e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended March 31, 2008
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission File Number: 001-33784

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)


Delaware		20-8084793
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1601 N.W. Expressway, Suite 1600, Oklahoma City, Oklahoma (Address of principal executive offices)		73118 (Zip Code)

Registrant’s telephone number, including area code:

(405) 753-5500

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

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

Indicate by check mark whether the registrant 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):


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

(Do not check if a smaller reporting company)

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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per shares, as of the close of business on April 30, 2008, was 146,194,356.

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Various statements contained in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements include projections and estimates concerning 2008 capital expenditures, the pending sale of assets in the Piceance Basin, the timing and success of specific projects such as our rig fleet expansion program, outcomes and effects of litigation, claims and disputes, and elements of our business strategy. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of our annual report on Form 10-K for the year ended December 31, 2007, the opportunities that may be presented to and pursued by us, competitive actions by other companies, changes in laws or regulations and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.

PART I. Financial Information


ITEM 1.	*Financial Statements*

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets


	March 31,			December 31,
	2008			2007
	(Unaudited)
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	726		$	63,135
Accounts receivable, net:
Trade		112,674			94,741
Related parties		23,037			20,018
Derivative contracts		—			21,958
Inventories		4,864			3,993
Deferred income taxes		1,428			1,820
Other current assets		20,373			20,787

Total current assets		163,102			226,452
Crude oil and natural gas properties, using full cost method of accounting
Proved		3,204,557			2,848,531
Unproved		259,610			259,610
Less: accumulated depreciation and depletion		(294,729	)		(230,974	)

		3,169,438			2,877,167

Other property, plant and equipment, net		506,156			460,243
Derivative contracts		2,145			270
Investments		8,815			7,956
Restricted deposits		32,633			31,660
Other assets		25,543			26,818

Total assets	$	3,907,832		$	3,630,566


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current maturities of long-term debt	$	15,662		$	15,350
Accounts payable and accrued expenses:
Trade		242,324			215,497
Related parties		1,747			395
Asset retirement obligation		882			864
Derivative contracts		123,284			—

Total current liabilities		383,899			232,106
Long-term debt		1,263,270			1,052,299
Other long-term obligations		16,817			16,817
Asset retirement obligation		60,748			57,716
Deferred income taxes		18,341			49,350

Total liabilities		1,743,075			1,408,288

Commitments and contingencies (Note 11)
Minority interest		4,875			4,672
Redeemable convertible preferred stock, $0.001 par value, 2,625 shares authorized; 1,844 and 2,184 shares issued and outstanding at March 31, 2008 and December 31, 2007, respectively		380,893			450,715
Stockholders’ equity:
Preferred stock, $0.001 par value; 47,375 shares authorized; no shares issued and outstanding in 2008 and 2007		—			—
Common stock, $0.001 par value, 400,000 shares authorized; 147,516 issued and 146,206 outstanding at March 31, 2008 and 141,847 issued and 140,391 outstanding at December 31, 2007		144			140
Additional paid-in capital		1,763,225			1,686,113
Treasury stock, at cost		(17,389	)		(18,578	)
Retained earnings		33,009			99,216

Total stockholders’ equity		1,778,989			1,766,891

Total liabilities and stockholders’ equity	$	3,907,832		$	3,630,566

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

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations


	Three Months Ended
	March 31,
	2008			2007
	(Unaudited)
	(In thousands except per share amounts)

Revenues:
Natural gas and crude oil	$	205,487		$	90,176
Drilling and services		12,334			27,895
Midstream and marketing		46,409			26,187
Other		4,856			4,806

Total revenues		269,086			149,064
Expenses:
Production		34,188			21,974
Production taxes		9,220			2,933
Drilling and services		7,169			18,777
Midstream and marketing		40,418			23,420
Depreciation, depletion and amortization — natural gas and crude oil		65,076			32,684
Depreciation, depletion and amortization — other		17,965			10,160
General and administrative		20,994			12,468
Loss on derivative contracts		136,844			23,181
Loss (gain) on sale of assets		23			(1	)

Total expenses		331,897			145,596

(Loss) income from operations		(62,811	)		3,468

Other income (expense):
Interest income		796			1,088
Interest expense		(25,172	)		(35,429	)
Minority interest		(835	)		(146	)
Income from equity investments		859			1,025

Total other (expense) income		(24,352	)		(33,462	)

Loss before income tax benefit		(87,163	)		(29,994	)
Income tax benefit		(30,538	)		(10,501	)

Net loss		(56,625	)		(19,493	)
Preferred stock dividends and accretion		9,582			8,966

Loss applicable to common stockholders	$	(66,207	)	$	(28,459	)

Basic and diluted loss per share applicable to common stockholders	$	(0.47	)	$	(0.31	)

Weighted average number of common shares outstanding:
Basic		141,044			92,442

Diluted		141,044			92,442

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

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Statement of Changes in Stockholders’ Equity


			Additional
	Common		Paid-In		Treasury			Retained
	Stock		Capital		Stock			Earnings			Total
	(Unaudited)
	(In thousands)

Three months ended March 31, 2008
Balance, December 31, 2007	$	140	$	1,686,113	$	(18,578	)	$	99,216		$	1,766,891
Purchase of treasury stock		—		—		(1,254	)		—			(1,254	)
Common stock issued under retirement plan		—		2,566		2,443			—			5,009
Conversion of redeemable convertible preferred stock to common stock		4		71,305		—			—			71,309
Accretion on redeemable convertible preferred stock		—		—		—			(1,487	)		(1,487	)
Stock-based compensation		—		3,241		—			—			3,241
Net loss		—		—		—			(56,625	)		(56,625	)
Redeemable convertible preferred stock dividend		—		—		—			(8,095	)		(8,095	)

Balance, March 31, 2008	$	144	$	1,763,225	$	(17,389	)	$	33,009		$	1,778,989

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., together with its subsidiaries (collectively, the “Company” or “SandRidge”), is a natural gas and crude oil company with its principal focus on exploration, development and production. SandRidge also owns and operates natural gas gathering, marketing and processing facilities and CO₂ treating and transportation facilities and conducts tertiary oil recovery operations. In addition, SandRidge owns and operates drilling rigs and a related oil field services business operating under the Lariat Services, Inc. brand name. SandRidge’s primary exploration, development and production areas are concentrated in West Texas. The Company also operates significant interests in the Cotton Valley Trend in East Texas, the Gulf Coast area, the Mid-Continent and the Gulf of Mexico.

On November 21, 2006, the Company acquired all of the outstanding membership interests of NEG Oil & Gas LLC (“NEG”).

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2007 have been derived from the audited financial statements contained in the Company’s annual report on Form 10-K for the fiscal year ended December 31, 2007 (the “2007 Form 10-K”). The unaudited interim condensed consolidated financial statements of SandRidge have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2007 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 financial statements should be read in conjunction with the financial statements and notes thereto included in the 2007 Form 10-K.


2.	Significant Accounting Policies

For a description of the Company’s accounting policies, refer to Note 1 of the consolidated financial statements included in the 2007 Form 10-K.

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

Recent Accounting Pronouncements. Effective January 1, 2008, SandRidge implemented Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements”. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not require new fair value measurements. SFAS No. 157 did not have an effect on the Company’s financial statements other than requiring additional disclosures regarding fair value measurements. See Note 4.

In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”). FSP 157-2 delays the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. The adoption of FSP 157-2 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations”, which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company has not yet evaluated the potential impact of this standard.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51”, which establishes 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. The Statement also establishes disclosure requirements to clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company has not yet evaluated the potential impact of this standard.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, which changes disclosure requirements for derivative instruments and hedging activities. The Statement requires enhanced disclosure, including qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company has not yet evaluated the potential impact of this standard.


3.	Property, Plant and Equipment

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


	March 31,			December 31,
	2008			2007

Crude oil and natural gas properties:
Proved	$	3,204,557		$	2,848,531
Unproved		259,610			259,610

Total crude oil and natural gas properties		3,464,167			3,108,141
Less accumulated depreciation and depletion		(294,729	)		(230,974	)

Net crude oil and natural gas properties capitalized costs		3,169,438			2,877,167

Land		1,344			1,149
Non crude oil and natural gas equipment		602,488			539,893
Buildings and structures		39,225			38,288

Total		643,057			579,330
Less accumulated depreciation, depletion and amortization		(136,901	)		(119,087	)

Net capitalized costs		506,156			460,243

Total property, plant and equipment	$	3,675,594		$	3,337,410

The amount of capitalized interest included in the above non crude oil and natural gas equipment balance at March 31, 2008 and December 31, 2007 was approximately $3.7 million and $3.4 million, respectively.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)


4.	Fair Value Measurements

The Company implemented SFAS No. 157 effective January 1, 2008 for its financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and liabilities that are being measured and reported on a fair value basis. In February 2008, the FASB issued FSP 157-2, which delayed the effective date of SFAS No. 157 by one year for certain nonfinancial assets and liabilities.

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


Level 1:		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

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

As required by SFAS No. 157, financial assets and liabilities 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, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Per SFAS No. 157, the Company has classified its derivative contracts into one of the three levels based upon the data relied upon to determine the fair value. The fair values of the Company’s natural gas and crude oil swaps, crude oil collars and interest rate swap are based upon quotes obtained from counterparties to the derivative contracts and are designated as Level 3 as the Company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2. The following table summarizes the valuation of the Company’s financial assets and liabilities by SFAS No. 157 pricing levels as of March 31, 2008:


	Fair Value Measurements Using:
	Quoted Prices in		Significant
	Active Markets for		Other		Significant
	Identical Assets		Observable		Unobservable			Assets/
	or Liabilities		Inputs		Inputs			Liabilities at
Description	(Level 1)		(Level 2)		(Level 3)			FairValue
			(In thousands)

Derivative assets	$	—	$	—	$	2,145		$	2,145
Derivative liabilities		—		—		(123,284	)		(123,284	)

	$	—	$	—	$	(121,139	)	$	(121,139	)

The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include not only the impact of the Company’s nonperformance risk on its liabilities, but also the credit standing of the counterparties.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

The table below sets forth a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the first quarter of 2008 (in thousands):


Derivative contracts as of December 31, 2007	$	22,228
Total gains or losses (realized/unrealized)		(136,038	)
Purchases, issuances and settlements		(7,329	)
Transfers in and out of Level 3		—

Derivative contracts as of March 31, 2008	$	(121,139	)

Change in unrealized gains (losses) on derivative contracts still held as of March 31, 2008	$	(143,367	)


5.	Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2007 to March 31, 2008 is as follows (in thousands):


Asset retirement obligation, December 31, 2007	$	58,580
Liability incurred upon acquiring and drilling wells		1,730
Revisions in estimated cash flows		—
Liability settled in current period		—
Accretion of discount expense		1,320

Asset retirement obligation, March 31, 2008		61,630
Less: Current portion		882

Asset retirement obligation, net of current	$	60,748


6.	Long-Term Debt

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


	March 31,		December 31,
	2008		2007

Senior term loans	$	1,000,000	$	1,000,000
Senior credit facility		215,000		—
Other notes payable:
Drilling rig fleet and related oil field services equipment		44,347		47,836
Mortgage		19,450		19,651
Other equipment and vehicles		135		162

Total debt		1,278,932		1,067,649
Less: Current maturities of long-term debt		15,662		15,350

Long-term debt	$	1,263,270	$	1,052,299

Senior Term Loans. On March 22, 2007, the Company issued $1.0 billion of senior unsecured term loans (the “senior term loans”). The closing of the senior term loans was generally contingent upon closing the private placement of common equity as described in Note 13. The senior term loans include both floating rate term loans and fixed rate term loans. A portion of the proceeds from the senior term loans was used to repay the Company’s $850.0 million senior bridge facility, which was paid in full in March 2007.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

The Company issued $350.0 million at a variable rate with interest payable quarterly and principal due on April 1, 2014 (the “variable rate term loans”). The variable rate term loans bear interest, at the Company’s option, at the LIBOR rate plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%. After April 1, 2009, the variable rate term loans may be prepaid in whole or in part with certain prepayment penalties. The average interest rate paid on amounts outstanding under the Company’s variable term loans for the three month period ended March 31, 2008 was 8.36%.

In January 2008, the Company entered into an interest rate swap to fix the variable LIBOR interest rate on the variable rate term loans at 6.26% for the period from April 1, 2008 to April 1, 2011. This swap has not been designated as a hedge.

The Company issued $650.0 million at a fixed rate of 8.625% with the principal due on April 1, 2015 (the “fixed rate term loans”). Under the terms of the fixed rate term loans, interest is payable quarterly and during the first four years interest may be paid, at the Company’s option, either entirely in cash or entirely with additional fixed rate term loans. If the Company elects to pay the interest due during any period in additional fixed rate term loans, the interest rate increases to 9.375% during such period. After April 1, 2011, the fixed rate term loans may be prepaid in whole or in part with certain prepayment penalties.

The Company incurred $26.1 million of debt issuance costs in connection with the senior term loans. These costs are included in other assets and amortized over the term of the senior term loans.

On March 28, 2008, the Company commenced an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. See Note 15.

Senior Credit Facility. On November 21, 2006, the Company entered into a $750.0 million senior secured revolving credit facility (the “senior credit facility”). The senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid without restriction so long as the Company is in compliance with its terms, including certain financial covenants. The initial proceeds of the senior credit facility were used to (i) partially finance the acquisition of NEG, (ii) refinance the existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and the existing credit facility.

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

The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), (ii) ratio of EBITDAX to interest expense plus current maturities of long-term debt, and (iii) current ratio. The Company was in compliance with all of the covenants under the senior credit facility as of March 31, 2008.

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

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

At the Company’s election, interest under the senior credit facility is determined by reference to (i) the LIBOR rate plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three month period. The average interest rate paid on amounts outstanding under our senior credit facility for the three month period ended March 31, 2008 was 4.57%.

The borrowing base of proved reserves was initially set at $300.0 million. The borrowing base was increased to $400.0 million on May 2, 2007, to $700.0 million on September 14, 2007 and to $1.2 billion on April 4, 2008. Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed loan amount, which was increased to $1.75 billion on April 4, 2008. At March 31, 2008, the Company had $215.0 million in outstanding indebtedness under this facility.

Senior Bridge Facility. On November 21, 2006, the Company entered into an $850.0 million senior unsecured bridge facility (the “senior bridge facility”). Together with borrowings under the senior credit facility, the proceeds from the senior bridge facility were used to (i) partially finance the NEG acquisition, (ii) refinance the existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and the existing credit facility. The senior bridge facility was repaid in March 2007. The Company expensed remaining unamortized debt issuance costs related to the senior bridge facility of approximately $12.5 million to interest expense in March 2007.

Other Indebtedness. The Company has financed a portion of its drilling rig fleet and related oil field services equipment through notes. At March 31, 2008, the aggregate outstanding balance of these notes was $44.3 million, with an annual fixed interest rate ranging from 7.64% to 8.87%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments for principal and interest in the amount of $1.2 million and are secured by the equipment. The notes have a prepayment penalty (currently ranging from 1 to 3%) that is triggered if the Company repays the notes prior to maturity.

On November 15, 2007, the Company entered into a note payable in the amount of $20.0 million with a lending institution as a mortgage on the downtown Oklahoma City property purchased by the Company in July 2007 to serve as its corporate headquarters. This note is fully secured by one of the buildings and a parking garage located on the downtown property, 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 2008, the Company expects to make payments of principal and interest on this note totaling $0.8 million and $1.2 million, respectively.

Prior to 2007, the Company financed the purchase of various vehicles, oil field services equipment and other equipment through various notes payable. The aggregate outstanding balance of these notes as of December 31, 2006 was $4.5 million. Additionally, the Company financed its insurance premium payment made in 2007. These notes were substantially repaid during 2007 with borrowings under the Company’s senior credit facility. Also, in 2007 the Company repaid a $4.0 million loan incurred in 2005 for the purpose of completing a gas processing plant and pipeline in Colorado.

For the three months ended March 31, 2008 and 2007, interest payments, net of amounts capitalized, were approximately $25.4 million and $28.5 million, respectively.


7.	Other Long-Term Obligations

The Company has recorded a long-term obligation for amounts to be paid under a settlement agreement with Conoco, Inc. entered into in January 2007. The Company agreed to pay approximately $25.0 million plus interest, payable in $5.0 million increments on April 1, 2007, July 1, 2008, July 1, 2009, July 1, 2010, and July 1, 2011. On March 30, 2007, the Company made the first $5.0 million settlement payment plus accrued interest. The $5.0 million

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

payment to be made on July 1, 2008 has been included in accounts payable-trade in the accompanying condensed consolidated balance sheets as of March 31, 2008 and December 31, 2007. The unpaid settlement amount of approximately $15.0 million has been included in other long-term obligations in the accompanying condensed consolidated balance sheets as of March 31, 2008 and December 31, 2007.


8.	Derivative Contracts

The Company has entered into various derivative contracts including collars, fixed price swaps, basis swaps and interest rate swaps with counterparties. The contracts expire on various dates through December 31, 2011.

At March 31, 2008, the Company’s open commodity derivative contracts consisted of the following:

Natural Gas


	Notional		Weighted Avg.
Period and Type of Contract	(in MMBtus)		Fixed Price

April 2008 — June 2008
Price swap contracts		17,900	$	7.69
Basis swap contracts		13,350	$	(0.59	)
July 2008 — September 2008
Price swap contracts		18,100	$	8.23
Basis swap contracts		15,640	$	(0.57	)
October 2008 — December 2008
Price swap contracts		17,480	$	8.67
Basis swap contracts		14,720	$	(0.65	)
January 2009 — March 2009
Price swap contracts		6,300	$	9.12
Basis swap contracts		2,700	$	(0.49	)
April 2009 — June 2009
Price swap contracts		910	$	8.10
Basis swap contracts		2,730	$	(0.49	)
July 2009 — September 2009
Basis swap contracts		2,760	$	(0.49	)
October 2009 — December 2009
Basis swap contracts		2,760	$	(0.49	)
January 2011 — March 2011
Basis swap contracts		1,350	$	(0.47	)
April 2011 — June 2011
Basis swap contracts		1,365	$	(0.47	)
July 2011 — September 2011
Basis swap contracts		1,380	$	(0.47	)
October 2011 — December 2011
Basis swap contracts		1,380	$	(0.47	)

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Crude Oil


	Notional		Weighted Avg.
Period and Type of Contract	(in MBbls)		Fixed Price

April 2008 — June 2008
Price swap contracts		270	$	95.04
Collar contracts		21	$	50.00 — 83.35
July 2008 — September 2008
Price swap contracts		225	$	94.33
Collar contracts		27	$	50.00 — 82.60
October 2008 — December 2008
Price swap contracts		225	$	93.17
Collar contracts		27	$	50.00 — 82.60

In January 2008, the Company entered into an interest rate swap to fix the variable LIBOR interest rate on its variable rate term loans at 6.26% for the period April 1, 2008 to April 1, 2011.

These derivatives have not been designated as hedges. The Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. Cash settlements and valuation gains and losses for commodity derivative contracts are included in loss on derivative contracts in the condensed consolidated statements of operations. The following table summarizes the cash settlements and valuation gains and losses on commodity derivative contracts for the three month periods ended March 31, 2008 and 2007 (in thousands):


	Three Months Ended
	March 31,
	2008			2007

Realized (gain) loss	$	(7,329	)	$	1,519
Unrealized loss		144,173			21,662

Loss on derivative contracts	$	136,844		$	23,181

An unrealized gain of $0.8 million related to the interest rate swap is included in interest expense in the condensed consolidated statement of operations for the three month period ended March 31, 2008.


9.	Income Taxes

In accordance with applicable generally accepted accounting principles, 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.

For the three months ended March 31, 2008 and 2007, income tax payments were approximately $0.2 million and $0.4 million, respectively.


10.	Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock. The following table summarizes the

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the three month periods ended March 31, 2008 and 2007 (in thousands):


	Three Months Ended
	March 31,
	2008		2007

Weighted average basic common shares outstanding		141,044		92,442
Effect of dilutive securities:
Restricted stock		—		—

Weighted average diluted common and potential common shares outstanding		141,044		92,442

For the three month periods ended March 31, 2008 and 2007, restricted stock awards covering 2.2 million shares and 1.3 million shares, respectively, were excluded from the computation of net loss per share because their effect would have been antidilutive.

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding redeemable convertible preferred stock. Under this method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available to common stockholders. The Company determined the if-converted method is not more dilutive and has included preferred stock dividends in the determination of loss applicable to common stockholders.


11.	Commitments and Contingencies

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


12.	Redeemable Convertible Preferred Stock

In November 2006, the Company sold 2,136,667 shares of redeemable convertible preferred stock in order to finance a portion of the NEG acquisition and received net proceeds from this sale of approximately $439.5 million after deducting offering expenses of approximately $9.3 million. Each holder of the redeemable convertible preferred stock is entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value of its redeemable convertible preferred stock. The accreted value was $210 per share as of March 31, 2008 and December 31, 2007. Each share of convertible preferred stock was initially convertible into ten (10.2 currently) shares of common stock at the option of the holder, subject to certain anti-dilution adjustments. A summary of dividends declared and paid on the redeemable convertible preferred stock is as follows (in thousands except per share data):

Dividends

Declared

Dividend Period

per Share

Total

Payment Date

January 31, 2007

November 21, 2006 — February 1, 2007

3.21

6,859

February 15, 2007

May 8, 2007

February 2, 2007 — May 1, 2007

3.97

8,550

May 15, 2007

June 8, 2007

May 2, 2007 — August 1, 2007

4.10

8,956

August 15, 2007

September 24, 2007

August 2, 2007 — November 1, 2007

4.10

8,956

November 15, 2007

December 16, 2007

November 2, 2007 — February 1, 2008

4.10

8,956

February 15, 2008

March 7, 2008

February 2, 2008 — May 1, 2008

4.01

8,095

(1)

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)


(1)		Includes $0.6 million of prorated dividends paid to holders of redeemable convertible preferred shares who converted to shares of common stock in March 2008. The remaining dividends of $7.5 million were paid subsequent to March 31, 2008.

Approximately $8.1 million and $8.6 million in paid and unpaid dividends have been included in the Company’s earnings per share calculations for the three month periods ended March 31, 2008 and 2007, respectively, as presented in the accompanying condensed consolidated statements of operations.

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. The conversion resulted in an increase to additional paid in capital of $71.3 million, which represents the difference between the par value of the common stock issued and the carrying value of the redeemable convertible preferred shares converted. Additionally, the Company recorded a one-time charge to retained earnings for $1.1 million in accelerated accretion expense related to the converted redeemable convertible preferred shares.

Beginning in the second quarter of 2008, the Company may convert all outstanding shares of redeemable convertible preferred stock at the then conversion rate if certain conditions have been met. See Note 15.


13.	Stockholders’ Equity

The following table presents information regarding SandRidge’s common stock (in thousands):


	March 31,		December 31,
	2008		2007

Shares authorized		400,000		400,000
Shares outstanding at end of period		146,206		140,391
Shares held in treasury		1,310		1,456

The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 2,625,000 shares are designated as redeemable convertible preferred. As of March 31, 2008 and December 31, 2007, there were 1,844,464 and 2,184,286 shares, respectively, of redeemable convertible preferred stock outstanding. (See Note 12.) There were no undesignated preferred shares outstanding as of March 31, 2008 and December 31, 2007.

Common Stock Issuance. In March 2007, the Company sold approximately 17.8 million shares of common stock for net proceeds of $318.7 million after deducting offering expenses of approximately $1.4 million. The stock was sold in private sales to various investors including Tom L. Ward, the Company’s Chairman and Chief Executive Officer, who invested $61.4 million in exchange for approximately 3.4 million shares of common stock.

On November 9, 2007, the Company completed the initial public offering of its common stock. The Company sold 32,379,500 shares of its common stock, including 4,710,000 shares sold directly to an entity controlled by Tom L. Ward, at a price of $26 per share. After deducting underwriting discounts of approximately $44.0 million and

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

offering expenses of approximately $3.1 million, the Company received net proceeds of approximately $794.7 million. The Company used the net proceeds from the offering as follows (in millions):


Repayment of outstanding balance and accrued interest on senior credit facility	$	515.9
Repayment of note payable and accrued interest incurred in connection with recent acquisition		49.1
Excess cash to fund future capital expenditures		229.7

Total	$	794.7

During March 2008, the Company issued 3,465,593 shares of common stock upon the conversion of 339,823 shares of its redeemable convertible preferred stock (see additional discussion at Note 12).

Treasury Stock. The Company makes required tax payments on behalf of employees as 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 38,000 and 37,000 shares at a total value of $1.3 million and $0.7 million during the three month periods ended March 31, 2008 and 2007, respectively. These shares were accounted for as treasury stock.

During the first quarter 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. Historical cost of the shares transferred totaled approximately $2.4 million, resulting in an increase to the Company’s additional paid-in capital of approximately $2.6 million.

Restricted Stock. The Company issues restricted stock awards under incentive compensation plans which vest over specified periods of time. 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 and certain conditions to vesting.

For the three months ended March 31, 2008 and 2007, the Company recognized stock-based compensation expense related to restricted stock of $3.2 million and $1.1 million, respectively. Stock-based compensation expense is reflected in general and administrative expense in the condensed consolidated statements of operations.


14.	Related Party Transactions

In the ordinary course of business, the Company engages in transactions with certain shareholders and other related parties. These transactions primarily consist of purchases of drilling equipment and sales of oil field service supplies. Following is a summary of significant transactions with such related parties for the three month periods ended March 31, 2008 and 2007 (in thousands):


	Three Months Ended
	March 31,
	2008		2007

Sales to and reimbursements from related parties	$	25,356	$	2,319

Purchases of services from related parties	$	19,890	$	6,785

The Company leases office space in Oklahoma City from a member of its Board of Directors. The Company believes that the payments made under this lease are at fair market rates. Rent expense related to the lease totaled $0.4 million and $0.3 million for the three month periods ended March 31, 2008 and 2007, respectively. The lease expires in August 2009.

Larclay, L.P. The Company and Clayton Williams Energy, Inc. (“CWEI”) each own a 50% interest in Larclay, L.P., a limited partnership formed in 2006 to acquire drilling rigs and provide land drilling services. Larclay

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

currently owns 12 rigs, one of which has not yet been assembled. The Company serves as the operations manager of the partnership. Under the partnership agreement, CWEI was responsible for rig financing and purchasing. The Company had sales to and cost reimbursements from Larclay for the three months ended March 31, 2008 and 2007 of $10.9 million and $2.3 million, respectively. As of March 31, 2008 and December 31, 2007, the Company had accounts receivable — related party due from Larclay of $18.3 million and $16.6 million, respectively. Additionally, the Company contracted with Larclay to utilize rigs for drilling. For the three month periods ended March 31, 2008 and 2007, the Company was billed $10.7 million and $6.8 million, respectively, for these services. As of March 31, 2008 and December 31, 2007, the Company had accounts payable — related party due to Larclay of $1.5 million and $0.3 million, respectively.


15.	Subsequent Events

Increase in Borrowing Base. In April 2008, the Company’s borrowing base under its senior credit facility was increased to $1.2 billion from $700.0 million and the total available under the facility was increased to $1.75 billion from $750.0 million.

Exchange of Senior Term Loans. On May 1, 2008, the Company issued $650.0 million of its Senior Notes due 2015 in exchange for an equal outstanding principal amount of its fixed rate term loans and $350.0 million of its Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of its variable rate term loans. The exchange was made pursuant to a non-public exchange offer that commenced on March 28, 2008 and expired on April 28, 2008. The newly issued senior notes have terms that are substantially identical to those of the exchanged senior term loans, except that the senior notes have been issued with registration rights.

Conversion of Redeemable Convertible Preferred Stock. In 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. This conversion resulted in a one-time charge to retained earnings of $6.1 million in accelerated accretion expense related to the remaining offering costs of the 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.

Sale of Assets. In May 2008, the Company entered into an agreement, along with other parties, to sell substantially all of its assets located in the Piceance Basin of Colorado to a subsidiary of The Williams Companies, Inc. The total purchase price is $285 million with net proceeds to the Company estimated to be approximately $140 million, subject to closing adjustments and allocation of the sales price among multiple sellers. Assets to be sold include undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells. The sale is subject to customary closing conditions and is expected to close during the second quarter of 2008.


16.	Industry Segment Information

SandRidge has four business segments: exploration and production, drilling and oil field services, midstream gas services, and other. These segments represent the Company’s four main business units, each offering different products and services. The exploration and production segment is engaged in the development, acquisition and production of crude oil and natural gas properties. The drilling and oil field services segment is engaged in the land contract drilling of crude oil and natural gas wells. The midstream gas services segment is engaged in the purchasing, gathering, processing and treating of natural gas. The other segment includes transporting CO₂ to market for use by the Company and others in tertiary oil recovery operations and other miscellaneous operations.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

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


	Three Months Ended
	March 31,
	2008			2007

Revenues:
Exploration and production	$	206,966		$	92,634
Elimination of inter-segment revenue		(44	)		(1,808	)

Exploration and production, net of inter-segment revenue		206,922			90,826

Drilling and oil field services		79,838			56,915
Elimination of inter-segment revenue		(67,516	)		(29,020	)

Drilling and oil field services, net of inter-segment revenue		12,322			27,895

Midstream gas services		148,235			61,422
Elimination of inter-segment revenue		(103,148	)		(35,235	)

Midstream gas services, net of inter-segment revenue		45,087			26,187

Other		5,854			5,753
Elimination of inter-segment revenue		(1,099	)		(1,597	)

Other, net of inter-segment revenue		4,755			4,156

Total revenues	$	269,086		$	149,064

Operating (Loss) Income:
Exploration and production	$	(47,389	)	$	371
Drilling and oil field services		(2,148	)		5,202
Midstream gas services		32			1,350
Other		(13,306	)		(3,455	)

Total operating (loss) income		(62,811	)		3,468
Interest income		796			1,088
Interest expense		(25,172	)		(35,429	)
Other income		24			879

Loss before income tax benefit	$	(87,163	)	$	(29,994	)

Capital Expenditures:
Exploration and production	$	354,765		$	127,582
Drilling and oil field services		17,921			41,242
Midstream gas services		38,721			9,543
Other		7,243			2,728

Total capital expenditures	$	418,650		$	181,095


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

Introduction

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the accompanying notes included in this report, as well as our audited consolidated financial statements and the accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2007 (the “2007 Form 10-K”). The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and crude oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this report and in our 2007 Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

The financial information with respect to the three month periods ended March 31, 2008 and March 31, 2007 that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring accruals, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Overview of Our Company

We are a rapidly expanding independent natural gas and crude oil company concentrating on exploration, development and production activities. We are focused on continuing the exploration and exploitation of our significant holdings in the West Texas Overthrust, which we refer to as the WTO, a natural gas prone geological region where we have operated since 1986. The WTO includes the Piñon Field as well as the Allison Ranch, South Sabino, Thistle, Big Canyon, and McKay Creek exploration areas. We also own and operate drilling rigs and conduct related oil field services, and we own and operate interests in gas gathering, marketing and processing facilities and CO₂ gathering and transportation facilities.

On November 21, 2006, we acquired all of the outstanding membership interests in NEG Oil & Gas LLC (“NEG”) for total consideration of approximately $1.5 billion, excluding cash acquired. With core assets in the Val Verde and Permian Basins of West Texas, including overlapping or contiguous interests in the WTO, the NEG acquisition has dramatically increased our exploration and production segment operations. In addition to the NEG acquisition, we have completed numerous acquisitions of additional working interests in the WTO during the period from late 2005 through March 31, 2008. We also operate significant interests in the Cotton Valley Trend in East Texas, the Gulf Coast area, the Mid-Continent and the Gulf of Mexico.

During November 2007, we completed the initial public offering of our common stock. We used the proceeds from this offering to repay indebtedness outstanding under our senior credit facility as well as a note payable related to a 2007 acquisition and to fund the remainder of our 2007 capital expenditure program and a portion of our 2008 capital expenditure program. See further discussion of these transactions in Note 13 to the condensed consolidated financial statements contained in Part I, Item 1 of this report.

Segment Overview

We operate in four related business segments: exploration and production, drilling and oil field services, midstream gas services and other. Management evaluates the performance of our business segments based on operating income, which is defined as segment operating revenue less operating expenses and depreciation, depletion and amortization. These measurements provide important information to us about the activity and profitability of our lines of business. Set forth in the table below is financial information regarding each of our business segments.


	Three Months Ended
	March 31,
	2008			2007
Segment income and expense (in thousands):
Revenue:
Exploration and production	$	206,922		$	90,826
Drilling and oil field services		12,322			27,895
Midstream gas services		45,087			26,187
Other		4,755			4,156

Total revenues		269,086			149,064
Operating (loss) income:
Exploration and production		(47,389	)		371
Drilling and oil field services		(2,148	)		5,202
Midstream gas services		32			1,350
Other		(13,306	)		(3,455	)

Total operating (loss) income		(62,811	)		3,468
Interest income		796			1,088
Interest expense		(25,172	)		(35,429	)
Other income		24			879

Loss before income taxes	$	(87,163	)	$	(29,994	)

Production data:
Natural gas (Mmcf)		19,173			10,449
Crude oil (MBbls)		611			393
Combined equivalent volumes (Mmcfe)		22,839			12,807
Average daily combined equivalent volumes (Mmcfe/d)		251.0			142.3
Average prices — as reported(1):
Natural gas (per Mcf)	$	7.86		$	6.60
Crude oil (per Bbl)(3)	$	89.81		$	54.06
Combined equivalent (per Mcfe)	$	9.00		$	7.04
Average prices — including impact of derivative contract settlements:
Natural gas (per Mcf)	$	8.32		$	6.45
Crude oil (per Bbl)(3)	$	87.42		$	54.06
Combined equivalent (per Mcfe)	$	9.32		$	6.92
Drilling and oil field services:
Number of operational drilling rigs owned at end of period		26.0			25.0
Average number of operational drilling rigs owned during the period		26.0			25.0
Average total revenue per rig per day(2)	$	17,500		$	16,600


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

(2)		Does not include revenues for related rental equipment.

(3)		Includes natural gas liquids.

Exploration and Production Segment

We explore for, develop and produce natural gas and crude oil reserves, with a focus on our proved reserves and extensive undeveloped acreage positions in the WTO. We operate substantially all of our wells in our core areas and employ our drilling rigs and other drilling services in the exploration and development of our operated wells and, to a lesser extent, on our non-operated wells.

The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our natural gas and crude oil production, the quantity of our natural gas and crude oil production and changes in the fair value of derivative contracts we use to reduce the volatility of the prices we receive for our natural gas and crude oil production. Because we are vertically integrated, our exploration and production activities affect the results of our drilling and oil field services and midstream gas services segments. The NEG acquisition in 2006 substantially increased our revenues and operating income in our exploration and production segment. However, because our working interest in the Piñon Field increased to approximately 93%, there are greater intercompany eliminations that affect the consolidated financial results of our drilling and oil field services and midstream gas services segments.

Exploration and production segment revenues increased to $206.9 million in the three months ended March 31, 2008 from $90.8 million in the three months ended March 31, 2007, an increase of 127.8%, as a result of a 78.1% increase in combined production volumes and a 27.8% increase in the combined average price we received for the natural gas and crude oil we produced. In the three month period ended March 31, 2008 we increased natural gas production by 8.8 Bcf to 19.2 Bcf and increased crude oil production by 218 MBbls to 611 MBbls from the comparable period in 2007. The total combined 10.0 Bcfe increase in production was due primarily to an increase in our average working interest in the WTO from 81% at March 31, 2007 to 93% at March 31, 2008 and successful drilling in the WTO throughout 2007 and the first quarter of 2008. The Company had 1,869 producing wells at March 31, 2008 as compared to 1,333 producing wells at March 31, 2007.

The average price we received for our natural gas production for the three month period ended March 31, 2008 increased 19.1%, or $1.26 per Mcf, to $7.86 per Mcf from $6.60 per Mcf in the comparable period in 2007. The average price received for our crude oil production increased 66.1%, or $35.75 per barrel, to $89.81 per barrel during the three months ended March 31, 2008 from $54.06 per barrel during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for natural gas for the three month period ended March 31, 2008 was $8.32 per Mcf as compared to $6.45 per Mcf during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for crude oil for the three month period ended March 31, 2008 was $87.42. Our derivative contracts had no impact on effective oil prices during the three months ended March 31, 2007. During 2007 and continuing into 2008, we entered into derivatives contracts to mitigate the impact of commodity price fluctuations on our 2007, 2008 and 2009 production. Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded as an 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.”

For the three months ended March 31, 2008, we had a $47.4 million operating loss in our exploration and production segment, compared to $0.4 million in operating income for the same period in 2007. Our $116.1 million increase in exploration and production revenues was offset by a $12.2 million increase in production expenses, a $32.4 million increase in depreciation, depletion and amortization, or DD&A, due to the increase in production and a $136.8 million loss on our derivative contracts. The increase in production expenses was attributable to the increase in number of operating wells we own and an increase in our average working interest in those wells. During the three month period ended March 31, 2008, the exploration and production segment reported a $136.8 million net loss on our commodity derivative positions ($7.3 million realized gain and $144.1 million unrealized loss) compared to a $23.2 million loss ($1.5 million realized loss and $21.7 million unrealized loss) in the comparable period in 2007. During 2007 and first quarter 2008, we selectively entered into natural gas and oil swaps and natural gas basis swaps in order to mitigate the effects of fluctuations in prices received for our production. Given the long term nature of our investment in the WTO development program and the relatively high level of natural gas prices compared to our budgeted prices, management believes it prudent to enter into natural gas and crude oil swaps and natural gas basis swaps for a portion of our production. Unrealized gains or losses on derivative contracts represent

the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. The unrealized loss on natural gas and crude oil derivative contracts recorded in the three month period ended March 31, 2008 was attributable to an increase in average natural gas and crude oil prices at March 31, 2008 as compared to the average natural gas and crude oil prices at December 31, 2007 or the contract price for contracts entered into during the period. Future volatility in natural gas and crude oil prices could have an adverse effect on the operating results of our exploration and production segment.

Drilling and Oil Field Services Segment

We drill for our own account primarily in the WTO through our drilling and oil field services subsidiary, Lariat Services, Inc. We also drill wells for other natural gas and crude oil companies, primarily located in the West Texas region. As of March 31, 2008, our drilling rig fleet consisted of 37 operational rigs, 26 we owned directly and 11 owned by Larclay, L.P., a limited partnership in which we have a 50% interest. We also own one rig that is currently being retrofitted. Our oil field services business conducts operations that complement our drilling services operations. These services include providing pulling units, trucking, rental tools, location and road construction and roustabout services to ourselves and to third parties. Additionally, we provide under-balanced drilling systems only for our own account.

In 2006, we and CWEI formed Larclay, L.P., which acquired twelve sets of rig components and other related equipment to assemble into completed land drilling rigs. The drilling rigs were to be used for drilling on CWEI’s prospects, our prospects or for contracting to third parties on daywork drilling contracts. All of these rigs have been delivered, although one rig has not been assembled. CWEI was responsible for securing financing and the purchase of the rigs. The partnership financed 100% of the acquisition cost of the rigs utilizing a guarantee by CWEI. We operate the rigs owned by the partnership. The partnership and CWEI are responsible for all costs related to the initial construction and equipping of the drilling rigs. In the event of an operating shortfall within the partnership, we, along with CWEI, are responsible to fund the shortfall through loans to the partnership. We account for Larclay as an equity investment.

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. We provide drilling services for our own account and for others, generally on a daywork, and less often on a turnkey, contract basis. We generally assess the complexity and risk of operations, the on-site drilling conditions, the type of equipment to be used, the anticipated duration of the work to be performed and the prevailing market rates in determining the contract terms we offer.

Daywork Contracts. Under a daywork drilling contract, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs, and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs. As of March 31, 2008, 26 of our rigs were operating under daywork contracts and 24 of these were working for our account. As of March 31, 2008, the 11 operational rigs owned by Larclay were operating under daywork contracts and six of these were working for our account. Four of the remaining operational Larclay rigs were working for CWEI as of March 31, 2008.

Turnkey Contracts. Under a typical turnkey contract, a customer will pay us to drill a well to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide most of the equipment and drilling supplies required to drill the well. We subcontract for related services such as the provision of casing crews, cementing and well logging. Generally, we do not receive progress payments and are paid only after the well is drilled. We enter into turnkey contracts in areas where our experience and expertise permit us to drill wells more profitably than under a daywork contract. As of March 31, 2008, none of our rigs were operating under a turnkey contract.

Drilling and oil field services segment revenue decreased to $12.3 million in the three month period ended March 31, 2008 from $27.9 million in the three month period ended March 31, 2007. This resulted in an operating loss of $2.1 million in the three month period ended March 31, 2008 compared to operating income of $5.2 million

in the same period in 2007. The decline in revenues and operating income is primarily attributable to an increase in the number of our rigs operating on our properties and an increase in our ownership interest in our natural gas and crude oil properties. Our drilling and oil field services segment records revenues and operating income only on wells drilled for or on behalf of third parties. The portion of drilling costs incurred by our drilling and oil field services segment relating to our ownership interest are capitalized as part of our full-cost pool. With the various WTO property acquisitions that occurred throughout 2007 and the first quarter of 2008, our average working interest has increased to approximately 93% (from 81% at March 31, 2007) in the wells we operate in the WTO, and the third-party interest has declined to less than 10%. Additionally, 24 of the 26 operational rigs we owned were working for our account at March 31, 2008, as compared to 14 of our 23 operational rigs working for our account at March 31, 2007. As a result, during the three month period ended March 31, 2008, approximately 84.6%, or $67.5 million, of our drilling and oil field service revenues were generated by work performed on our own account and eliminated in consolidation as compared to approximately 51.0%, or $29.0 million, for the comparable period in 2007. The average daily rate we received per rig of approximately $17,500, excluding revenues for related rental equipment and before intercompany eliminations, was slightly higher than the daily rate of $16,600 from the comparable period in 2007.

Midstream Gas Services Segment

We provide gathering, compression, processing and treating services of natural gas in West Texas and the Piceance Basin in northwestern Colorado, primarily through our wholly owned subsidiary, SandRidge Midstream, Inc. (formerly known as ROC Gas Company, Inc.). Through our gas marketing subsidiary, Integra Energy LLC, we buy and sell natural gas produced from our operated wells as well as third-party operated wells. Gas marketing revenue is one of our largest revenue components; however, it is a very low margin business. On a consolidated basis, natural gas purchases and other costs of sales include the total value we receive from third parties for the natural gas we sell and the amount we pay for natural gas, which are reported as midstream and marketing expense. The primary factors affecting our midstream gas services are the quantity of natural gas we gather, treat and market and the prices we pay and receive for natural gas.

Midstream gas services revenue for the three months ended March 31, 2008 was $45.1 million compared to $26.2 million in the comparable period of 2007. The quarterly increase in midstream gas services revenues is attributable to larger third-party volumes transported and marketed through our gathering systems during the three months ended March 31, 2008 as compared to the same period in 2007. We generally charge a flat fee per unit transported and charge a percentage of sales for marketed volumes.

Other Segment

Our other segment consists primarily of our CO₂ gathering and sales operations, corporate operations and other investments. We conduct our CO₂ gathering and sales operations through our wholly owned subsidiary, SandRidge CO₂, LLC (formerly operated through PetroSource Energy Company, LLC). SandRidge CO₂ gathers CO₂ from natural gas treatment plants located in West Texas and transports and sells this CO₂ for use in our and third parties’ tertiary oil recovery operations. The operating loss in the other segment was $13.3 million for the three months ended March 31, 2008 as compared to a loss of $3.5 million during the same period in 2007. The increase is primarily attributable to significant increases in corporate and support staff throughout 2007 and the first quarter of 2008.

Results of Operations

Three months ended March 31, 2008 compared to the three months ended March 31, 2007

Revenue. Total revenue increased 80.5% to $269.1 million for the three months ended March 31, 2008 from $149.1 million in the same period in 2007. This increase was due to a $115.3 million increase in natural gas and crude oil sales. Lower drilling and oil field services revenues partially offset the increases noted in midstream gas services and other segments.


	Three Months Ended
	March 31,
	2008		2007		$ Change			% Change
	(In thousands)

Revenue:
Natural gas and crude oil	$	205,487	$	90,176	$	115,311			127.9%
Drilling and services		12,334		27,895		(15,561	)		(55.8)%
Midstream and marketing		46,409		26,187		20,222			77.2%
Other		4,856		4,806		50			1.0%

Total revenues	$	269,086	$	149,064	$	120,022			80.5%

Total natural gas and crude oil revenues increased $115.3 million to $205.5 million for the three months ended March 31, 2008 compared to $90.2 million for the same period in 2007, primarily as a result of an increase in natural gas and crude oil production volumes and prices received for our production. Total natural gas production increased 83.5% to 19,173 Mmcf in 2008 compared to 10,449 Mmcf in 2007, while crude oil production increased 55.5% to 611 MBbls in 2008 from 393 MBbls in 2007. The increase was due to our successful drilling in the WTO and an increased working interest in 2008 in the WTO as compared to the same period in 2007. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production increased 27.8% in the 2008 period to $9.00 per Mcfe compared to $7.04 per Mcfe in 2007.

Drilling and services revenue decreased 55.8% to $12.3 million for the three months ended March 31, 2008 compared to $27.9 million in the same period in 2007. The decline in revenues is due to an increase in the number of company-owned rigs operating on company-owned natural gas and crude oil properties and the increase in working interest in these properties. Additionally, the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, increased to approximately $17,500 per day during the first three months of 2008 as compared to an average rate of $16,600 per day during the same period in 2007.

Midstream and marketing revenue increased $20.2 million, or 77.2%, with revenues of $46.4 million in the three month period ended March 31, 2008 as compared to $26.2 million in the three month period ended March 31, 2007. This increase is due primarily to larger production volumes transported and marketed, during the three months ended March 31, 2008 as compared to the same period in 2007, for the third parties with ownership in our wells or ownership in other wells connected to our gathering systems.

Other revenue increased to $4.9 million for the three months ended March 31, 2008 from $4.8 million for the same period in 2007. Other revenue is generated primarily by our CO₂ gathering and sales operations.

Operating Costs and Expenses. Total operating costs and expenses increased to $331.9 million for the three months ended March 31, 2008 compared to $145.6 million for the same period in 2007 due to increases in production-related costs, general and administrative expenses as a result of an increase in corporate staff, depreciation, depletion and amortization and losses on derivative contracts. These increases were partially offset by a decrease in expenses attributable to our drilling and services.


	Three Months Ended
	March 31,
	2008		2007			$ Change			% Change
	(In thousands)

Operating costs and expenses:
Production	$	34,188	$	21,974		$	12,214			55.6%
Production taxes		9,220		2,933			6,287			214.4%
Drilling and services		7,169		18,777			(11,608	)		(61.8)%
Midstream and marketing		40,418		23,420			16,998			72.6%
Depreciation, depletion, and amortization — natural gas and crude oil		65,076		32,684			32,392			99.1%
Depreciation, depletion and amortization — other		17,965		10,160			7,805			76.8%
General and administrative		20,994		12,468			8,526			68.4%
Loss on derivative contracts		136,844		23,181			113,663			490.3%
Loss (gain) on sale of assets		23		(1	)		24			2,400.0%

Total operating costs and expenses	$	331,897	$	145,596		$	186,301			128.0%

Production expense includes the costs associated with our production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $12.2 million primarily due to an increase in the number of wells in which we have a working interest. We owned working interests in 1,869 producing wells at March 31, 2008 compared to 1,333 producing wells at March 31, 2007. Production taxes increased $6.3 million, or 214.4%, to $9.2 million primarily due to the increase in production and the increased prices received for production during the three months ended March 31, 2008.

Drilling and services expenses decreased 61.8% for the three months ended March 31, 2008 as compared to the same period in 2007 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.

Midstream and marketing expenses increased $17.0 million or 72.6% to $40.4 million due to larger production volumes transported and marketed during the three months ended March 31, 2008 on behalf of third parties than during the comparable period in 2007.

Depreciation, depletion and amortization (“DD&A”) for our natural gas and crude oil properties increased to $65.1 million for the three months ended March 31, 2008 from $32.7 million in the same period in 2007. Our DD&A per Mcfe increased $0.30 to $2.85 in the first quarter of 2008 from $2.55 in the comparable period in 2007. The increase is primarily attributable to an increase in our depreciable properties, higher future development costs and increased production. Our production increased 78.1% to 22.8 Bcfe from 12.8 Bcfe in 2007.

DD&A for our other assets consists primarily of depreciation of our drilling rigs, midstream gathering and compression facilities and other equipment. The increase in DD&A for our other assets was attributable primarily to higher carrying costs of our rigs due to upgrades and retrofitting and our midstream gathering and processing assets due to upgrades made throughout 2007. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from three to 25 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life.

General and administrative expenses increased $8.5 million to $21.0 million for the three months ended March 31, 2008 from $12.5 million for the comparable period in 2007. The increase was principally attributable to an $8.8 million increase in corporate salaries and wages due to a significant increase in corporate and support staff. As of March 31, 2008, we had 2,385 employees as compared to 1,746 at March 31, 2007. General and administrative expenses include non-cash stock compensation expense of $3.2 million for the three months ended March 31, 2008 as compared to $1.1 million for the comparable period in 2007. The increases in salaries and wages as well as stock compensation were partially offset by $3.2 million in capitalized general and administrative

expenses for the three months ended March 31, 2008. There were no general and administrative expenses capitalized during the three months ended March 31, 2007.

For the three month period ended March 31, 2008, we recorded a loss of $136.8 million ($144.1 million unrealized loss and $7.3 million realized gain) on our derivative contracts compared to a $23.2 million loss ($21.7 million unrealized loss and $1.5 million realized loss) for the comparable period in 2007. During 2007 and the first three months of 2008, we selectively entered into natural gas and crude oil swaps and basis swaps in order to mitigate the effects of fluctuations in prices received for our production. Given the long-term nature of our investment in the WTO development program and the relatively high level of natural gas prices compared to budgeted prices, we believe it is prudent to enter into natural gas swaps and basis swaps for a portion of our production. Unrealized gains or losses on natural gas and crude oil derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the prior period end prices or contract price for contracts entered into during the period. The unrealized loss recorded in the three month period ended March 31, 2008 related to natural gas and crude oil commodities was attributable to an increase in average natural gas and crude oil prices at March 31, 2008 as compared to the average natural gas and crude oil prices at December 31, 2007 or the contract price for contracts entered into during the period.

Other Income (Expense). Total other expense decreased to $24.4 million in the three month period ended March 31, 2008 from $33.5 million in the three month period ended March 31, 2007. The decrease is reflected in the table below.


	Three Months Ended
	March 31,
	2008			2007			$ Change			% Change
	(In thousands)

Other income (expense):
Interest income	$	796		$	1,088		$	(292	)		(26.8)%
Interest expense		(25,172	)		(35,429	)		10,257			(29.0)%
Minority interest		(835	)		(146	)		(689	)		471.9%
Income from equity investments		859			1,025			(166	)		(16.2)%

Total other expense		(24,352	)		(33,462	)		9,110			(27.2)%

Loss before income tax expense (benefit)		(87,163	)		(29,994	)		(57,169	)		190.6%
Income tax expense (benefit)		(30,538	)		(10,501	)		(20,037	)		190.8%

Net loss	$	(56,625	)	$	(19,493	)	$	(37,132	)		190.5%

Interest income decreased to $0.8 million for the three months ended March 31, 2008 from $1.1 million for the same period in 2007. This decrease was generally due to lower excess cash levels during the three months ended March 31, 2008 as compared to the same period in 2007.

Interest expense decreased to $25.2 million for the three months ended March 31, 2008 from $35.4 million for the same period in 2007. This decrease was primarily attributable to the expensing, in March 2007, of approximately $12.5 million in unamortized debt issuance costs related to our senior bridge facility at the time it was repaid. Also contributing slightly to the decrease for the three months ended March 31, 2008 was an $0.8 million unrealized gain related to our interest rate swap These decreases were partially offset by increased interest expense during the three months ended March 31, 2008 due to higher average debt balances outstanding during that period as compared to the same period in 2007.

During the three months ended March 31, 2008, we reported income from equity investments of $0.9 million as compared to $1.0 million in the comparable period in 2007.

We reported an income tax benefit of $30.5 million for the three months ended March 31, 2008, as compared to a benefit of $10.5 million for the same period in 2007. The current period income tax benefit represents an effective income tax rate of 35% which is unchanged from the same period in 2007.

Liquidity and Capital Resources

Summary

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

On November 9, 2007, we completed the initial public offering of our common stock. We sold 32,379,500 shares of our common stock, including 4,170,000 shares sold directly to an entity controlled by our Chairman and Chief Executive Officer, Tom L. Ward. After deducting underwriting discounts of approximately $44.0 million and offering expenses of approximately $3.1 million, we received net proceeds of approximately $794.7 million. The net proceeds were utilized as follows (in millions):


Repayment of outstanding balance and accrued interest on senior credit facility	$	515.9
Repayment of note payable and accrued interest incurred in connection with recent acquisition		49.1
Excess cash to fund capital expenditures		229.7

Total	$	794.7

As of March 31, 2008, our cash and cash equivalents were $0.7 million, and we had approximately $462.3 million available under our senior credit facility. Amounts outstanding under our senior credit facility at March 31, 2008 totaled $215.0 million. As of March 31, 2008, we had $1.3 billion in total debt outstanding.

Recent Developments

Increase in Borrowing Base. In April 2008, the Company’s senior credit facility was increased to $1.75 billion from $750 million and its borrowing base was increased to $1.2 billion from $700.0 million.

Exchange of Senior Term Loans. On May 1, 2008, the Company issued $650.0 million in Senior Notes due 2015 in exchange for an equal outstanding principal amount of its fixed rate term loans and $350.0 million of its Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of its variable rate term loans. The exchange was made pursuant to a private placement exchange offer that commenced on March 28, 2008 and expired on April 28, 2008. The newly issued senior notes have terms that are substantially identical to those of the exchanged senior term loans, except that the senior notes have been issued with registration rights.

Sale of Assets. In May 2008, we entered into an agreement, along with other parties, to sell substantially all of our assets located in the Piceance Basin of Colorado to a subsidiary of The Williams Companies, Inc. The total purchase price is $285 million with net proceeds to the Company estimated to be approximately $140 million, subject to closing adjustments and allocation of the sales price among multiple sellers. Assets to be sold include undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells. The sale is subject to customary closing conditions and is expected to close during the second quarter of 2008.

Capital Expenditures

We make and expect to continue to make substantial capital expenditures in the exploration, development, production and acquisition of natural gas and crude oil reserves.

During the first quarter of 2008 and 2007, our capital expenditures by segment were:


	Three Months Ended
	March 31,
	2008		2007
	(In thousands)

Capital Expenditures:
Exploration and production	$	354,765	$	127,582
Drilling and oil field services		17,921		41,242
Midstream gas services		38,721		9,543
Other		7,243		2,728

Total	$	418,650	$	181,095

We estimate that our total capital expenditures for 2008, excluding acquisitions, will be approximately $1.5 billion. Our planned 2008 capital expenditures are consistent with 2007 levels. As in 2007, our 2008 capital expenditures for our exploration and production segment will be focused on growing and developing our reserves and production on our existing acreage and acquiring additional leasehold interests, primarily in the WTO. Of our total $1.5 billion capital expenditure budget, approximately $1.2 billion is budgeted for exploration and production activities. Included in our 2008 exploration and production capital expenditure budget is $723 million for drilling in the WTO, including the Piñon field, $241 million for drilling in areas other than the WTO, $33 million dedicated to our tertiary oil recovery program and $241 million for land and seismic. Based on encouraging initial results from our 3-D seismic acquisition program that we commenced in 2007, we have budgeted $151 million of our 2008 WTO capital expenditures to explore for new fields within the WTO. We plan to drill approximately 440 gross wells in 2008.

During 2008, we expect to complete our rig fleet expansion program that we started in 2005. We have accepted the delivery of all of the rigs ordered from Chinese manufacturers. We are in the process of retro-fitting and rigging up one of these rigs, which we expect to join our fleet during the second quarter of 2008. We are also continuing to upgrade and modernize our rig fleet. Approximately $67 million of our 2008 capital expenditure budget will be spent on our drilling and oil field services segment.

We anticipate spending approximately $195 million in capital expenditures in our midstream gas services and other segments as we expand our network of gas gathering lines and plant and compression capacity.

We believe that our cash flows from operations, current cash and investments on hand and availability under our senior credit facility will be sufficient to meet our capital expenditure budget for the next twelve months. The majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels or we are unable to obtain capital on attractive terms; however, we have various sources of capital in the form of our revolving credit facility, potential asset sales or the incurrence of additional long-term debt.

Cash Flows

Our cash flows for the three months ended March 31, 2008 and 2007 were as follows:


	Three Months Ended
	March 31,
	2008			2007
	(In thousands)

Cash flows provided by operating activities	$	156,689		$	43,963
Cash flows used in investing activities		(418,979	)		(182,546	)
Cash flows provided by financing activities		199,881			293,094

Net (decrease) increase in cash and cash equivalents	$	(62,409	)	$	154,511

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2008 and 2007 were $156.7 million and $44.0 million, respectively. The increase in cash provided by operating activities from 2007 to 2008 was primarily due to our 78.1% increase in production volumes as a result of our drilling success

in the WTO as well as various acquisitions throughout 2007 and the first three months of 2008. Also, contributing to this increase was a 27.8% increase in the combined average prices we received for the natural gas and crude oil produced. These increases were partially offset by increases in general and administrative costs, such as salaries and wages.

Investing Activities. Cash flows used in investing activities increased to $419.0 million in the three month period ended March 31, 2008 from $182.5 million in the comparable 2007 period as we continued to ramp up our capital expenditure program. For the three month period ended March 31, 2008, our capital expenditures were $354.8 million in our exploration and production segment, $17.9 million for drilling and oil field services, $38.7 million for midstream gas services and $7.2 million for other capital expenditures. During the same period in 2007, capital expenditures were $127.6 million in our exploration and production segment, $41.2 million for drilling and oil field services, $9.5 million for midstream gas services and $2.7 million for other capital expenditures.

Financing Activities. Since December 2005, we have used equity issuances, borrowings and, to a lesser extent, our cash flows from operations to fund our rapid growth. Proceeds from borrowings decreased to $340.2 million for the three months ended March 31, 2008, and we repaid approximately $128.9 million leaving net borrowings during the period of approximately $211.3 million. Our financing activities provided $199.9 million in cash for the three month period ended March 31, 2008 compared to $293.1 million in the comparable period in 2007.

Credit Facilities and Other Indebtedness

Senior Credit Facility. On November 21, 2006, we entered into a new $750.0 million senior secured revolving credit facility (the “senior credit facility”) with Bank of America, N.A., as Administrative Agent. The senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid without restriction so long as we are in compliance with its terms, including certain financial covenants. The initial proceeds of the senior credit facility were used to (i) partially finance the NEG acquisition, (ii) refinance our existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and our existing credit facility.

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

The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for (i) the 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 fiscal quarter on an annualized basis as of the end of fiscal quarters ending on or before September 30, 2008 and calculated using the last four completed fiscal quarters thereafter, (ii) the 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) the current ratio, which must be at least 1.0:1.0. As of March 31, 2008, we were in compliance with all of the covenants under the senior credit facility.

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

The borrowing base is subject to review semi-annually; however, the lenders reserve the right to have one additional redetermination of the borrowing base per calendar year. Unscheduled redeterminations may be made at our request, but are limited to one request per year. The borrowing base is determined based on proved developed

producing reserves, proved developed non-producing reserves and proved undeveloped reserves and was $700.0 million as of March 31, 2008. As of March 31, 2008, we had outstanding indebtedness of $237.7 million under our senior credit facility, including outstanding letters of credit of $22.7 million. The committed loan amount for the facility was increased to $1.75 billion and the borrowing base was increased to $1.2 billion during April 2008. As of May 5, 2008, the balance outstanding under our senior credit facility was $410.0 million.

At our election, interest under the senior credit facility is determined by reference to (i) LIBOR plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average interest rate paid on amounts outstanding under our senior credit facility for the three month period ended March 31, 2008 was 4.57%.

Senior Term Loans. On March 22, 2007, we issued $1.0 billion principal amount of senior unsecured term loans. The proceeds of the term loans were used to partially repay the senior bridge facility described below. The senior term loans include both a floating rate tranche and fixed rate tranche as described below.

We issued $350.0 million at a variable rate with interest payable quarterly and principal due on April 1, 2014 (the “variable rate term loans”). The variable rate term loans bear interest, at our option, at LIBOR plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%. After April 1, 2009, the variable rate term loans may be prepaid in whole or in part with a prepayment penalty. The average interest rates paid on amounts outstanding under our variable rate term loans for the three month period ended March 31, 2008 was 8.36%. In January 2008, we entered into a $350 million notional amount interest rate swap agreement with a financial institution that effectively fixed our interest rate on the variable rate term loans at 6.2625% for the period from April 1, 2008 to April 1, 2011.

We also issued $650.0 million at a fixed rate of 8.625% with principal due on April 1, 2015 (the “fixed rate term loans”). Under the terms of the fixed rate term loans, interest is payable quarterly and during the first four years interest may be paid, at our option, either entirely in cash or entirely with additional fixed rate term loans. If we elect to pay the interest due during any period in additional fixed rate term loans, the interest rate increases to 9.375% during such period. After April 1, 2011, the fixed rate term loans may be prepaid in whole or in part with prepayment penalties.

On March 28, 2008, we commenced an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. The offer expired on April 28, 2008, and on May 1, 2008, we issued $650.0 million of Senior Notes due 2015 in exchange for an equal outstanding principal amount of fixed rate term loans and $350.0 million of Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of variable rate term loans. The newly issued senior notes have terms that are substantially identical to those of the exchanged senior term loans, except that the senior notes have been issued with registration rights.

Debt covenants under the senior term loans include financial covenants similar to those of the senior credit facility and include limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties and consolidation or merger agreements. We incurred $26.1 million of debt issuance costs in connection with the senior term loans. These costs are included in other assets and amortized over the term of the senior term loans.

Other Indebtedness. We have financed a portion of our drilling rig fleet and related oil field services equipment through notes payable. At March 31, 2008, the aggregate outstanding balance of these notes was $44.3 million, with annual fixed interest rates ranging from 7.64% to 8.87%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments for principal and interest in the amount of $1.2 million and are secured by the equipment. The notes have a prepayment penalty (currently ranging from 1 to 3%) that is triggered if we repay the notes prior to maturity.

Building Mortgage. On November 15, 2007, we entered into a $20.0 million note payable which is fully secured by one of the buildings and a parking garage located on our property in downtown Oklahoma City,

Oklahoma which we purchased in July 2007 to serve as its corporate headquarters. The mortgage bears interest at 6.08% per annum, 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. We expect to make payments of principal and interest on this note totaling $0.8 million and $1.2 million, respectively, over the next twelve months.

We have financed the purchase of other equipment used in our business. At March 31, 2007, the aggregate outstanding balance on these financings was $6.8 million. We substantially repaid such borrowings during July 2007 with borrowings under our senior credit facility.

Senior Bridge Facility. On November 21, 2006, we entered into an $850.0 million senior unsecured bridge facility in conjunction with the acquisition of NEG. This facility was repaid in full in March 2007 with proceeds from our senior unsecured term loans.

Redeemable Convertible Preferred Stock

We had 1,844,464 shares of redeemable convertible preferred stock issued and outstanding at March 31, 2008. Each holder of our redeemable convertible preferred stock is entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value of its redeemable convertible preferred stock. At our option, we may choose to increase the accreted value of the redeemable convertible preferred stock in lieu of paying any quarterly cash dividend. We have paid all dividends in cash, including $33.3 million in 2007 and $9.5 million in the first quarter of 2008. The accreted value was $210 per share as of March 31, 2008 and each share of redeemable convertible preferred stock was convertible into approximately 10.2 shares of common stock at the option of the holder, subject to certain anti-dilution adjustments. During March 2008, holders of 339,823 shares of our redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of our common stock. In May 2008, we converted the remaining outstanding 1,844,464 shares of our redeemable convertible preferred stock into 18,810,260 shares of our common stock as permitted under the terms of the redeemable convertible preferred stock. This conversion resulted in a one-time charge to retained earnings of $6.1 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.


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 price and interest rate volatility. All contracts are financial contracts, which are settled in cash and do not require the delivery of a physical quantity to satisfy settlement.

Commodity Price Risk. Our most significant market risk is the prices we receive for our natural gas and crude oil production. In light of the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of natural gas and crude oil prices we receive for our production. From time to time, we enter into commodities pricing derivative contracts for a portion of our anticipated production volumes depending upon our 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 derivatives transactions to 85% of expected production volumes from estimated proved reserves. Future credit agreements could require a minimum level of commodity price hedging.

We use, or may use, a variety of commodity-based derivative contracts, including collars, fixed-price swaps and basis protection swaps. These transactions generally require no cash payment upfront and are settled in cash at maturity. While our derivative strategy may result in lower operating profits than if we were not party to these derivative contracts in times of high natural gas prices, we believe that the stabilization of prices and protection afforded us by providing a revenue floor for our production is very beneficial.

For natural gas derivatives, transactions are settled based upon the New York Mercantile Exchange price of natural gas at the Waha hub, a West Texas gas marketing and delivery center, on the final trading day of each month.

Settlement for natural gas derivative contracts occurs in the month following the production month. Generally, our trade counterparties are affiliates of the financial institution that is a party to our credit agreement, although we do have transactions with counterparties that are not affiliated with this institution.

While we believe that the natural gas and crude oil price derivative arrangements we enter into are important to our program to manage price variability for our production, we have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which reflects changes in natural gas and crude oil prices. We establish fair value of our derivative contracts by market price quotations of the derivative contract or, if not available, market price quotations obtained from counterparties. Changes in fair values of our derivative contracts that are not designated as hedges for accounting purposes 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 arrangements. Changes in fair value are principally measured based on period end prices as compared to the contract price.

The following table summarizes the cash settlements and valuation gains and losses on our natural gas and crude oil commodity derivative contracts for the three months ended March 31, 2008 and 2007:


	Three Months Ended
	March 31,
	2008			2007
	(In thousands)

Realized (gain) loss	$	(7,329	)	$	1,519
Unrealized loss		144,173			21,662

Loss on derivative contracts	$	136,844		$	23,181

At March 31, 2008, our open natural gas and crude oil commodity derivative contracts consisted of the following:

Natural Gas


	Notional		Weighted Avg.
Period and Type of Contract	(in MMBtus)		Fixed Price

April 2008 — June 2008
Price swap contracts		17,900	$	7.69
Basis swap contracts		13,350	$	(0.59	)
July 2008 — September 2008
Price swap contracts		18,100	$	8.23
Basis swap contracts		15,640	$	(0.57	)
October 2008 — December 2008
Price swap contracts		17,480	$	8.67
Basis swap contracts		14,720	$	(0.65	)
January 2009 — March 2009
Price swap contracts		6,300	$	9.12
Basis swap contracts		2,700	$	(0.49	)
April 2009 — June 2009
Price swap contracts		910	$	8.10
Basis swap contracts		2,730	$	(0.49	)
July 2009 — September 2009
Basis swap contracts		2,760	$	(0.49	)
October 2009 — December 2009
Basis swap contracts		2,760	$	(0.49	)


	Notional		Weighted Avg.
Period and Type of Contract	(in MMBtus)		Fixed Price

January 2011 — March 2011
Basis swap contracts		1,350	$	(0.47	)
April 2011 — June 2011
Basis swap contracts		1,365	$	(0.47	)
July 2011 — September 2011
Basis swap contracts		1,380	$	(0.47	)
October 2011 — December 2011
Basis swap contracts		1,380	$	(0.47	)

Crude Oil


	Notional		Weighted Avg.
Period and Type of Contract	(in MBbls)		Fixed Price

April 2008 — June 2008
Price swap contracts		270	$	95.04
Collar contracts		21	$	50.00 — 83.35
July 2008 — September 2008
Price swap contracts		225	$	94.33
Collar contracts		27	$	50.00 — 82.60
October 2008 — December 2008
Price swap contracts		225	$	93.17
Collar contracts		27	$	50.00 — 82.60

These derivatives have not been designated as hedges and the Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. Cash settlements and valuation gains and losses on commodity derivative contracts are included in loss on derivative contracts in the consolidated statements of operations.

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

We use sensitivity analysis to determine the impact that market risk exposures may have on our variable interest rate borrowings. Based on the approximately $350.0 million outstanding balance of the variable rate portion of our senior term loans at March 31, 2008, and $215.0 million outstanding balance on our senior credit facility a one percent change in the applicable rates, with all other variables held constant, would result in a change in our interest expense of approximately $1.4 million for the three months ended March 31, 2008.

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 agreements. At March 31, 2008, we did not have any interest rate swap contracts in effect. In January 2008, we entered into a $350.0 million notional amount interest rate swap agreement with a financial institution that effectively fixed our interest rate on the variable rate term loans at 6.2625% for the period from April 1, 2008 through April 1, 2011. This swap has not been designated as a hedge.

An unrealized gain of $0.8 million was recorded in interest expense in the condensed consolidated statement of operation for the change in fair value of the interest rate swap for the three months ended March 31, 2008.

ITEM 4. Controls and Procedures

We performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, 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 report. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective 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 were no changes in our internal control over financial reporting during the quarter ended March 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. Other Information


ITEM 1.	*Legal Proceedings*

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


ITEM 1A.	*Risk Factors*

There have been no material changes to the risk factors previously disclosed in Item 1A — Risk Factors in our 2007 Form 10-K.


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

As part of our restricted stock program, we make required tax payments on behalf of employees as their stock awards vest and then withhold a number of vested shares having a value on the date of vesting equal to the tax obligation. The shares withheld are recorded as treasury shares. During the quarter ended March 31, 2008, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:

Total Number of

Maximum Number

Shares Purchased

of Shares that May

Total Number

Average

as Part of Publicly

Yet Be Purchased

of Shares

Price Paid

Announced Plans

Under the Plans

Period

Purchased

per Share

or Programs

January 1, 2008 — January 31, 2008

36,218

32.81

N/A

February 1, 2008 — February 29, 2008

779

36.00

N/A

March 1, 2008 — March 31, 2008

992

37.96

N/A


ITEM 6.	*Exhibits*

See the Exhibit Index accompanying this report.

EXHIBIT INDEX


				*Filed Herewith () or**
Exhibit				Incorporated by	File
Number			Description	Reference to Exhibit No.	Number

	3	.1	Certificate of Incorporation	3.1 to Registration Statement on Form S-1 filed on January 30, 2008	333-148956
	3	.2	Certificate of Designation of convertible preferred stock	3.2 to Registration Statement on Form S-1 filed on January 30, 2008	333-148956
	3	.3	Bylaws	*
	4	.1	Indenture dated as of May 1, 2008 among SandRidge Energy, Inc. and the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee	4.1 to Current Report on Form 8-K filed on May 1, 2008	1-33784
	4	.2	Registration Rights Agreement dated as of May 1, 2008 among SandRidge Energy, Inc. and the several guarantors named therein for the benefit of the holders of the Company’s Senior Notes Due 2015 and the Company’s Senior Floating Rate Notes Due 2014	4.2 to Current Report on Form 8-K filed on May 1, 2008	1-33784
	10	.5.2†	Employment Agreement of Dirk M. Van Doren, effective January 1, 2008	*
	10	.5.3†	Employment Agreement of Matthew K. Grubb, effective January 1, 2008	*
	10	.5.4†	Employment Agreement of Todd N. Tipton, effective January 1, 2008	*
	10	.5.5†	Employment Agreement of Larry K. Coshow, effective January 1, 2008	*
	10	.5.6†	Form of Employment Agreement for Senior Vice Presidents	*
	10	.5.7†	Employment Separation Agreement of Larry K. Coshow, dated April 14, 2008	*
	10	.7.3	Amendment No. 3, dated September 14, 2007, to Senior Credit Facility, dated November 21, 2006, by and among SandRidge Energy, Inc. (as successor by merger to Riata Energy, Inc.) and Bank of America, N.A., as Administrative Agent and Banc of America Securities LLC as Lead Arranger and Book Running Manager	*
	10	.7.4	Amendment No. 4, dated April 4, 2008, to Senior Credit Facility, dated November 21, 2006, by and among SandRidge Energy, Inc. (as successor by merger to Riata Energy, Inc.) and Bank of America, N.A., as Administrative Agent and Banc of America Securities LLC as Lead Arranger and Book Running Manager	*
	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	*


†		Management contract or compensatory plan or arrangement


	Three Months Ended
	March 31,
	2008			2007
	(Unaudited)
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(56,625	)	$	(19,493	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		83,041			42,844
Debt issuance cost amortization		1,097			12,752
Deferred income taxes		(30,617	)		(10,501	)
Unrealized loss on derivative contracts		143,367			21,662
Loss (gain) on sale of assets		23			(1	)
Interest income — restricted deposits		(192	)		(266	)
Income from equity investments, net of distributions		(859	)		(1,025	)
Stock-based compensation		3,241			1,071
Minority interest		835			146
Changes in operating assets and liabilities		13,378			(3,226	)

Net cash provided by operating activities		156,689			43,963

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(418,650	)		(181,095	)
Proceeds from sale of assets		452			26
Fundings of restricted deposits		(781	)		(1,477	)

Net cash used in investing activities		(418,979	)		(182,546	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		340,220			1,142,772
Repayments of borrowings		(128,937	)		(1,136,845	)
Dividends paid — preferred		(9,516	)		(6,859	)
Minority interest (distributions) contributions		(632	)		762
Proceeds from issuance of common stock		—			318,925
Purchase of treasury stock		(1,254	)		(661	)
Debt issuance costs		—			(25,000	)

Net cash provided by financing activities		199,881			293,094

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(62,409	)		154,511
CASH AND CASH EQUIVALENTS, beginning of year		63,135			38,948

CASH AND CASH EQUIVALENTS, end of period	$	726		$	193,459

Supplemental Disclosure of Noncash Investing and Financing Activities:
Insurance premiums financed	$	—		$	1,496
Accretion on redeemable convertible preferred stock	$	1,487		$	350


	Three Months Ended
	March 31,
	2008		2007

Depreciation, Depletion and Amortization:
Exploration and production	$	65,590	$	33,211
Drilling and oil field services		12,348		7,163
Midstream gas services		2,774		1,113
Other		2,329		1,357

Total depreciation, depletion and amortization	$	83,041	$	42,844

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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 Stockholders’ 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	22
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	34
ITEM 4.	Controls and Procedures	37
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	37
ITEM 1A.	Risk Factors	37
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
ITEM 6.	Exhibits	37
Bylaws
Employment Agreement - Dirk M. Van Doren
Employment Agreement - Matthew K. Grubb
Employment Agreement - Todd N. Tipton
Employment Agreement - Larry K. Coshow
Form of Employment Agreement for Senior Vice Presidents
Employment Separation Agreement of Larry K. Coshow
Amendment No. 3 to Senior Credit Facility
Amendment No. 4 to Senior Credit Facility
Section 302 Certification - Chief Executive Officer
Section 302 Certification - Chief Financial Officer
Section 906 Certification of Chief Executive Officer and Chief Financial Officer


(1)		Identifiable assets are those used in SandRidge’s operations in each business segment.