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

Form 10-Q


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended ~~September 30, 2007~~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)		~~20-8084793~~ (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 oþ No þo

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


Large accelerated filer o	Accelerated filer o	o ~~Accelerated filer~~ oNon-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 inRule 12b-2 of the Exchange Act). Yes o No þ

The number of shares outstanding of the registrant’s common stock, par value $0.001 per shares, as of the close of business on ~~November~~April 30, ~~2007,~~2008, was ~~141,845,661.~~146,194,356.

SANDRIDGE ENERGY, INC.
FORM 10-Q
Quarter Ended ~~September 30, 2007~~March 31, 2008

INDEX


PART I. FINANCIAL INFORMATION
ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated ~~Statements~~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	3934
ITEM 4.	Controls and Procedures	4137

PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	4137
ITEM 1A.	Risk Factors	4237
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4237
ITEM 6.	Exhibits	42
~~Signature~~		43
~~Index to Exhibits~~		44
~~Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~
~~Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~		37
~~Certification of CEO Pursuant to Section 302~~Bylaws
~~Certification of CFO Pursuant to Section 302~~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 ~~CEO & CFO Pursuant to Section 906~~Chief Executive Officer and Chief Financial Officer

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report onForm 10-Q ~~(“Quarterly Report”)~~ includes “forward-looking statements” within the meaning of ~~various provisions~~Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Various statements contained in this ~~Quarterly Report,~~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 ~~may~~ 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 ~~future production, revenues, income and capital spending.~~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 ~~Risk Factors~~the risk factors discussed in Item 1A of our ~~Registration Statement~~annual report onForm ~~S-1~~10-K ~~filed with~~for the ~~Securities and Exchange Commission on October 23,~~year ended December 31, 2007, ~~andItem 1A-~~ ~~Risk Factors contained herein,~~ 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 ~~document~~report are qualified by these cautionary ~~statements and there can be no assurance that the~~statements. The actual results or developments anticipated ~~will~~may not be realized or, even if substantially realized, ~~that~~ they ~~will~~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


		September 30,			December 31,				March 31,			December 31,
		2007			2006				2008			2007
		(Unaudited)							(Unaudited)
		(In thousands)							(In thousands)

ASSETS	ASSETS							ASSETS
Current assets:
Cash and cash equivalents		$	32,013		$	38,948			$	726		$	63,135
Accounts receivable, net:
Trade			71,957			89,774				112,674			94,741
Related parties			16,727			5,731				23,037			20,018
Derivative contracts			27,903			—				—			21,958
Inventories			4,249			2,544				4,864			3,993
Deferred income taxes			—			6,315				1,428			1,820
Other current assets			20,548			31,494				20,373			20,787

Total current assets			173,397			174,806				163,102			226,452
Oil and natural gas properties, using full cost method of accounting
Crude oil and natural gas properties, using full cost method of accounting
Proved			2,388,534			1,636,832				3,204,557			2,848,531
Unproved			247,757			282,374				259,610			259,610
Less: accumulated depreciation and depletion			(174,552	)		(60,752	)			(294,729	)		(230,974	)

			2,461,739			1,858,454				3,169,438			2,877,167

Other property, plant and equipment, net			427,756			276,264				506,156			460,243
Derivative contracts			4,139			—				2,145			270
Goodwill			27,076			26,198
Investments			6,983			3,584				8,815			7,956
Restricted deposits			39,851			33,189				32,633			31,660
Other assets			29,515			15,889				25,543			26,818

Total assets		$	3,170,456		$	2,388,384			$	3,907,832		$	3,630,566

															LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current maturities of long-term debt		$	14,293		$	26,201			$	15,662		$	15,350
Accounts payable and accrued expenses:
Trade			181,227			129,799				242,324			215,497
Related parties			3,182			1,834				1,747			395
Deferred income taxes			6,740			—
Asset retirement obligation										882			864
Derivative contracts			—			958				123,284			—

Total current liabilities			205,442			158,792				383,899			232,106
Long-term debt			1,437,211			1,040,630				1,263,270			1,052,299
Derivative contracts			—			3,052
Other long-term obligations			16,219			21,219				16,817			16,817
Asset retirement obligation			57,508			45,216				60,748			57,716
Deferred income taxes			32,992			24,922				18,341			49,350

Total liabilities			1,749,372			1,293,831				1,743,075			1,408,288

Commitments and contingencies (Note 12)
Commitments and contingencies (Note 11)
Minority interest			5,605			5,092				4,875			4,672
Redeemable convertible preferred stock, $0.001 par value, 2,650 shares authorized; 2,184 and 2,137 shares issued and outstanding at September 30, 2007 and December 31, 2006, respectively			450,356			439,643
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, no par; 50,000 shares authorized; no shares issued and outstanding in 2007 and 2006			—			—
Common stock, $0.001 par value, 400,000 shares authorized; 109,272 issued and 107,820 outstanding at September 30, 2007 and 93,048 issued and 91,604 outstanding at December 31, 2006			108			92
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			889,211			574,868				1,763,225			1,686,113
Treasury stock, at cost			(18,496	)		(17,835	)			(17,389	)		(18,578	)
Retained earnings			94,300			92,693				33,009			99,216

Total stockholders’ equity			965,123			649,818				1,778,989			1,766,891

Total liabilities and stockholders’ equity		$	3,170,456		$	2,388,384			$	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						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2007			2006			2007			2006			2008			2007
	(Unaudited)												(Unaudited)
	(In thousands except per share amounts)												(In thousands except per share amounts)

Revenues:
Natural gas and crude oil	$	113,106		$	18,150		$	319,556		$	46,419		$	205,487		$	90,176
Drilling and services		16,684			35,742			56,928			105,713			12,334			27,895
Midstream and marketing		19,030			29,326			71,131			91,218			46,409			26,187
Other		4,828			6,432			14,160			19,827			4,856			4,806

Total revenues		153,648			89,650			461,775			263,177			269,086			149,064
Expenses:
Production		28,689			7,960			77,707			21,625			34,188			21,974
Production taxes		4,402			1,050			12,328			2,579			9,220			2,933
Drilling and services		6,809			24,985			30,935			72,670			7,169			18,777
Midstream and marketing		14,444			27,139			61,191			85,525			40,418			23,420
Depreciation, depletion and amortization — natural gas and crude oil		45,177			6,064			115,876			13,932			65,076			32,684
Depreciation, depletion and amortization — other		14,282			8,298			36,545			22,106			17,965			10,160
General and administrative		20,421			11,721			45,781			32,024			20,994			12,468
Gain on derivative contracts		(39,247	)		(5,304	)		(55,228	)		(16,176	)
Gain on sale of assets		(1,045	)		(839	)		(1,704	)		(849	)
Loss on derivative contracts														136,844			23,181
Loss (gain) on sale of assets														23			(1	)

Total expenses		93,932			81,074			323,431			233,436			331,897			145,596

Income from operations		59,716			8,576			138,344			29,741
(Loss) income from operations														(62,811	)		3,468

Other income (expense):
Interest income		575			51			4,201			448			796			1,088
Interest expense		(28,522	)		(2,506	)		(88,630	)		(4,090	)		(25,172	)		(35,429	)
Minority interest		(164	)		(182	)		(321	)		(281	)		(835	)		(146	)
Income from equity investments		1,235			737			3,399			40			859			1,025

Total other income (expense)		(26,876	)		(1,900	)		(81,351	)		(3,883	)
Total other (expense) income														(24,352	)		(33,462	)

Income before income tax expense		32,840			6,676			56,993			25,858
Income tax expense		11,920			1,781			21,002			6,931
Loss before income tax benefit														(87,163	)		(29,994	)
Income tax benefit														(30,538	)		(10,501	)

Net income		20,920			4,895			35,991			18,927
Net loss														(56,625	)		(19,493	)
Preferred stock dividends and accretion		9,313			—			30,573			—			9,582			8,966

Income available to common stockholders	$	11,607		$	4,895		$	5,418		$	18,927
Loss applicable to common stockholders													$	(66,207	)	$	(28,459	)

Basic and diluted income per share available to common stockholders	$	0.11		$	0.07		$	0.05		$	0.26
Basic and diluted loss per share applicable to common stockholders													$	(0.47	)	$	(0.31	)

Weighted average number of shares outstanding:
Weighted average number of common shares outstanding:
Basic		107,554			71,870			102,562			71,692			141,044			92,442

Diluted		109,049			72,806			103,778			72,633			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														Additional
	Common			Paid-in			Treasury			Retained						Common		Paid-In		Treasury			Retained
	Stock			Capital			Stock			Earnings			Total			Stock		Capital		Stock			Earnings			Total
	(Unaudited)															(Unaudited)
	(In thousands)															(In thousands)

Balance, December 31, 2006	$	92		$	574,868		$	(17,835	)	$	92,693		$	649,818
Stock offering, net of $1.4 million in offering costs		18			318,652			—			—			318,670
Conversion of common stock to redeemable convertible preferred stock		(1	)		(9,650	)		—			—			(9,651	)
Accretion on redeemable convertible preferred stock		—			—			—			(1,062	)		(1,062	)
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	)		—			(1,578	)		—			(1,579	)		—		—		(1,254	)		—			(1,254	)
Common stock issued under retirement plan		—			379			917			—			1,296			—		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		—			4,962			—			—			4,962			—		3,241		—			—			3,241
Net income		—			—			—			35,991			35,991
Net loss																	—		—		—			(56,625	)		(56,625	)
Redeemable convertible preferred stock dividend		—			—			—			(33,322	)		(33,322	)		—		—		—			(8,095	)		(8,095	)

Balance, September 30, 2007	$	108		$	889,211		$	(18,496	)	$	94,300		$	965,123
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

Condensed Consolidated Statements of Cash Flows


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
	2007			2006			2008			2007
	(Unaudited)						(Unaudited)
	(In thousands)						(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	35,991		$	18,927
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for doubtful accounts		—			2,458
Net loss							$	(56,625	)	$	(19,493	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		152,421			36,038			83,041			42,844
Debt issuance cost amortization		14,903			—			1,097			12,752
Deferred income taxes		20,004			2,662			(30,617	)		(10,501	)
Unrealized gain on derivatives		(36,052	)		(2,007	)
Gain on sale of assets		(1,704	)		(849	)
Unrealized loss on derivative contracts								143,367			21,662
Loss (gain) on sale of assets								23			(1	)
Interest income — restricted deposits		(1,024	)		—			(192	)		(266	)
Income from equity investments, net of distributions		(3,399	)		(28	)		(859	)		(1,025	)
Stock-based compensation		4,962			8,156			3,241			1,071
Minority interest		321			281			835			146
Changes in operating assets and liabilities		53,133			1,862			13,378			(3,226	)

Net cash provided by operating activities		239,556			67,500			156,689			43,963

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(895,160	)		(181,231	)		(418,650	)		(181,095	)
Acquisition of assets		(3,001	)		(63,125	)
Proceeds from sale of assets		6,458			19,742			452			26
Proceeds from sale of investment		—			2,373
Contributions on equity investments		—			(3,388	)
Restricted deposits		(5,638	)		—
Restricted cash		—			2,373
Fundings of restricted deposits								(781	)		(1,477	)

Net cash used in investing activities		(897,341	)		(223,256	)		(418,979	)		(182,546	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,262,769			295,215			340,220			1,142,772
Repayments of borrowings		(879,592	)		(177,425	)		(128,937	)		(1,136,845	)
Dividends paid — preferred		(24,366	)		—			(9,516	)		(6,859	)
Minority interest contributions (distributions)		192			(390	)
Minority interest (distributions) contributions								(632	)		762
Proceeds from issuance of common stock		319,966			3,343			—			318,925
Purchase of treasury shares		(1,579	)		—
Purchase of treasury stock								(1,254	)		(661	)
Debt issuance costs		(26,540	)		—			—			(25,000	)

Net cash provided by financing activities		650,850			120,743			199,881			293,094

NET DECREASE IN CASH AND CASH EQUIVALENTS		(6,935	)		(35,013	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS								(62,409	)		154,511
CASH AND CASH EQUIVALENTS, beginning of year		38,948			45,731			63,135			38,948

CASH AND CASH EQUIVALENTS, end of period	$	32,013		$	10,718		$	726		$	193,459

Supplemental Disclosure of Noncash Investing and Financing Activities:
Insurance premiums financed	$	1,496		$	—		$	—		$	1,496
Accretion on redeemable convertible preferred stock	$	1,062		$	—		$	1,487		$	350
Common stock issued in connection with acquisitions	$	—		$	5,128
Redeemable convertible preferred stock dividends, net of dividends paid	$	8,956		$	—
Property, plant and equipment addition due to settlement	$	4,500		$	—

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. ~~and~~, together with its subsidiaries (collectively, the “Company” or “SandRidge”), ~~“SandRidge”, “we”, “us”, or “our”)~~ is ana natural gas and crude oil ~~and gas~~ company with its principal focus on exploration, development and ~~production related to~~production. SandRidge also owns and operates natural gas gathering, marketing and processing facilities and CO₂ treating and transportation facilities and conducts tertiary oil ~~and gas activities.~~recovery operations. In addition, SandRidge ~~also~~ owns and operates drilling rigs and ~~provides~~a related oil field services ~~midstream gas services operations, and CO~~₂ ~~and tertiary oil recovery operations.~~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, ~~and~~the Gulf Coast ~~area.~~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 ~~balance sheet~~financial statements as of December 31, ~~2006 has~~2007 have been derived from ~~our~~the audited financial statements contained in the Company’s ~~Registration Statement~~annual report onForm ~~S-1/A~~10-K ~~filed October 23,~~for the fiscal year ended December 31, 2007 (the ~~“Registration Statement”~~“2007Form 10-K”). The unaudited interim condensed consolidated financial statements of SandRidge ~~and its subsidiaries~~ have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the ~~Company’s~~2007~~S-1/A~~Form 10-K. ~~filed October 23, 2007 pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).~~ 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 ~~we believe~~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 ~~for a fair presentation~~to state fairly the information in ~~accordance with GAAP have been included in these~~the Company’s unaudited ~~interim~~ condensed consolidated financial ~~statements.~~statements have been included. These condensed financial statements should be read in conjunction with the financial statements and notes thereto included in the ~~Registration Statement.~~2007Form 10-K.


2.	Significant Accounting Policies

For a description of the Company’s accounting policies, refer to Note 1 of the ~~2006~~ consolidated financial statements included in the ~~Company’s Registration Statement, as well as Note 10 herein.~~2007Form 10-K.

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

~~Change in Method~~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 ~~Oil~~measuring fair value and ~~Gas Operations.~~ Inexpands 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 ~~fourth quarter of 2006, the Company changed from the successful efforts method to the full cost method of accounting for its oil and gas operations. Prior period~~Company’s financial statements ~~presented herein have been restated to reflect the change.~~other than requiring additional disclosures regarding fair value measurements. See Note 4.

~~SandRidge’s~~In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff PositionFAS 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 ofFSP 157-2 is not expected to have a material impact on the Company’s financial position, results ~~have been retroactively restated to reflect~~of operations or cash flows.

In December 2007, the ~~conversion to~~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 full cost method. As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred foridentifiable assets acquired, the ~~purpose of finding oil and gas reserves.~~liabilities assumed, any noncontrolling

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

~~A comparison~~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 ~~Company’s previously presented income tax expense, net income, and earnings per share under~~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 ~~successful efforts method~~potential impact of ~~accounting to its results of operations disclosed herein are as follows (in thousands, except per share amounts):~~

Three Months Ended
Nine Months Ended

September 30, 2006 September 30, 2006
(As Originally
(As Originally

Presented) (As Restated) Presented) (As Restated)

Income tax expense $ 4,844 $ 1,781 $ 8,998 $ 6,931

Net income $ 13,308 $ 4,895 $ 15,175 $ 18,927

Basic earnings per share $ 0.18 $ 0.07 $ 0.21 $ 0.26

Diluted earnings per share $ 0.18 $ 0.07 $ 0.21 $ 0.26

this standard.

~~Oil and Natural Gas Operations.~~ The Company uses the full cost method to account for its natural gas and oil properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of natural gas and oil reserves are capitalized into a “full cost pool.” These capitalized costs include costs of all unproved properties, internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. These costs are amortized using a unit-of-production method. Under this method, the provision for depreciation, depletion and amortization is computed at the end of each quarter by multiplying total production for such quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base by net equivalent proved reserves at the beginning of the quarter.

~~Recent Accounting Pronouncements.~~In ~~September 2006,~~December 2007, the FASB issued SFAS No. ~~157, “Fair Value Measurements,”~~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 ~~formal framework for measuring fair values~~parent’s ownership interest and the valuation of ~~assets~~retained noncontrolling equity investments when a subsidiary is deconsolidated. The Statement also establishes disclosure requirements to clearly identify and ~~liabilities in financial statements that are already required by GAAP to be measured at fair value.~~distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. ~~157 clarifies guidance in~~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 ~~Concepts~~issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, which changes disclosure requirements for derivative instruments and hedging activities. The Statement ~~(“CON”) No. 7 which discusses present value techniques in measuring fair value. Additional~~requires enhanced disclosure, including qualitative disclosures ~~are also required~~about objectives and strategies for ~~transactions measured at fair value. No new~~using derivatives, quantitative disclosures about fair value ~~measurements are prescribed,~~amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 157 is intended to codify the several definitions of fair value included in various accounting standards. However, the application of this Statement may change current practices for certain companies. SFAS No. 157161 is effective for fiscal years beginning after November 15, ~~2007.~~2008. The Company ~~is currently evaluating the impact of adopting SFAS No. 157~~plans to implement this standard on ~~the financial statements.~~

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option For Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115”(“SFAS No. 159”), which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS No. 159 also revises provisions of SFAS No. 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007.January 1, 2009. The Company has not yet evaluated the potential impact of this standard.


3.	~~Acquisitions and Dispositions~~

On March 15, 2006, the Company acquired from an executive officer and director, an additional 12.5% interest in PetroSource Energy Company, a consolidated subsidiary. The acquisition consisted of the extinguishment of subordinated debt of approximately $1.0 million and a $4.5 million cash payment for the ownership interest acquired for a total acquisition price of approximately $5.5 million.

On May 1, 2006, the Company purchased certain leases in developed and undeveloped properties from an oil and gas company. The purchase price was approximately $40.9 million in cash. The cash consideration was paid in July 2006.

On May 26, 2006, the Company purchased several oil and natural gas properties from an oil and gas company. The purchase price was approximately $12.9 million, comprised of $8.2 million in cash, and 251,351 shares of

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~

~~SandRidge Energy, Inc. common stock (valued at $4.7 million). The cash and equity consideration was paid in July 2006.~~

On June 7, 2006, the Company acquired the remaining 1% interest in PetroSource Energy Company, a consolidated subsidiary, from an oil and gas company. The purchase price was 27,749 shares of SandRidge Energy, Inc. common stock (valued at $0.5 million). As a result of this acquisition, the Company became a 100% owner of PetroSource Energy Company.

In July 2006, the Company sold leaseholds and lease and well equipment for $16.0 million. The book basis of the assets at the time of the sale transaction was $3.7 million resulting in a gain of $12.3 million. The sale was accounted for as an adjustment to the full cost pool, with no gain recognized.


4.	Property, Plant and Equipment

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


	September 30,			December 31,			March 31,			December 31,
	2007			2006			2008			2007

Oil and natural gas properties:
Crude oil and natural gas properties:
Proved	$	2,388,534		$	1,636,832		$	3,204,557		$	2,848,531
Unproved		247,757			282,374			259,610			259,610

Total oil and natural gas properties		2,636,291			1,919,206
Total crude oil and natural gas properties								3,464,167			3,108,141
Less accumulated depreciation and depletion		(174,552	)		(60,752	)		(294,729	)		(230,974	)

Net oil and natural gas properties capitalized costs		2,461,739			1,858,454
Net crude oil and natural gas properties capitalized costs								3,169,438			2,877,167

Land		1,344			738			1,344			1,149
Non oil and gas equipment		491,000			337,294
Non crude oil and natural gas equipment								602,488			539,893
Buildings and structures		37,725			6,564			39,225			38,288

Total		530,069			344,596			643,057			579,330
Less accumulated depreciation, depletion and amortization		(102,313	)		(68,332	)		(136,901	)		(119,087	)

Net capitalized costs		427,756	��		276,264			506,156			460,243

Total property, plant and equipment	$	2,889,495		$	2,134,718		$	3,675,594		$	3,337,410

The amount of capitalized interest ~~in the nine months ended September 30, 2007 and 2006 was approximately $1.5 million and $1.0 million, respectively, and is~~ included in the above non crude oil and natural gas equipment ~~balance.~~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 issuedFSP 157-2, which delayed the effective date of SFAS No. 157 by one year for certain nonfinancial assets and liabilities.

~~On July 11, 2007,~~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 ~~purchased property to serve as~~has classified its ~~future corporate headquarters. The 3.51-acre site contains four buildings and is located in downtown Oklahoma City, Oklahoma. The purchase price~~derivative contracts into one of the ~~property was approximately $25 million in cash plus~~three levels based upon the ~~assumption of an obligation~~data relied upon to ~~indemnify~~determine the ~~sellers in connection with pending litigation involving the property. Payment~~fair value. The fair values of the ~~purchase price was funded through a draw on~~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 ~~senior credit facility.~~ 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 ~~related litigation was settled subsequent to September 30, 2007, resulting in an additional cost to the Company of $4.5 million which was treated as an adjustment to the purchase price~~determination of the ~~property. For additional discussion~~fair values above incorporates various factors required under SFAS No. 157. These factors include not only the impact of ~~this settlement, refer to Note 17 herein.~~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.	~~Goodwill~~

~~The change in the carrying amount of goodwill from December 31, 2006 to September 30, 2007 was as follows (in thousands):~~

Balance at December 31, 2006 $ 26,198
Adjustments 878

Balance at September 30, 2007 $ 27,076

The adjustments made in the nine months ended September 30, 2007 related to the preliminary purchase allocation in connection with the NEG acquisition in November 2006. The Company has assigned all of the NEG goodwill to the Exploration and Production segment.


6.	Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement ~~obligations~~obligation for the period offrom December 31, ~~2006~~2007 to ~~September 30, 2007~~March 31, 2008 is as follows (in thousands):


Asset retirement obligation, December 31, 2006	$	45,216
Asset retirement obligation, December 31, 2007				$	58,580
Liability incurred upon acquiring and drilling wells		1,688			1,730
Revisions in estimated cash flows		7,747			—
Liability settled in current period		(9	)		—
Accretion of discount expense		2,866			1,320

Asset retirement obligation, September 30, 2007	$	57,508
Asset retirement obligation, March 31, 2008					61,630
Less: Current portion					882

Asset retirement obligation, net of current				$	60,748


7.6.	Long-Term Debt

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


	September 30,		December 31,		March 31,		December 31,
	2007		2006		2008		2007

Senior term loans					$	1,000,000	$	1,000,000
Senior credit facility	$	400,000	$	140,000		215,000		—
Senior bridge facility		—		850,000
Senior term loan		1,000,000		—
Other notes payable:
Drilling rig fleet and related oil field services equipment		51,261		61,105		44,347		47,836
Sagebrush		—		4,000
Insurance financing		199		7,240
Mortgage						19,450		19,651
Other equipment and vehicles		44		4,486		135		162

Total debt		1,451,504		1,066,831		1,278,932		1,067,649
Less: Current maturities of long-term debt		14,293		26,201		15,662		15,350

Long-term debt	$	1,437,211	$	1,040,630	$	1,263,270	$	1,052,299

~~Senior Credit Facility.~~ ~~On November 21, 2006, the Company entered into a $750 million senior secured revolving credit facility (the “senior credit facility”). The senior credit facility matures on November 21, 2011.~~

The proceeds of the senior credit 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. Future borrowings under the senior credit~~

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~

facility will be available for capital expenditures, working capital and general corporate purposes and to finance permitted acquisitions of oil and gas properties and other assets related to the exploration, production and development of oil and gas properties. The senior credit facility will be available to be drawn on and repaid without restriction so long as the Company is in compliance with its terms, including certain financial covenants.

The senior credit facility contains various covenants that limit the 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 Company and certain of its subsidiaries’ ability to incur additional indebtedness with certain exceptions, including under the senior unsecured bridge facility (as discussed below) which was repaid in full during March 2007.

The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the ratio of (i) total funded debt to EBITDAX (as defined in the senior credit facility), (ii) EBITDAX to interest expense plus current maturities of long-term debt, and (iii) current ratio. The Company was in compliance with these financial covenants as of September 30, 2007.

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 assets and the assets of its guarantor subsidiaries, including proven oil and gas reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of proven oil and gas reserves reviewed in determining the borrowing base for the senior credit facility. Additionally, the obligations under the senior credit facility will be guaranteed by certain Company subsidiaries.

At the Company’s election, interest under the senior credit facility is determined by reference to (i) the British Bankers Association LIBOR rate, or 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 will be 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 will be paid at the end of each three-month period. The average interest rates paid on amounts outstanding under our senior credit facility for the three and nine month periods ended September 30, 2007 were 7.08% and 7.62%, respectively.

The borrowing base of proved reserves was initially set at $300.0 million. As of December 31, 2006, the Company had $140.0 million of outstanding indebtedness on the senior credit facility. Proceeds from the Company’s sale of common stock on March 20, 2007, as described in Note 14, were used to repay outstanding borrowings under the Company’s senior credit facility.

The borrowing base was increased to $400 million on May 2, 2007, and to $700 million on September 14, 2007. At September 30, 2007, the Company had $400 million in outstanding indebtedness under this facility. The Company repaid all amounts outstanding under this facility subsequent to September 30, 2007. See Note 17 for further discussion.

~~Senior Bridge Facility.~~ On November 21, 2006, the Company also entered into an $850.0 million senior unsecured bridge facility (the “senior bridge facility”), which 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.

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 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.~~

Senior Term Loans. On March 22, 2007, the Company ~~entered into~~issued $1.0 billion inof senior unsecured term loans (the “senior term loans”). The closing of the senior term loans was generally contingent upon closing the private

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~

placement of common equity as described in Note ~~14.~~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 ~~British Bankers Association~~ LIBOR rate plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a ~~Bank’s~~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 ~~rates~~rate paid on amounts outstanding under ~~our~~the Company’s variable term loans for the three ~~and nine~~ month ~~periods~~period ended ~~September 30, 2007 were 8.99% and 8.98%, respectively.~~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.

After March 22, 2008, the Company is required to offer to exchange the senior term loans for senior unsecured notes with registration rights and with identical terms and conditions as the term loans. If the Company is unable or does not offer to exchange the senior term loans for senior unsecured notes with registration rights by April 30, 2008, the interest rate on the senior term loans will increase by 0.25% every 90 days up to a maximum of 0.50%.

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.~~ merger.

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. ~~A portion~~

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 ~~term loans was~~bridge facility were used to ~~repay~~(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 ~~$850.0~~senior credit facility. Also, in 2007 the Company repaid a $4.0 million ~~senior bridge facility.~~loan incurred in 2005 for the purpose of completing a gas processing plant and pipeline in Colorado.

For the ~~nine~~three months ended ~~September 30,~~March 31, 2008 and 2007, interest payments, net of amounts capitalized, were approximately ~~$59.5~~$25.4 million ~~in 2007~~ and ~~$4.6~~$28.5 million, ~~in 2006.~~respectively.


8.7.	Other Long-Term Obligations

The Company has recorded a long-term obligation for amounts to be paid under a settlement agreement with Conoco, Inc. ~~(“Conoco”). During~~entered into in January ~~2007, the~~2007. The Company agreed to pay approximately $25.0 million plus interest, ~~to Conoco to settle outstanding litigation. Under this agreement, payments are to be made~~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 ~~September 30,~~March 31, 2008 and December 31, 2007. ~~Unpaid~~The unpaid settlement ~~amounts~~amount of approximately $15.0 million ~~and $20.0 million have~~has been included in other long-term obligations in the accompanying condensed consolidated balance sheets as of ~~September 30, 2007~~March 31, 2008 and December 31, ~~2006, respectively.~~2007.


9.8.	~~Derivatives~~Derivative Contracts

The Company has entered into various derivative contracts including collars, fixed price swaps, basis swaps and ~~basis~~interest rate swaps with counterparties. The contracts expire on various dates through December 31, ~~2009.~~

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~2011.

At ~~September 30, 2007,~~March 31, 2008, the Company’s open commodity derivative contracts consisted of the following:

Weighted Avg.

Period

Commodity

Notional

Fix Price

Fixed price swaps:

April 2007 — October 2007 Natural gas 4,280,000 MmBtu $ 7.02
April 2007 — October 2007 Natural gas 4,280,000 MmBtu $ 7.50
September 2007 — December 2007 Natural gas 1,220,000 MmBtu $ 8.88
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 7.60
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 7.82
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 8.00
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 8.04
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 8.77
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 9.04
November 2007 — June 2008 Natural gas 4,860,000 MmBtu $ 8.05
November 2007 — June 2008 Natural gas 9,720,000 MmBtu $ 8.20
November 2007 — March 2008 Natural gas 1,520,000 MmBtu $ 8.51
January 2008 — June 2008 Natural gas 3,640,000 MmBtu $ 7.99
January 2008 — June 2008 Natural gas 3,640,000 MmBtu $ 7.99
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ 8.23
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ 8.48
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ 9.00
May 2008 — August 2008 Natural gas 2,460,000 MmBtu $ 8.38
July 2008 — September 2008 Natural gas 920,000 MmBtu $ 8.23
July 2008 — December 2008 Natural gas 1,840,000 MmBtu $ 8.31
Collars:

January 2007 — December 2007 Crude oil 60,000 Bbls $ 50.00 − $84.50
January 2008 — June 2008 Crude oil 42,000 Bbls $ 50.00 − $83.35
July 2008 — December 2008 Crude oil 54,000 Bbls $ 50.00 − $82.60
Waha basis swaps:

January 2007 — December 2007 Natural gas 7,300,000 MmBtu $ (0.5925 )
January 2007 — December 2007 Natural gas 14,600,000 MmBtu $ (0.70 )
April 2007 — October 2007 Natural gas 4,280,000 MmBtu $ (0.530 )
January 2008 — December 2008 Natural gas 10,980,000 MmBtu $ (0.57 )
January 2008 — December 2008 Natural gas 7,320,000 MmBtu $ (0.585 )
January 2008 — December 2008 Natural gas 7,320,000 MmBtu $ (0.59 )
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ (0.595 )
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ (0.625 )
January 2008 — December 2008 Natural gas 7,320,000 MmBtu $ (0.635 )
January 2008 — December 2008 Natural gas 7,320,000 MmBtu $ (0.6525 )
May 2008 — August 2008 Natural gas 2,460,000 MmBtu $ (0.45 )
January 2009 — December 2009 Natural gas 3,650,000 MmBtu $ (0.47 )
January 2009 — December 2009 Natural gas 3,650,000 MmBtu $ (0.49 )
January 2009 — December 2009 Natural gas 3,650,000 MmBtu $ (0.4975 )

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 and the~~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 ~~gain~~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 ~~and nine~~ month periods ended ~~September 30,~~March 31, 2008 and 2007 ~~and 2006~~ (in thousands):

Three Months Ended
Nine Months Ended

September 30, September 30,
2007 2006 2007 2006

Realized gain $ (19,969 ) $ (13,875 ) $ (19,176 ) $ (14,169 )
Unrealized loss (gain) (19,278 ) 8,571 (36,052 ) (2,007 )

Gain on derivative contracts $ (39,247 ) $ (5,304 ) $ (55,228 ) $ (16,176 )


	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.


~~10.~~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.

On January 1, 2007, the Company adopted the provisions of FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes.” The Company has determined that no uncertain tax positions exist where the Company would be required to make additional tax payments. As a result, the Company has not recorded any additional liabilities for any unrecognized tax benefits as of September 30, 2007. The Company and its subsidiaries file income tax returns in the U.S. federal and various state jurisdictions. Tax years 1994 to present remain open for the majority of taxing authorities. The Company’s accounting policy is to recognize penalties and interest related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for the payment of penalties and interest at September 30, 2007.

For the ~~nine~~three months ended ~~September 30,~~March 31, 2008 and 2007, income tax payments were approximately ~~$2.7~~$0.2 million ~~in 2007~~ and ~~$1.9~~$0.4 million, ~~in 2006.~~respectively.


~~11.~~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 ~~year,~~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 ~~and nine~~ month periods ended ~~September 30,~~March 31, 2008 and 2007 ~~and 2006~~ (in thousands):


	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
	2007		2006		2007		2006		2008		2007

Weighted average basic common shares outstanding		107,554		71,870		102,562		71,692		141,044		92,442
Effect of dilutive securities:
Restricted stock		1,495		936		1,216		941		—		—

Weighted average diluted common and potential common shares outstanding		109,049		72,806		103,778		72,633		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.~~method with respect to its outstanding redeemable convertible preferred stock. Under this method, the Company assumes the conversion of the ~~outstanding redeemable convertible~~ 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

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~

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 ~~income available~~loss applicable to common stockholders.


~~12.~~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 ~~other than those specifically identified below,~~ which, individually or in the aggregate, could have a material effect on the financial condition, operationsand/or cash flows of the Company.

~~Roosevelt Litigation.~~ On May 18, 2004, the Company commenced a civil action seeking declaratory judgment against Elliot Roosevelt, Jr., E.R. Family Limited Partnership and Ceres Resource Partners, L.P. in the District Court of Dallas County, Texas, 101st Judicial District, SandRidge Energy, Inc. and Riata Energy Piceance, LLC v. Elliot Roosevelt, Jr. et al, Cause~~No. 92.717-C.~~ This suit sought a declaratory judgment relating to the rights of the parties in and to certain leases in a defined area of mutual interest in the Piceance Basin pursuant to an acquisition agreement entered into in 1989, including the Company’s 41,454 gross (16,193 net) acreage position. The Company tried the case to a jury in July 2006. Before the case was submitted to the jury, the trial court granted Roosevelt a directed verdict stating that he owned a 25% deferred interest in the Company’s acreage after project payout. The directed verdict is not likely to affect the Company’s proved reserves of 11.7 Bcfe, because of the requirement that project payout be achieved before the deferred interest shares in revenue. Other issues of fact were submitted to the jury. The trial court recently entered a judgment favorable to Roosevelt. The Company has filed a motion to modify the judgment and for a new trial. Depending on the outcome of this motion, the Company expects to appeal, at a minimum, from the entry of the directed verdict. If the Company does not ultimately prevail, the deferred interest will reduce the Company’s economic returns from the project, if project payout is achieved.

The Company is subject to other claims in the ordinary course of business. However, the Company believes that the ultimate resolution of the above mentioned claims and other current legal proceedings will not have a material adverse effect on its results of operations, financial condition, or cash flows.


~~13.~~12.	Redeemable Convertible Preferred Stock

In November 2006, the Company sold 2,136,667 shares of redeemable convertible preferred stock ~~as part~~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 iswas $210 per share as of ~~September 30,~~March 31, 2008 and December 31, 2007. Each share of convertible preferred stock iswas initially convertible into ten (10.2 currently) shares of common stock at the option of the holder, subject to certain anti-dilution adjustments.

~~On January 31, 2007, the Company’s Board~~ A summary of ~~Directors~~dividends declared ~~a dividend~~and paid on the ~~outstanding shares of~~ redeemable convertible preferred ~~stock. The dividend of $3.21~~stock is as follows (in thousands except per share ~~was~~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 ~~cash on February 15, 2007. The dividend covered~~ the ~~time period from November 21, 2006, when~~Company’s earnings per share calculations for the ~~shares were issued, through February 1, 2007.~~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.

~~On May 8, 2007,~~During March 2008, holders of 339,823 shares of the Company’s ~~Board~~redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of ~~Directors declared~~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 ~~dividend on~~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. The dividend of $3.97 per share was paid in cash on May 15, 2007. The dividend covered~~stock at the ~~time period from February 2, 2007 through May 1, 2007.~~

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~

On June 8, 2007, the Company’s Board of Directors declared a dividend on the outstanding shares of redeemable convertible preferred stock. The dividend of $4.10 per share was paid in cash on August 15, 2007. The dividend covered the time period from May 2, 2007 through August 1, 2007.

On September 24, 2007, the Company’s Board of Directors declared a dividend on the outstanding shares of redeemable convertible preferred stock. The dividend of $4.10 per share was paid in cash on November 15, 2007. The dividend covers the time period from August 2, 2007 to November 1, 2007.

~~Approximately $9.0 million and $29.5 million in paid and unpaid dividends~~then conversion rate if certain conditions have been included in the Company’s earnings per share calculations for the three and nine month periods ended September 30, 2007, respectively, as presented in the accompanying condensed consolidated statements of operations.met. See Note 15.


~~14.~~13.	Stockholders’ Equity

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


	September 30,		December 31,		March 31,		December 31,
	2007		2006		2008		2007

Shares authorized		400,000		400,000		400,000		400,000
Shares outstanding at end of period		107,820		91,604		146,206		140,391
Shares held in treasury		1,452		1,444		1,310		1,456

The Company is authorized to issue 50,000,000 shares of preferred stock, no$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 ~~were~~ outstanding as of ~~September 30, 2007~~March 31, 2008 and December 31, ~~2006.~~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 ~~of the Board of Directors~~ 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 ~~41,095~~approximately 38,000 and 37,000 shares at a total value of $1.3 million and $0.7 million during the ~~nine~~three month ~~period~~periods ended ~~September 30, 2007.~~March 31, 2008 and 2007, respectively. These shares were accounted for as treasury stock.

~~On June 28, 2007,~~During the Company purchased 39,844 shares of its common stock into treasury through an open market repurchase program in order to fund a portion of its 401(K) matching obligation as described below. Cash consideration for these shares of approximately $0.8 million was paid in July 2007.

~~On June 29, 2007,~~first quarter 2008, the Company transferred ~~72,044~~184,484 shares of its treasury stock tointo an account established for the benefit of the Company’s ~~401k Plan brokerage account.~~401(k) Plan. The transfer was made in order to satisfy the Company’s ~~$1.3~~$5.0 million accrued payable to match employee contributions made to the plan during ~~2006.~~2007. Historical cost of the shares transferred totaled approximately ~~$0.9~~$2.4 million, resulting in an increase to the Company’s additional paid-in capital of approximately ~~$0.4~~$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 ~~vest over~~had vesting periods of one, four or seven years. All awards issued during and after 2006 have four year vesting periods. ~~These shares~~Shares of restricted common stock are subject to restriction on transfer and certain conditions to vesting.

For the three months ended ~~September 30,~~March 31, 2008 and 2007, the Company recognized stock-based compensation expense related to restricted stock of ~~$2.7~~$3.2 million ~~in 2007~~ and ~~$3.7~~$1.1 million, ~~in 2006. For the nine months ended September 30, the Company recognized stock-based compensation expense related to restricted stock of approximately $5.0 million in 2007 and $8.2 million in 2006.~~respectively. Stock-based compensation expense is reflected in general and administrative expense in the condensed consolidated statements of operations.

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~


~~15.~~14.	Related Party Transactions

~~During~~In the ordinary course of business, the Company ~~has~~engages in transactions with certain shareholders and other related parties. These transactions primarily consist of purchases of drilling equipment and sales of ~~oilfield~~oil field service supplies. Following is a summary of significant transactions with such related parties for the three ~~and nine~~ month periods ended ~~September 30,~~March 31, 2008 and 2007 ~~and 2006~~ (in thousands):


	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
	2007		2006		2007		2006		2008		2007

Sales to and reimbursements from related parties	$	27,355	$	4,449	$	72,434	$	12,070	$	25,356	$	2,319

Purchases of services from related parties	$	32,093	$	1,394	$	42,544	$	3,656	$	19,890	$	6,785

~~On June 1, 2006, the~~The Company ~~purchased certain producing well interest~~leases office space in Oklahoma City from ~~an executive officer and director. The purchase price was approximately $9.0 million in cash. The cash consideration was paid in July 2006.~~

~~In August 2006, the Company sold various non-energy related assets to the Company’s former President and Chief Operating Officer, N. Malone Mitchell, 3~~^rd, for approximately $6.1 million in cash. The sale transaction resulted in a $0.8 million gain recognized in earnings by the Company in August 2006. The gain is included in gain on sale of assets in the condensed consolidated statements of operations.

~~In September 2006, the Company entered into a facilities lease with~~ a member of its Board of Directors. The Company believes that the payments ~~to be~~ made under this lease are at fair market rates. Rent expense related to the lease totaled ~~$1.7~~$0.4 million and ~~$0.1~~$0.3 million for the ~~nine~~three month periods ended ~~September 30,~~March 31, 2008 and 2007, ~~and 2006,~~ respectively. The lease ~~extends to~~expires in August 2009.

~~On May 2, 2007, the Company purchased certain leasehold acreage from a partnership controlled by a director. The purchase price was approximately $8.3 million in cash.~~

~~On June 11, 2007, the Company purchased certain producing well interests from a director. The purchase price was approximately $3.5 million in cash.~~

Larclay, L.P. ~~Larclay is a joint venture between the~~The Company and Clayton Williams Energy, Inc. (“CWEI”) ~~and was~~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 purchased its investment in 2006 and accounts for it under the equity method of accounting.~~ The Company serves as the operations manager of the ~~joint venture.~~partnership. Under the partnership agreement, CWEI iswas responsible for rig financing and ~~purchasing of the rigs.~~purchasing. The Company had sales to and cost reimbursements from Larclay for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2008 and 2007 of ~~$20.0~~$10.9 million and ~~$48.9 million, respectively. The Company had sales to and cost reimbursements from Larclay for the three and nine months ended September 30, 2006 of $0.7 million and $0.8~~$2.3 million, respectively. As of ~~September 30, 2007~~March 31, 2008 and December 31, ~~2006,~~2007, the Company had accounts receivable — related party due from Larclay of ~~$16.0~~$18.3 million and ~~$3.0~~$16.6 million, respectively. Additionally, the Company ~~had purchases from~~contracted with Larclay to utilize rigs for drilling. For the three month periods ended March 31, 2008 and ~~nine months ended September 30,~~ 2007, ~~of $10.0~~the Company was billed $10.7 million and ~~$25.6~~$6.8 million, ~~respectively.~~respectively, for these services. As of ~~September 30,~~March 31, 2008 and December 31, 2007, the Company had accounts payable — related party due to Larclay of ~~$2.2~~$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 ~~made no purchases~~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 ~~Larclay~~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 ~~2006.~~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~~exploration and ~~Production, Drilling~~production, drilling and ~~Oilfield Services, Midstream Gas Services,~~oil field services, midstream gas services, and ~~Other representing its~~other. These segments represent the Company’s four main business units, each offering different products and services. The ~~Exploration~~exploration and ~~Production~~production segment is engaged in the development, acquisition and production of crude oil and natural gas properties. The ~~Drilling~~drilling and ~~Oilfield Services~~oil field services segment is engaged in the land contract drilling of crude oil and natural gas wells. The ~~Midstream Gas Services~~midstream gas services segment is engaged in the purchasing, gathering, processing and treating of

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~

natural gas. The ~~Other~~other segment ~~transports~~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 ~~SandRidge’s operating~~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 ~~our~~the Company’s segments is shown in the following table (in thousands):

Three Months Ended
Nine Months Ended

September 30, September 30,
2007 2006 2007 2006

Revenues:
Exploration and production $ 113,105 $ 20,942 $ 320,984 $ 50,704
Elimination of inter-segment revenue — (142 ) (574 ) (354 )

Exploration and production, net of inter-segment revenue 113,105 20,800 320,410 50,350

Drilling and oilfield services 70,728 55,795 188,887 154,295
Elimination of inter-segment revenue (53,957 ) (19,864 ) (131,888 ) (48,040 )

Drilling and oilfield services, net of inter-segment revenue 16,771 35,931 56,999 106,255

Midstream gas services 55,395 47,405 189,143 137,329
Elimination of inter-segment revenue (36,364 ) (18,081 ) (118,012 ) (46,115 )

Midstream gas services, net of inter-segment revenue 19,031 29,324 71,131 91,214

Other 7,209 3,652 19,780 15,578
Elimination of inter-segment revenue (2,468 ) (57 ) (6,545 ) (220 )

Other, net of inter-segment revenue 4,741 3,595 13,235 15,358

Total revenues $ 153,648 $ 89,650 $ 461,775 $ 263,177

Operating Income:
Exploration and production $ 61,843 $ 241 $ 138,306 $ 8,203
Drilling and oilfield services 5,376 10,153 14,252 27,178
Midstream gas services 3,657 1,361 5,958 3,138
Other (11,160 ) (3,179 ) (20,172 ) (8,778 )

Total operating income 59,716 8,576 138,344 29,741
Interest income 575 51 4,201 448
Interest expense (28,522 ) (2,506 ) (88,630 ) (4,090 )
Other income (expense) 1,071 555 3,078 (241 )

Income before income tax expense $ 32,840 $ 6,676 $ 56,993 $ 25,858

Capital Expenditures:
Exploration and production $ 329,430 $ 37,127 $ 706,550 $ 88,861
Drilling and oilfield services 20,883 4,709 104,796 53,832
Midstream gas services 22,297 17,387 45,427 25,406
Other 30,406 7,508 38,387 13,132

Total capital expenditures $ 403,016 $ 66,731 $ 895,160 $ 181,231

Depreciation, Depletion and Amortization:
Exploration and production $ 45,643 $ 6,680 $ 117,329 $ 14,902
Drilling and oilfield services 10,092 5,206 25,962 14,070
Midstream gas services 1,688 845 4,182 2,238
Other 2,036 1,631 4,948 4,828

Total depreciation, depletion and amortization $ 59,459 $ 14,362 $ 152,421 $ 36,038


	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

1920

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)


	September 30,		December 31,		Three Months Ended
	2007		2006		March 31,
	2008		2007
Identifiable Asset(1):

Depreciation, Depletion and Amortization:
Exploration and production	$	2,712,621	$	2,091,459	$	65,590	$	33,211
Drilling and oilfield services		264,272		175,169
Drilling and oil field services						12,348		7,163
Midstream gas services		108,031		75,606		2,774		1,113
Other		85,532		46,150		2,329		1,357

Total	$	3,170,456	$	2,388,384
Total depreciation, depletion and amortization					$	83,041	$	42,844


	March 31,		December 31,
	2008		2007

Identifiable Assets(1):
Exploration and production	$	3,364,879	$	3,143,137
Drilling and oil field services		272,374		271,563
Midstream gas services		169,578		127,822
Other		101,001		88,044

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


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


~~17.~~	~~Subsequent Events~~

~~Acquisitions.~~ On October 9, 2007, the Company purchased developed and undeveloped properties located in West Texas from an oil and gas company. The purchase price was approximately $74 million, comprised of $25 million in cash and a $49 million note payable. The $25 million cash consideration paid was funded through a draw on the Company’s senior credit facility. All principal and accrued interest (interest at 7% annually) due on the note payable were repaid on November 9, 2007 with proceeds from the Company’s initial public offering.

~~On November 28, 2007, the Company purchased a gas treatment plant and related gathering system located in Pecos County, Texas. The purchase price of approximately $10.0 million was paid in cash.~~

On November 29, 2007, the Company purchased leasehold acreage and producing well interests located predominately in the WTO from a group of entities. The purchase price of approximately $32.0 million was paid in cash.

~~Litigation Settlement.~~ On October 29, 2007, the Company entered into an agreement whereby it settled outstanding litigation related to certain property purchased by the Company during July 2007. Under the terms of the agreement, the Company paid $4.5 million to the counterparties on November 15, 2007 and the litigation was dismissed. The amount paid has been included in accounts payable and accrued expenses in the accompanying condensed consolidated balance sheet as of September 30, 2007.

~~Note Payable.~~ On November 15, 2007, the Company entered into a note payable in the amount of $20 million with a lending institution as a mortgage on the downtown Oklahoma City property purchased by the Company during July 2007 (see additional discussion in Note 4). 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 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 the next twelve months, the Company expects to make payments of principal and interest on this note totaling $1.0 million and $1.1 million, respectively.

~~Initial Public Offering.~~ On November 9, 2007, the Company completed an initial public offering (the “IPO”) of its common stock. The Company sold 28,700,000 shares of SandRidge common stock, including 4,170,000 shares sold directly to an entity controlled by Tom L. Ward. The shares were sold at a price of $26 per share. After deducting underwriting discounts of approximately $38.3 million and estimated offering expenses of approximately $2.5 million, the Company received net proceeds of approximately $705.4 million. This transaction priced after market close on November 5, 2007. In conjunction with the IPO, the underwriters were granted an option to purchase 3,679,500 additional shares of the Company’s common stock. The underwriters fully exercised this option and purchased the additional shares on November 6, 2007. After deducting underwriting discounts of approximately $5.7 million, the Company received net proceeds of approximately $89.9 million from

~~SandRidge Energy, Inc. and Subsidiaries~~

~~Notes to Condensed Consolidated Financial Statements — (Continued)~~

these additional shares. This offering generated total gross proceeds to the Company of $841.8 million and total net proceeds of approximately $795.3 million to us after deducting total underwriting discounts of approximately $44.0 million and other offering expenses estimated to be approximately $2.5 million. The aggregate net proceeds of approximately $795.3 million received by the Company at closing on November 9, 2007 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 future capital expenditures 230.3

Total $ 795.3


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

Introduction

The following discussion and analysis is intended to ~~assist you in understanding~~help the reader understand our business, ~~and the~~financial condition, results of operations, ~~together with our present financial condition.~~liquidity and capital resources. This ~~section~~discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the accompanying notes included in this ~~Quarterly Report,~~report, as well as our ~~historical~~audited consolidated financial statements and the accompanying notes included in ~~registration statement~~our annual report onForm ~~S-1/A~~10-K ~~filed with the Securities and Exchange Commission on October 23, 2007. Our operating results~~ for the ~~periods~~year ended December 31, 2007 (the “2007Form 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 2007Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not be indicative of future performance. Statements concerning future results are forward-looking statements. In the text below, financial statement numbers have been rounded; however, the percentage changes are based on amounts that have not been rounded.occur.

The financial information with respect to the three ~~and nine~~ month periods ended ~~September 30,~~March 31, 2008 and March 31, 2007 ~~and 2006~~ that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring accruals, necessary ~~for a fair presentation of~~to state fairly the ~~results for such periods.~~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 that~~1986. The WTO includes the Piñon Field ~~and our~~as well as the Allison Ranch, South Sabino, ~~and~~Thistle, Big Canyon, ~~Prospects.~~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 ~~or NEG,~~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. ~~The~~In addition to the NEG acquisition, ~~coupled with~~we have completed numerous acquisitions of additional working interests ~~completed~~in the WTO during ~~2007, 2006 and~~the period from late 2005 ~~have significantly increased our holdings in the WTO.~~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 ~~Coast region.~~of Mexico.

During November 2007, we completed anthe initial public offering of our common ~~stock, a portion of~~stock. We used the proceeds from ~~which were used~~this offering to repay indebtedness outstanding under our senior credit facility as well as a note payable ~~outstanding~~ related to a ~~recent acquisition.~~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 1713 to the condensed consolidated financial statements contained in Part I, Item I1 of this ~~Quarterly Report.~~report.

Segment Overview

~~Operating~~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 ~~computed~~defined as segment operating revenue less ~~direct~~ operating ~~costs.~~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 ~~current~~business segments.


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2007			2006			2007			2006			2008			2007
	(In thousands)

Segment revenue:
Segment income and expense (in thousands):
Revenue:
Exploration and production	$	113,105		$	20,800		$	320,410		$	50,350		$	206,922		$	90,826
Drilling and oil field services		16,771			35,931			56,999			106,255			12,322			27,895
Midstream gas services		19,031			29,324			71,131			91,214			45,087			26,187
Other		4,741			3,595			13,235			15,358			4,755			4,156

Total revenues		153,648			89,650			461,775			263,177			269,086			149,064
Segment operating income:
Operating (loss) income:
Exploration and production		61,843			241			138,306			8,203			(47,389	)		371
Drilling and oil field services		5,376			10,153			14,252			27,178			(2,148	)		5,202
Midstream gas services		3,657			1,361			5,958			3,138			32			1,350
Other		(11,160	)		(3,179	)		(20,172	)		(8,778	)		(13,306	)		(3,455	)

Total operating income		59,716			8,576			138,344			29,741
Total operating (loss) income														(62,811	)		3,468
Interest income		575			51			4,201			448			796			1,088
Interest expense		(28,522	)		(2,506	)		(88,630	)		(4,090	)		(25,172	)		(35,429	)
Other income (expense)		1,071			555			3,078			(241	)
Other income														24			879

Income before income taxes	$	32,840		$	6,676		$	56,993		$	25,858
Loss before income taxes													$	(87,163	)	$	(29,994	)

Production data:
Gas (Mmcf)		12,856			2,637			35,148			6,856
Oil (MBbls)		535			24			1,441			70
Natural gas (Mmcf)														19,173			10,449
Crude oil (MBbls)														611			393
Combined equivalent volumes (Mmcfe)		16,067			2,780			43,793			7,275			22,839			12,807
Daily combined equivalent volumes (Mmcfe/d)		174.6			30.2			160.4			26.6
Average daily combined equivalent volumes (Mmcfe/d)														251.0			142.3
Average prices — as reported(1):
Natural gas (per Mcf)	$	5.99		$	6.23		$	6.56		$	6.14		$	7.86		$	6.60
Oil (per Bbl)	$	67.57		$	59.76		$	61.67		$	61.89
Crude oil (per Bbl)(3)													$	89.81		$	54.06
Combined equivalent (per Mcfe)	$	7.04		$	6.42		$	7.30		$	6.38		$	9.00		$	7.04
Average prices — including impact of derivatives:
Average prices — including impact of derivative contract settlements:
Natural gas (per Mcf)	$	7.54		$	11.61		$	7.11		$	8.21		$	8.32		$	6.45
Oil (per Bbl)	$	67.57		$	59.76		$	61.67		$	61.89
Crude oil (per Bbl)(3)													$	87.42		$	54.06
Combined equivalent (per Mcfe)	$	8.28		$	11.52		$	7.73		$	8.33		$	9.32		$	6.92
Drilling and oil field services:
Number of operational drilling rigs owned at end of period		27.0	(3)		23.0			27.0	(3)		23.0			26.0			25.0
Average number of operational drilling rigs owned during the period		27.0	(3)		22.3			26.0	(3)		21.0			26.0			25.0
Average total revenue per rig per day(2)	$	17,771		$	17,121		$	17,302		$	17,089		$	17,500		$	16,600


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


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

(3)		~~Does not include five rigs being retrofitted as of September 30, 2007.~~Includes natural gas liquids.

~~We report the results of our operations in the following segments:~~

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 ~~instruments~~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 ~~service~~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 ~~85%~~93%, there are greater intercompany eliminations that affect the consolidated financial results of our drilling and oil field ~~service~~services and midstream gas services segments.

~~Exploration and Production Segment — Three months ended September 30, 2007 compared to the three months ended September 30, 2006~~

Exploration and production segment revenues increased to ~~$113.1~~$206.9 million in the three months ended ~~September 30, 2007~~March 31, 2008 from ~~$20.8~~$90.8 million in the three months ended ~~September 30, 2006,~~March 31, 2007, an increase of ~~443.8%~~127.8%, as a result of a ~~477.9%~~78.1% increase in combined production volumes and a ~~9.7%~~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 ~~September 30, 2007~~March 31, 2008 we increased natural gas production by ~~10.2~~8.8 Bcf to ~~12.9~~19.2 Bcf and increased crude oil production by ~~511~~218 MBbls to ~~535~~611 MBbls from the comparable period in ~~2006.~~2007. The total combined ~~13.3~~10.0 Bcfe increase in production was due primarily to ~~acquisitions~~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.~~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 ~~September 30, 2007 decreased 3.9%~~March 31, 2008 increased 19.1%, or ~~$0.24~~$1.26 per Mcf, to ~~$5.99~~$7.86 per Mcf from ~~$6.23~~$6.60 per Mcf in the comparable period in ~~2006.~~2007. The average price received for our crude oil production ~~however,~~ increased ~~13.1%~~66.1%, or ~~$7.81~~$35.75 per barrel, to ~~$67.57~~$89.81 per barrel during the three months ended ~~September 30, 2007~~March 31, 2008 from ~~$59.76~~$54.06 per barrel during the same period in ~~2006.~~2007. Including the impact of derivative contract settlements, the effective price received for natural gas for the three month period ended ~~September 30, 2007~~March 31, 2008 was ~~$7.54~~$8.32 per Mcf as compared to ~~$11.61~~$6.45 per Mcf during the same period in ~~2006.~~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 ~~derivatives~~derivative contracts had no impact on effective oil prices during the three months ended ~~September 30,~~March 31, 2007. During 2007 ~~or the comparable period in 2006. During late 2006~~ and continuing into ~~2007~~2008, we entered into derivatives contracts to mitigate the impact of commodity price fluctuations on our 2007, 2008 and ~~2008~~2009 production. Our ~~derivatives~~derivative contracts are not designated as accounting hedges and, as a result, gains or losses on ~~derivatives~~commodity derivative contracts are recorded as an operating expense. Internally, management views the settlement of such ~~derivatives~~derivative contracts as adjustments to the price received for natural gas and crude oil production to determine “effective prices.”

For the three months ended ~~September 30, 2007,~~March 31, 2008, we had ~~$61.8~~a $47.4 million in operating ~~income~~loss in our exploration and production segment, compared to ~~$0.2~~$0.4 million in operating income for the same period in ~~2006.~~2007. Our ~~$92.3~~$116.1 million increase in exploration and production revenues was offset by a ~~$20.7~~$12.2 million increase in production expenses, ~~and~~ a ~~$39.1~~$32.4 million increase in depreciation, depletion and amortization, or DD&A, due to the ~~step up~~increase in ~~basis~~production and a $136.8 million loss on ~~the NEG properties.~~our derivative contracts. The increase in production expenses was attributable to the ~~additional properties acquired~~increase in ~~the NEG acquisition~~number of operating wells we own and ~~operating expenses on~~an increase in our ~~new~~average working interest in those wells. During the three month period ended ~~September 30, 2007,~~March 31, 2008, the exploration and production segment reported a ~~$39.2~~$136.8 million net ~~gain~~loss on our ~~derivatives~~commodity derivative positions ($~~19.9~~7.3 million realized ~~gains~~gain and ~~$19.3~~$144.1 million unrealized ~~gains)~~loss) compared to a ~~$5.3~~$23.2 million ~~gain~~loss ($~~13.9~~1.5 million realized ~~gains~~loss and ~~$8.6~~$21.7 million unrealized ~~losses)~~loss) in the comparable period in ~~2006.~~2007. During 2007 and first quarter 2008, we selectively entered into natural gas and oil swaps and natural gas basis swaps ~~by capitalizing on what we perceived as spikes~~in order to mitigate the effects of fluctuations in prices received for our production. Given the long term nature of our investment in the ~~price~~WTO development program and the relatively high level of natural gas ~~or favorable basis differences between the NYMEX price~~prices compared to our budgeted prices, management believes it prudent to enter into natural gas and crude oil swaps and natural gas ~~prices at~~basis swaps for a portion of our ~~principal West Texas~~production. Unrealized gains or losses on derivative contracts represent

equipment and before intercompany eliminations was essentially unchanged from the comparable period in 2006. Our rig utilization rate was 92.6%, representing 314 stacked rig days in 2007. The decline in operating income was principally attributable to the increase in the number and working interest ownership in wells drilled for our own account.

~~Drilling and Oil Field Services Segment — Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006~~

Drilling and oil field services segment revenue decreased to $57.0 million in the nine month period ended September 30, 2007 from $106.3 million in the nine month period ended September 30, 2006. Operating income decreased to $14.3 million in the nine month period ended September 30, 2007 from $27.2 million in the same period in 2006. The decline in revenues and operating income is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and 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 NEG acquisition and other WTO property acquisitions, our average working interest has increased to approximately 85% in the wells we operate in the WTO, and the third party interest has declined to less than 20%. During the nine month period ended September 30, 2007, approximately 70% ($131.9 million) of the drilling and oil field service revenues were generated by work performed on our own account and eliminated in consolidation as compared to approximately 31% ($48.0 million) for the comparable period in 2006. The number of drilling rigs we owned increased 23.8% to an average of 26.0 rigs during the nine month period ended September 30, 2007 from an average of 21.0 rigs in the comparable period in 2006. The average daily rate we received per rig of approximately $17,000,$17,500, excluding revenues for related rental equipment and before intercompany eliminations, was ~~essentially unchanged~~slightly higher than the daily rate of $16,600 from the comparable period in ~~2006. Our rig utilization rate was 91.0%, representing 826 stacked rig days in~~ 2007. ~~The decline in operating income was principally attributable to the increase in the number and working interest ownership in wells drilled for our own account.~~

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~~wholly owned subsidiary, SandRidge Midstream, Inc. (formerly known as ROC ~~Gas.~~Gas Company, Inc.). Through our gas marketing subsidiary, Integra Energy LLC, ~~(“Integra Energy”),~~ we buy and sell natural gas produced from our operated wells as well as third-party operated ~~wells located on or near our gathering systems.~~wells. Gas marketing revenue is one of our largest revenue components; however, it is a very low margin business. ~~Substantially all of our marketing fees are billed on a per unit basis.~~ On a consolidated basis, natural gas purchases and other costs of sales ~~includes~~include the total value we receive from ~~third-parties~~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 ~~September 30, 2007~~March 31, 2008 was ~~$19.0~~$45.1 million compared to ~~$29.3~~$26.2 million in the comparable period of ~~2006. Midstream gas services revenue for the nine months ended September 30, 2007 was $71.1 million compared to $91.2 million in the comparable period in 2006.~~2007. The quarterly ~~and nine month decrease~~increase in midstream gas services revenues is attributable to larger third-party volumes transported and marketed through our gathering systems during the ~~increase~~three months ended March 31, 2008 as compared to the same period in ~~our working interest in the WTO as~~2007. We generally charge a ~~result~~flat fee per unit transported and charge a percentage of ~~the NEG and other acquisitions.~~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, ~~PetroSource.~~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’~~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 ~~September 30, 2007~~March 31, 2008 compared to the three months ended ~~September 30, 2006~~March 31, 2007

Revenue. Total revenue increased ~~71.4%~~80.5% to ~~$153.6~~$269.1 million for the three months ended ~~September 30, 2007~~March 31, 2008 from ~~$89.7~~$149.1 million in the same period in ~~2006.~~2007. This increase was due to a ~~$95.0~~$115.3 million increase in natural gas and crude oil ~~sales and was partially offset by lower revenues in our~~sales. Lower drilling and oil field services revenues partially offset the increases noted in midstream gas services and other segments.

Three Months Ended

September 30,
2007 2006 $ Change % Change
(In thousands)

Revenue:
Natural gas and crude oil $ 113,106 $ 18,150 $ 94,956 523.2 %
Drilling and services 16,684 35,742 (19,058 ) (53.3 )%
Midstream and marketing 19,030 29,326 (10,296 ) (35.1 )%
Other 4,828 6,432 (1,604 ) (24.9 )%

Total revenues $ 153,648 $ 89,650 $ 63,998 71.4 %


	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 ~~$95.0~~$115.3 million to ~~$113.1~~$205.5 million for the three months ended ~~September 30, 2007~~March 31, 2008 compared to ~~$18.2~~$90.2 million for the same period in ~~2006,~~2007, primarily as a result of an increase in natural gas and crude oil production ~~volumes.~~volumes and prices received for our production. Total natural gas production increased ~~387.5%~~83.5% to ~~12,856~~19,173 Mmcf in ~~2007~~2008 compared to ~~2,637~~10,449 Mmcf in ~~2006~~2007, while crude oil production increased ~~2,129.2%~~55.5% to ~~535~~611 MBbls in ~~2007~~2008 from 24393 MBbls in ~~2006. Of the 13,287 Mmcfe increase in total production, approximately 11,741 Mmcfe of the increase was attributable to the NEG acquisition.~~2007. The ~~remainder of the~~ increase was due to our successful drilling in the ~~WTO.~~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 ~~9.7%~~27.8% in the ~~2007~~2008 period to $9.00 per Mcfe compared to $7.04 per Mcfe ~~compared to $6.42 per Mcfe~~ in ~~2006, excluding the impact of derivative contracts.~~2007.

Drilling and services revenue decreased ~~53.3%~~55.8% to ~~$16.7~~$12.3 million for the three months ended ~~September 30, 2007~~March 31, 2008 compared to ~~$35.7~~$27.9 million in the same period in ~~2006.~~2007. The decline in revenues is ~~primarily attributable~~due to an increase in the number of company-owned rigs operating on ~~our properties and an increase in our ownership interest in our~~company-owned natural gas and crude oil properties and the increase in working interest in these properties. The number of rigs we owned increased to 27.0 (average for the three months ended September 30, 2007) in 2007 compared to 22.3 (average for the three months ended September 30, 2006) in 2006, an increase of 21.1%, andAdditionally, the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, ~~was essentially unchanged at $17,771~~increased to approximately $17,500 per ~~day.~~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 ~~decreased $10.3~~increased $20.2 million, or ~~35.1%~~77.2%, with revenues of ~~$19.0~~$46.4 million in the three month period ended ~~September 30, 2007~~March 31, 2008 as compared to ~~$29.3~~$26.2 million in the three month period ended ~~September 30, 2006. The NEG acquisition significantly decreased our midstream gas services revenues~~March 31, 2007. This increase is due primarily to larger production volumes transported and marketed, during the three months ended March 31, 2008 as ~~more gas was transported for our own account. Prior~~compared to the ~~acquisition, transportation, treating and processing of gas~~same period in 2007, for ~~NEG was recorded as midstream gas services revenue. We have~~ the ~~contractual right~~third parties with ownership in our wells or ownership in other wells connected to ~~periodically increase fees we receive for transportation and processing based on certain indexes.~~our gathering systems.

Other revenue ~~decreased~~increased to ~~$4.8~~$4.9 million for the three months ended ~~September 30, 2007~~March 31, 2008 from ~~$6.4~~$4.8 million for the same period in 2006. The decrease was primarily due to the effects of the sale of various non-energy related assets to our former President and Chief Operating Officer as described further in Note 15 to the condensed consolidated financial statements.. Revenues related to these assets are included in the 2006 period prior to their sale in August 2006.2007. Other revenue is generated primarily by our CO₂ gathering and sales operations.

Operating Costs and Expenses. Total operating costs and expenses increased to ~~$93.9~~$331.9 million for the three months ended ~~September 30, 2007~~March 31, 2008 compared to ~~$81.1~~$145.6 million for the same period in ~~2006~~2007 due to increases in ~~our~~ production-related costs, general and administrative expenses as ~~well as~~a result of an increase in corporate ~~staff.~~staff, depreciation, depletion and amortization and losses on derivative contracts. These increases were partially offset by a decrease in ~~costs~~expenses attributable to our drilling and ~~services and midstream and marketing operations as well as increased gains on derivative instruments.~~services.

Three Months Ended

September 30,
2007 2006 $ Change % Change
(In thousands)

Operating costs and expenses:
Production $ 28,689 $ 7,960 $ 20,729 260.4 %
Production taxes 4,402 1,050 3,352 319.2 %
Drilling and services 6,809 24,985 (18,176 ) (72.7 )%
Midstream and marketing 14,444 27,139 (12,695 ) (46.8 )%
Depreciation, depletion, and amortization — natural gas and crude oil 45,177 6,064 39,113 645.0 %
Depreciation, depletion and amortization — other 14,282 8,298 5,984 72.1 %
General and administrative 20,421 11,721 8,700 74.2 %
Gain on derivative instruments (39,247 ) (5,304 ) (33,943 ) (640.0 )%
Gain on sale of assets (1,045 ) (839 ) (206 ) (24.6 )%

Total operating costs and expenses $ 93,932 $ 81,074 $ 12,858 15.9 %


	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 ~~exploration and~~ production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased ~~$20.7~~$12.2 million primarily ~~due to a $20.0 million increase related to the addition of the NEG properties in 2007. The remainder of the increase was due to an increase in lease operating expenses~~ due to an increase in the number of wells in which we ~~operate.~~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 ~~$3.4~~$6.3 million, or ~~319.2%~~214.4%, to ~~$4.4~~$9.2 million primarily due to the ~~addition of~~increase in production and the ~~NEG properties in 2007.~~increased prices received for production during the three months ended March 31, 2008.

Drilling and services ~~and midstream and marketing~~ expenses decreased ~~72.7% and 46.8% respectively,~~61.8% for the three months ended ~~September 30, 2007~~March 31, 2008 as compared to the same period in ~~2006~~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 ~~$45.2~~$65.1 million for the three months ended ~~September 30, 2007~~March 31, 2008 from ~~$6.1~~$32.7 million in the same period in ~~2006.~~2007. Our DD&A per Mcfe increased ~~$0.63~~$0.30 to ~~$2.81~~$2.85 in the first quarter of 2008 from ~~$2.18~~$2.55 in the comparable period in ~~2006.~~2007. The increase is primarily attributable to ~~the NEG acquisition, which increased~~an increase in our depreciable properties, ~~by the purchase price plus~~higher future development costs and increased production. Our production increased ~~477.9%~~78.1% to ~~16.1~~22.8 Bcfe from ~~2.8~~12.8 Bcfe in ~~2006.~~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 ~~drilling and oil field services equipment~~other assets was ~~due~~attributable primarily to ~~the increase in the number~~higher carrying costs of our rigs ~~we own.~~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~~life.

General and administrative expenses increased ~~$8.7~~$8.5 million to ~~$20.4~~$21.0 million for the three months ended ~~September 30, 2007~~March 31, 2008 from ~~$11.7~~$12.5 million for the comparable period in ~~2006.~~2007. The increase was principally attributable to ~~a $10.2~~an $8.8 million increase in corporate salaries and wages due to a significant increase in corporate and support staff. As of ~~September 30, 2007,~~March 31, 2008, we had ~~2,205~~2,385 employees as compared to ~~1,319~~1,746 at ~~September 30, 2006.~~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 ~~increase~~increases in salaries and wages ~~was~~as well as stock compensation were partially offset by ~~a $1.0~~$3.2 million ~~decrease~~ in stock compensation expense. As part of a severance package for certain executive officers, the Board of Directors approved the acceleration of vesting of certain stock awards resulting in increased compensation expense recognized during the three month period ended September 30, 2006.capitalized general and administrative

2928

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 ~~September 30, 2007,~~March 31, 2008, we recorded a ~~gain~~loss of ~~$39.2~~$136.8 million ($~~19.3~~144.1 million unrealized ~~gain~~loss and ~~$19.9~~$7.3 million realized gain) on our ~~derivatives instruments~~derivative contracts compared to a ~~$5.3~~$23.2 million ~~gain~~loss ($~~8.6~~21.7 million unrealized loss and ~~$13.9~~$1.5 million realized ~~gain)~~loss) for the comparable period in ~~2006.~~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 ~~by capitalizing on what we perceived as spikes in the price~~for a portion of ~~natural gas or favorable basis differences between the NYMEX price and natural gas prices at~~ our ~~principal West Texas pricing point of Waha Hub.~~production. Unrealized gains or losses on ~~derivatives~~natural gas and crude oil derivative contracts represent the change in fair value of open ~~derivatives~~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.~~price for contracts entered into during the period. The unrealized ~~gain~~loss recorded in the three month period ended ~~September 30, 2007~~March 31, 2008 related to natural gas and crude oil commodities was attributable to ~~a decrease~~an increase in average natural gas and crude oil prices at ~~September 30, 2007~~March 31, 2008 as compared to the average natural gas and crude oil prices at December 31, 2007 or the ~~various~~ contract ~~dates.~~price for contracts entered into during the period.

Other Income (Expense). Total other expense ~~increased~~decreased to ~~$26.9~~$24.4 million in the three month period ended ~~September 30, 2007~~March 31, 2008 from ~~$1.9~~$33.5 million in the three month period ended ~~September 30, 2006.~~March 31, 2007. The ~~increase~~decrease is reflected in the table below.

Three Months Ended

September 30,
2007 2006 $ Change % Change
(In thousands)

Other income (expenses):
Interest income $ 575 $ 51 $ 524 1027.5 %
Interest expense (28,522 ) (2,506 ) (26,016 ) (1038.1 )%
Minority interest (164 ) (182 ) 18 9.9 %
Income (loss) from equity investments 1,235 737 498 67.6 %

Total other expense (26,876 ) (1,900 ) (24,976 ) (1314.5 )%

Income before income taxes 32,840 6,676 26,164 391.9 %
Income tax expense 11,920 1,781 10,139 569.3 %

Net income $ 20,920 $ 4,895 $ 16,025 327.4 %


	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 ~~increased~~decreased to ~~$0.6~~$0.8 million for the three months ended ~~September 30, 2007~~March 31, 2008 from ~~$0.1~~$1.1 million for the same period in ~~2006.~~2007. This ~~increase~~decrease was generally due to ~~interest income from the investment of~~lower excess cash ~~after~~levels during the ~~repayment of debt.~~three months ended March 31, 2008 as compared to the same period in 2007.

Interest expense ~~increased~~decreased to ~~$28.5~~$25.2 million for the three months ended ~~September 30, 2007~~March 31, 2008 from ~~$2.5~~$35.4 million for the same period in ~~2006.~~2007. This ~~increase~~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. To finance~~balances outstanding during that period as compared to the NEG acquisition, we entered into a $750 million senior credit facility, which has an initial borrowing base of $300 million, and an $850 million senior bridge facility. In March 2007, we entered into a $1.0 billion term loan and sold 17.8 million shares of common stocksame period in a private placement. A portion of the proceeds from the senior unsecured term loan were used to repay the bridge loan. The balance of proceeds were used to fund current year capital expenditures. Please read “— Liquidity and Capital Resources.”2007.

During the three months ended ~~September 30, 2007,~~March 31, 2008, we reported income from equity investments of ~~$1.2~~$0.9 million as compared to ~~$0.7~~$1.0 million in the comparable period in ~~2006. This increase was attributable to income from Larclay as all of Larclay’s rigs have now been delivered and all but one is operational.~~2007.

We reported an income tax ~~expense~~benefit of ~~$11.9~~$30.5 million for the three months ended ~~September 30, 2007,~~March 31, 2008, as compared to ~~an expense~~a benefit of ~~$1.8~~$10.5 million for the same period in ~~2006.~~2007. The current period income tax ~~expense~~benefit represents an effective income tax rate of ~~36.3% as compared to 26.7% in~~35% which is unchanged from the ~~comparable~~same period in ~~2006. The lower effective income tax rate in 2006 was attributable to favorable percentage depletion deductions during that period.~~2007.

3029

~~Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006~~

~~Revenue.~~ Total revenue increased 75.5% to $461.8 million for the nine months ended September 30, 2007 from $263.2 million in the same period in 2006. This increase was due to a $273.1 million increase in natural gas and oil sales and was partially offset by lower revenues in our other segments.

Nine Months Ended

September 30,
2007 2006 $ Change % Change
(In thousands)

Revenue:
Natural gas and crude oil $ 319,556 $ 46,419 $ 273,137 588.4 %
Drilling and services 56,928 105,713 (48,785 ) (46.1 )%
Midstream and marketing 71,131 91,218 (20,087 ) (22.0 )%
Other 14,160 19,827 (5,667 ) (28.6 )%

Total revenues $ 461,775 $ 263,177 $ 198,598 75.5 %

Total natural gas and crude oil revenues increased $273.1 million to $319.5 million for the nine months ended September 30, 2007, compared to $46.4 million for the same period in 2006, primarily as a result of an increase in natural gas and crude oil production volumes. Total natural gas production increased 412.7% to 35,148 Mmcf in 2007 compared to 6,856 Mmcf in 2006, while crude oil production increased 1,958.6% to 1,441 MBbls in 2007 from 70 MBbls in 2006. Approximately 32,964 Mmcfe of the 36,518 Mmcfe increase in production was attributable to the NEG acquisition. Average price received for our natural gas and crude oil production increased 14.4% in the 2007 period to $7.30 per Mcfe compared to $6.38 per Mcfe in 2006, excluding the impact of derivative contracts.

Drilling and services revenue decreased 46.1% to $56.9 million for the nine months ended September 30, 2007, compared to $105.7 million in the same period in 2006. The decline in revenues is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties as a result of the NEG acquisition. The number of rigs we owned increased to 26.0 (average for the nine months ended September 30, 2007) in 2007 compared to 21.0 (average for the nine months ended September 30, 2006) in 2006, an increase of 23.8%, and the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, was essentially unchanged at $17,302 per day.

Midstream and marketing revenue decreased $20.1 million, or 22.0%, with revenues of $71.1 million in the nine month period ended September 30, 2007, as compared to $91.2 million in the nine month period ended September 30, 2006. The NEG acquisition significantly decreased our midstream gas services revenues as more gas was transported for our own account. Prior to the acquisition, transportation, treating and processing of gas for NEG was recorded as midstream gas services revenue. We have the contractual right to periodically increase fees we receive for transportation and processing based on certain indexes.

Other revenue decreased to $14.2 million for the nine months ended September 30, 2007 from $19.8 million for the same period in 2006. The decrease was primarily due to the sale of various non-energy related assets to our former President and Chief Operating Officer. Revenues related to these assets are included in the 2006 period prior to their sale in August 2006. This decrease was slightly offset by an increase in revenues generated by the sale of CO₂~~. Other revenue is generated primarily by our CO~~₂ ~~gathering and sales operations.~~

~~Operating Costs and Expenses.~~ Total operating costs and expenses increased to $323.4 million for the nine months ended September 30, 2007, compared to $233.4 million for the same period in 2006, primarily due to increases in our production-related costs as well as an increase in corporate staff. These increases were partially offset by decreases in costs attributable to our drilling and services and midstream and marketing operations as well as increased gains on derivative instruments.

Nine Months Ended

September 30,
2007 2006 $ Change % Change
(In thousands)

Operating costs and expenses:
Production $ 77,707 $ 21,625 $ 56,082 259.3 %
Production taxes 12,328 2,579 9,749 378.0 %
Drilling and services 30,935 72,670 (41,735 ) (57.4 )%
Midstream and marketing 61,191 85,525 (24,334 ) (28.5 )%
Depreciation, depletion, and amortization — natural gas and crude oil 115,876 13,932 101,944 731.7 %
Depreciation, depletion and amortization — other 36,545 22,106 14,439 65.3 %
General and administrative 45,781 32,024 13,757 43.0 %
Gain on derivative instruments (55,228 ) (16,176 ) (39,052 ) (241.4 )%
Gain on sale of assets (1,704 ) (849 ) (855 ) (100.7 )%

Total operating costs and expenses $ 323,431 $ 233,436 $ 89,995 38.6 %

Production expense includes the costs associated with our exploration and production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $56.1 million primarily due to a $53.6 million increase because of the addition of the NEG properties in 2007. The remainder of the increase was due to an increase in lease operating expenses due to an increase in the number of wells we operate. Production taxes increased $9.7 million, or 378.0%, to $12.3 million primarily due to the addition of the NEG properties in 2007.

Drilling and services and midstream and marketing expenses decreased 57.4% and 28.5% respectively, for the nine months ended September 30, 2007, as compared to the same period in 2006 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.

DD&A for our natural gas and crude oil properties increased to $115.9 million for the nine months ended September 30, 2007, from $13.9 million in the same period in 2006. Our DD&A per Mcfe increased $0.73 to $2.65 from $1.92 in the comparable period in 2006. The increase is primarily attributable to the NEG acquisition, which increased our depreciable properties by the purchase price plus future development costs and increased production. Our production increased 502.0% to 43.8 Bcfe from 7.3 Bcfe in 2006.

DD&A for our other assets consists primarily of depreciation of our drilling rigs and other equipment. The increase in DD&A for our drilling and oil field services equipment was due primarily to the increase in the number of rigs we own. 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 $13.8 million to $45.8 million for the nine months ended September 30, 2007, from $32.0 million for the comparable period in 2006. The increase was principally attributable to a $21.7 million increase in corporate salaries and wages which was due to a significant increase in corporate and support staff. As of September 30, 2007, we had 2,205 employees as compared to 1,319 at September 30, 2006. The increase in salaries and wages was partially offset by a $3.2 million decrease in stock compensation expense. As part of a severance package for certain executive officers, the Board of Directors

~~approved the acceleration of vesting of certain stock awards resulting in increased compensation expense recognized during the nine months ended September 30, 2006.~~

For the nine month period ended September 30, 2007, we recorded a gain of $55.2 million ($36.1 million unrealized gain and $19.1 million realized gain) on our derivatives instruments compared to a $16.2 million gain ($2.0 million unrealized gain and $14.2 million realized gain) for the comparable period in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas pricing point of Waha Hub. Unrealized gains or losses on derivatives contracts represent the change in fair value of open derivatives 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 gain recorded in the nine month period ended September 30, 2007 was attributable to a decrease in average natural gas prices at September 30, 2007 as compared to the average natural gas prices at the various contract dates.

~~Other Income (Expense).~~ Total other expense increased to $81.4 million in the nine month period ended September 30, 2007, from $3.9 million in the nine month period ended September 30, 2006. The increase is reflected in the table below.

Nine Months Ended

September 30,
2007 2006 $ Change % Change
(In thousands)

Other income (expense):
Interest income $ 4,201 $ 448 $ 3,753 837.7 %
Interest expense (88,630 ) (4,090 ) (84,540 ) (2067.0 )%
Minority interest (321 ) (281 ) (40 ) (14.2 )%
Income (loss) from equity investments 3,399 40 3,359 8397.5 %

Total other expense (81,351 ) (3,883 ) (77,468 ) (1995.1 )%

Income before income taxes 56,993 25,858 31,135 120.4 %
Income tax expense 21,002 6,931 14,071 203.0 %

Net income $ 35,991 $ 18,927 $ 17,064 90.2 %

Interest income increased to $4.2 million for the nine months ended September 30, 2007, from $0.4 million for the same period in 2006. This increase was due to interest income from investment of excess cash after the repayment of debt.

Interest expense increased to $88.6 million for the nine months ended September 30, 2007, from $4.1 million for the same period in 2006. This increase was attributable to increased average debt balances. To finance the NEG acquisition, we entered into a $750 million senior credit facility, which has an initial borrowing base of $300 million, and an $850 million senior bridge facility. In March 2007, we entered into a $1.0 billion term loan and sold 17.8 million shares of common stock in a private placement. A portion of the proceeds from the senior unsecured term loan was used to repay the bridge loan. Please read “— Liquidity and Capital Resources.”

During the nine months ended September 30, 2007, we reported income from equity investments of $3.4 million as compared to $40,000 in the comparable period in 2006. Approximately $1.6 million of the increase was attributable to income from our interest in the Grey Ranch processing plant which has experienced increased profitability due to higher levels of utilization during the nine months ended September 30, 2007 as compared to the same period in 2006. Approximately $1.8 million of the increase was attributable to income from Larclay as all of Larclay’s rigs have now been delivered and all but one rig are operational.

We reported an income tax expense of $21.0 million for the nine months ended September 30, 2007, as compared to an expense of $6.9 million for the same period in 2006. The current period income tax expense represents an effective income tax rate of 36.9% as compared to 26.8% in the comparable period in 2006. The lower effective income tax rate in 2006 was attributable to favorable percentage depletion deductions during that period.

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;~~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 ~~therefore;~~for these services; and the margins we obtain from our natural gas and CO₂ gathering and processing contracts.

~~During 2006 and the first quarter of~~On November 9, 2007, we ~~entered into various debt~~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 ~~equity transactions to fund the acquisition~~Chief Executive Officer, Tom L. Ward. After deducting underwriting discounts of ~~NEG~~approximately $44.0 million and ~~our 2007 capital expenditure program.~~ 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 ~~September 30, 2007,~~March 31, 2008, our cash and cash equivalents were ~~$32.0~~$0.7 million, and we had approximately ~~$300.0~~$462.3 million available under our senior credit facility. The significant cash balance at September 30, 2007 was the result of borrowings under our senior credit facility in anticipation of an acquisition that closed subsequent to quarter-end. On November 9, 2007, we repaid amountsAmounts outstanding under our senior credit facility ~~with a portion of the proceeds from our initial public offering. There are currently no amounts outstanding under our senior credit facility.~~at March 31, 2008 totaled $215.0 million. As of ~~September 30, 2007,~~March 31, 2008, we had ~~$1,452 million~~$1.3 billion in total debt outstanding.

~~Our~~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.

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, 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 ~~three~~WTO. Of our total $1.5 billion capital expenditure budget, approximately $1.2 billion is budgeted for exploration and ~~nine month periods ended September 30,~~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 our3-D seismic acquisition program that we commenced in 2007, ~~totaled $403.0~~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 ~~$895.2~~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 ~~respectively. Please see Note 16~~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 ~~condensed consolidated financial statements contained in Part I, Item I~~next twelve months. The majority of ~~this Quarterly Report for a breakdown~~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 ~~expenditures by segment.~~in the form of our revolving credit facility, potential asset sales or the incurrence of additional long-term debt.

Cash Flows ~~from Operations~~

Our cash flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2008 and 2007 ~~and 2006 are~~were as follows:


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
	2007			2006			2008			2007
	(In thousands)						(In thousands)

Cash flows provided by operating activities	$	239,556		$	67,500		$	156,689		$	43,963
Cash flows used in investing activities		(897,341	)		(223,256	)		(418,979	)		(182,546	)
Cash flows provided by financing activities		650,850			120,743			199,881			293,094

Net decrease in cash and cash equivalents	$	(6,935	)	$	(35,013	)
Net (decrease) increase in cash and cash equivalents							$	(62,409	)	$	154,511

Operating Activities. Net cash provided by operating activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2008 and 2007 ~~and 2006~~ were ~~$239.6~~$156.7 million and ~~$67.5~~$44.0 million, respectively. The increase in cash provided by operating activities from ~~2006~~2007 to ~~2007~~2008 was primarily due to our ~~502.0%~~78.1% increase in production volumes as a result of our drilling success

in the ~~NEG and various other acquisitions~~WTO as well as ~~our drilling success.~~various acquisitions throughout 2007 and the first three months of 2008. Also, contributing to this increase was a ~~241.4%~~27.8% increase in ~~realized~~the combined average prices we received for the natural gas and ~~unrealized gains on our derivative contracts.~~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 ~~$897.3~~$419.0 million in the ~~nine~~three month period ended ~~September 30, 2007~~March 31, 2008 from ~~$223.3~~$182.5 million in the ~~2006~~comparable 2007 period as we continued to ramp up our capital expenditure program. For the ~~nine~~three month period ended ~~September 30, 2007,~~March 31, 2008, our capital expenditures were ~~$706.6~~$354.8 million in our exploration and production segment, ~~$104.8~~$17.9 million for drilling and oil field services, ~~$45.4~~$38.7 million for midstream gas services and ~~$38.4~~$7.2 million for other capital expenditures. During the same period in ~~2006,~~2007, capital expenditures were ~~$88.9~~$127.6 million in our exploration and production segment, ~~$53.8~~$41.2 million for drilling and oil field services, ~~$25.4~~$9.5 million for midstream gas services and ~~$13.1~~$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 ~~increased~~decreased to ~~$1,262.8~~$340.2 million for the ~~nine~~three months ended ~~September 30, 2007,~~March 31, 2008, and we repaid approximately ~~$879.6~~$128.9 million leaving net borrowings during the period of approximately ~~$383.2~~$211.3 million. We also received net proceeds of approximately $318.7 million from a private placement of our common stock. We used the net proceeds from the term loan and the common stock issuance to repay the senior bridge facility and to repay all of our outstanding

~~borrowings under our senior credit facility.~~ Our financing activities provided ~~$650.9~~$199.9 million in cash for the ~~nine~~three month period ended ~~September 30, 2007~~March 31, 2008 compared to ~~$120.7~~$293.1 million in the comparable period in ~~2006.~~2007.

Credit Facilities and Other Indebtedness

Senior Credit Facility. On November 21, 2006, we entered into a new ~~$750~~$750.0 million senior secured revolving credit facility (the “senior credit facility”) with Bank of America, N.A., as Administrative ~~Agent and Banc of America Securities LLC as Lead Arranger and Book Running Manager.~~Agent. The senior credit facility matures on November 21, ~~2011.~~

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. Future borrowings under the senior credit facility will be available for capital expenditures, working capital and general corporate purposes and to finance permitted acquisitions of natural gas and oil properties and other assets related to the exploration, production and development of natural gas and oil properties. The senior credit facility will be available to be drawn on and repaid without restriction so long as we are in compliance with its terms, including certain financial covenants.

The senior credit facility 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 with certain exceptions, including under the senior unsecured bridge facility (as discussed below), which was repaid in full during March 2007.~~indebtedness.

The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for (i) the ratio of ~~(i) our~~ 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) ~~our~~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 ~~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,~~ and (iii) ~~our~~the current ratio, which must be at least 1.0:1.0. As of ~~the end of the third quarter 2007~~March 31, 2008, we were in compliance with ~~these financial covenants.~~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 ~~proven~~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 ~~proven~~proved natural gas and crude oil reserves reviewed in determining the borrowing base for the senior credit facility (as determined by the ~~Administrative Agent)~~administrative agent). Additionally, the obligations under the senior credit facility ~~will be~~are guaranteed by certain of our subsidiaries.

The borrowing base for the senior credit facility is determined by the administrative agent in its sole discretion in accordance with its normal and customary natural gas and oil lending practices and approved by lenders. The reaffirmation of an existing borrowing base amount or an increase in the borrowing base will require approval by Required Lenders (as defined in the senior credit facility). The borrowing base is subject to review semi-annually; however, ~~Required Lenders~~the lenders reserve the right to have ~~(a) one additional redetermination within the first twelve months from the closing date and (b)~~ one additional redetermination of the borrowing base per calendar ~~year thereafter.~~year. Unscheduled redeterminations may be made at our request, but are limited to ~~two such requests during the twelve months following the closing date and~~ one request per ~~twelve months thereafter.~~

year. The borrowing base ~~includes~~is determined based on proved developed

producing reserves, proved developed non-producing reserves and proved undeveloped reserves and was $700.0 million as of ~~September 2007.~~March 31, 2008. As of ~~September 30, 2007,~~March 31, 2008, we had outstanding indebtedness of ~~$400~~$237.7 million onunder our senior credit ~~facility. We repaid all~~facility, including outstanding ~~borrowings under this~~letters of credit of $22.7 million. The committed loan amount for the facility ~~on November 9, 2007,~~was increased to $1.75 billion and ~~there are currently no amounts~~the borrowing base was increased to $1.2 billion during April 2008. As of May 5, 2008, the balance outstanding under ~~the~~our senior credit ~~facility.~~facility was $410.0 million.

At our election, interest under the senior credit facility is determined by reference to (i) ~~the British Bankers Association LIBOR rate, or~~ 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 ~~will be~~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 ~~will be~~is paid at the end of each three-month period. The average interest ~~rates~~rate paid on amounts outstanding under our senior credit facility for the three ~~and nine~~ month ~~periods~~period ended ~~September 30, 2007 were 7.08% and 7.62%, respectively.~~March 31, 2008 was 4.57%.

If an event of default exists under the senior credit facility, the lenders may accelerate the maturity of the obligations outstanding under the senior credit facility and exercise other rights and remedies. Each of the following will be an event of default:


	•	~~failure to pay any principal when due or any interest, fees or other amount within certain grace periods;~~

	•	~~failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;~~

	•	~~bankruptcy or insolvency events involving us or our subsidiaries;~~

	•	~~a change of control (as defined in the senior credit facility).~~

~~March 2007~~Senior Term ~~Loan.~~Loans. On March 22, 2007, we ~~entered into a $1~~issued $1.0 billion principal amount of senior unsecured term ~~loan.~~loans. The proceeds of the term ~~loan~~loans were used to partially repay the senior bridge facility described below. The senior term ~~loan includes~~loans include both a floating rate tranche and fixed rate ~~tranche.~~tranche as described below.

We issued ~~$350~~$350.0 million at a variable rate with interest payable quarterly and principal due on April 1, 2014 (the ~~“Variable Rate Term Loans”~~“variable rate term loans”). The ~~Variable Rate Term Loans~~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~~bank’s prime rate plus 2.625%. After April 1, 2009, the ~~Variable Rate Term Loans~~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 ~~and nine~~ month ~~periods~~period ended ~~September 30, 2007 were 8.99% and 8.98%, respectively.~~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~~$650.0 million at a fixed rate of 8.625% with principal due on April 1, 2015 (the ~~“Fixed Rate Term Loans”~~“fixed rate term loans”). Under the terms of the ~~Fixed Rate Term Loans,~~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.~~fixed rate term loans. If we elect to pay the interest due during any period in additional ~~Fixed Rate Term Loans,~~fixed rate term loans, the interest rate increases to 9.375% during such period. After April 1, 2011, the ~~Fixed Rate Term Loans~~fixed rate term loans may be prepaid in whole or in part with prepayment penalties.

~~After~~On March ~~22,~~28, 2008, we ~~are required to~~commenced an offer to exchange the senior term loan for senior unsecured notes with registration rights. The senior unsecured notes will have substantially similar terms and conditions as the term loan. If we are unable to or do not offer to exchange the term loanloans for senior unsecured notes with registration rights, ~~by April 30, 2008,~~as required under the ~~interest rate on the~~senior term loan ~~will increase by 0.25% every 90 days up~~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 ~~a maximum~~those of ~~0.50%. The~~the exchanged senior term ~~loan contains other~~loans, except that the senior notes have been issued with registration rights.

Debt covenants ~~which are ordinary~~under the senior term loans include financial covenants similar to those of the senior credit facility and ~~customary including~~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 ~~with Merrill Lynch Capital Corporation.~~payable. At ~~September 30, 2007,~~March 31, 2008, the aggregate outstanding balance of these ~~credit agreements~~notes was ~~$51.3~~$44.3 million, with aannual fixed interest ~~rate~~rates ranging from 7.64% to 8.87%. The notes have a final maturity date of ~~November~~December 1, ~~2010,~~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 ~~1-3%~~ranging from 1 to 3%) ~~in the event~~that is triggered if we repay the notes prior to maturity.

We have financed the purchase of various vehicles, oil field services equipment and other equipment used in our business. The aggregate outstanding balance of these notes as of December 31, 2006 was $4.5 million. These notes were repaid during the three months ended September 30, 2007 with borrowings under our senior credit facility.

On October 14, 2005, Sagebrush Pipeline, LLC borrowed $4.0 million from Bank of America, N.A. for the purpose of completing the gas processing plant and pipeline in Colorado. This loan was repaid in full in July 2007.

~~Senior Bridge Facility.~~ On November 21, 2006, we also entered into an $850 million senior unsecured bridge facility (the “senior bridge facility”) with Banc of America Bridge LLC, as the Initial Bridge Lender and Banc of America Securities LLC, Credit Suisse Securities, Goldman Sachs Credit Partners L.P., and Lehman Brothers Inc., as joint lead arrangers and bookrunners. This facility was repaid in full during March 2007 with proceeds from our senior unsecured term loan.

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 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 obligations under the senior bridge facility are general unsecured obligations of our company and certain of our subsidiaries. The senior bridge facility was paid in full in March 2007 with the proceeds from the term loan and the common stock issuance described above.

The senior bridge facility contained customary restrictive covenants pertaining to management and operations of our company and our subsidiaries similar to those contained in the senior credit facility. Generally, amounts outstanding under the senior bridge facility bore interest at a base rate equal to the greater of (i) three-month LIBOR plus an applicable margin initially equal to 4.50% per annum or (ii) 9.0% per annum plus an applicable margin initially equal to 0% per annum; provided that the applicable margin for the senior bridge facility will increase by 0.5% at the end of the period that is six months after the closing date for the senior bridge facility and an additional 0.25% per quarter thereafter for as long as the senior bridge facility, Rollover Loans or Exchange Notes remain outstanding subject to a cap of 11% (subject to certain additional interest rate increases in certain circumstances). In addition, the senior bridge facility included a covenant that obligated us to use commercially reasonable efforts to refinance the senior bridge facility as promptly as practicable.

~~Prior Senior Credit Facility.~~ Prior to its termination on November 21, 2006, we had a $130 million revolving credit facility in place with Bank of America, N.A. (the “prior senior credit facility”). The prior senior credit facility included a $20 million sub-limit for letters of credit. The prior senior credit facility was replaced by the senior credit facility as of November 21, 2006. Advances under the prior senior credit facility were subject to a borrowing base based on our proved developed producing reserves, our proved developed non-producing reserves and proved undeveloped reserves. The borrowing base was subject to re-determination semi-annually at the sole discretion of the lender based on the reports of independent petroleum engineers in accordance with normal and customary natural gas and oil lending practices.

The prior senior credit facility bore interest at our option at either LIBOR plus 2.15% or the Bank of America, N.A. prime rate. We paid a commitment fee on the unused portion of the borrowing base amount equal to 1/8% per annum. The prior senior credit facility was collateralized by natural gas and oil properties representing at least 80% of the present discounted value of our proved reserves and by a negative pledge on any of our non-mortgaged properties.

Building Mortgage. On November 15, 2007, we entered into a $20.0 million note payable ~~in the amount of $20 million with a lending institution~~ which is fully secured by one of the buildings and a parking garage located on our property in downtown ~~property.~~Oklahoma City,

Oklahoma which we purchased in July 2007 to serve as its corporate headquarters. The mortgage bears interest at 6.08% ~~,and~~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 ~~$1.0~~$0.8 million and ~~$1.1~~$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 ~~have 2,184,286~~had 1,844,464 shares of redeemable convertible preferred stock issued and ~~outstanding.~~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 iswas $210 per share as of ~~September 30, 2007. Each~~March 31, 2008 and each share of redeemable convertible preferred stock ~~is currently~~was convertible into approximately 10.2 shares of common stock at the option of the holder, subject to certain anti-dilution adjustments. ~~In addition, beginning in the second quarter~~During March 2008, holders of ~~2008, we may convert all outstanding~~339,823 shares of our redeemable convertible preferred stock ~~at the same conversion rate if we have satisfied certain conditions.~~

~~Initial Public Offering~~

~~On November 9, 2007, we completed an initial public offering (the “IPO”) of its common stock. We sold 28,700,000~~elected to convert those shares of SandRidge common stock, including 4,170,000 shares sold directly to an entity controlled by Tom L. Ward, at a price of $26 per share. We received net proceeds of approximately $705.4 million after deducting underwriting discounts of approximately $38.3 million and estimated offering expenses of approximately $2.5 million. This transaction priced after market close on November 5, 2007. In conjunction with the IPO, the underwriters were granted an option to purchase 3,679,500 additionalinto 3,465,593 shares of our common stock. ~~The underwriters fully exercised this option and purchased~~In May 2008, we converted the ~~additional~~remaining outstanding 1,844,464 shares on November 6, 2007. After deducting underwriting discounts of approximately $5.7 million, we received net proceeds of approximately $89.9 million from these additional shares. This offering generated total gross proceeds to us of approximately $841.8 million and total net proceeds of approximately $795.3 million to us after deducting total underwriting discounts of $44.0 million and other offering expenses estimated to be approximately $2.5 million. After the payment of offering expenses, we used a portion of the aggregate net proceeds to repay outstanding indebtedness under our senior credit facility as well as a note payable related to a recent acquisition. Funds remaining after these repayments will be used to fund future capital expenditures.

~~Contractual Obligations~~

~~A summary~~ of our ~~contractual obligations~~redeemable convertible preferred stock into 18,810,260 shares of our common stock as ~~of September 30, 2007 is provided in the following table:~~

Remainder
Payments Due by Year
of 2007 2008 2009 2010 2011 After 2011 Total
(In thousands)

Long-term debt $ 3,629 $ 14,450 $ 15,664 $ 11,541 $ 406,220 $ 1,000,000 $ 1,451,504
Interest on term loan(1) 35,502 85,944 85,944 85,944 85,944 249,436 628,714
Firm transportation(2) 237 949 949 949 949 4,592 8,625
Operating leases 1,209 4,525 2,707 110 46 — 8,597
Third party drilling rig commitments(3) 5,946 8,325 — — — — 14,271
Dispute settlement payments(4) — 5,000 5,000 5,000 5,000 — 20,000
Asset retirement obligations — 846 150 199 8,582 47,731 57,508

Total $ 46,523 $ 120,039 $ 110,414 $ 103,743 $ 506,741 $ 1,301,759 $ 2,189,219


~~(1)~~		~~Based on interest rates as of November 14, 2007.~~

~~(2)~~		We entered into a firm transportation agreement with Questar Pipeline Company giving us guaranteed capacity on their pipeline for 10 MmBtu per day at an estimated charge of $0.9 million per year, with a total commitment of $9.1 million. In December 2006 we assigned our rights and obligations to a third party.

~~(3)~~		Drilling contracts with third party drilling rig operators at specified day rates. All of our drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance. Subsequent to September 30, 2007, the Company signed short-term contracts (approximately 100 days) for two additional rigs for total commitments of approximately $3.8 million.

~~(4)~~		In January 2007, we settled a royalty interest dispute and agreed to pay five installments of $5 million each, plus interest commencing April 1, 2007. The remaining installments are due on July 1 of each year commencing July 1, 2008.

In connection with the NEG acquisition, we acquired restricted deposits aggregating $31.9 million. The restricted deposits represent bank trust and escrow accounts required to be set up by surety bond underwriters and certain former owners of a subsidiary on NEG’s offshore properties. In accordance with requirements of MMS, the NEG subsidiary was required to put in place surety bonds or escrow agreements to provide satisfaction of its eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. As part of the agreement with the surety bond underwriter or the former owners of the particular fields, bank

~~trust and escrow accounts were set up and funded based on~~permitted under the terms of the ~~escrow agreements. Certain amounts are required~~redeemable convertible preferred stock. This conversion resulted in a one-time charge to beretained 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 ~~upon receipt of proceeds from production.~~

~~In connection with one~~to the holders of the escrow accounts, we are required to make quarterly deposits to the escrow accounts of $0.8 million. Additionally, for some of the offshore properties, we will be required to deposit additional funds in an escrow account, representing the difference between the required escrow deposit under the surety bond and actual escrow deposit balance at various points in time in the future. Aggregate payments to the escrow accounts are estimated as follows (in thousands):

Remainder of 2007 $ 800
2008 3,200
2009 3,200
2010 5,000
Thereafter 4,000

$ 16,200

converted shares on May 7, 2008.


ITEM 3.	*Quantitative and Qualitative Disclosures About Market Risk*

General

~~We are exposed~~The discussion in this section provides information about the financial instruments we use to ~~a variety of market risks,~~manage commodity price ~~risk~~ and interest rate ~~risk. We address these risks through~~volatility. All contracts are financial contracts, which are settled in cash and do not require the delivery of a ~~program of risk management which may include the use of derivative instruments.~~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, which can be highly volatile.~~production. In light of ~~this~~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. ~~We will from~~From time to time, we enter into commodities pricing derivative ~~instruments~~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 ~~instruments~~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 ~~instruments~~contracts, including collars, fixed-price swaps and ~~fixed-price~~basis protection swaps. These transactions generally require no cash payment upfront and are settled in cash at maturity. While ~~this~~our derivative strategy may result in lower operating profits than if we were not party to these derivative ~~instruments~~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 ~~the~~each month.

Settlement for natural gas derivative contracts occurs in the month following the production month. ~~We currently do not enter into derivative arrangements with respect to our oil production, but we may do so in the future if our oil production increases as a result of the initiation of our CO~~₂ ~~tertiary oil recovery operations.~~ 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 ~~will be significantly affected by~~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 of derivative contracts with similar terms and characteristics. When market quotations are not available, we will estimate the fair value of derivative contracts using option pricing models that management believes represent its best estimate.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 ~~gain recognized in earnings, included in operating costs~~following table summarizes the cash settlements and ~~expenses,~~valuation gains and losses on our natural gas and crude oil commodity derivative contracts for the ~~nine~~three months ended ~~September 30, 2007~~March 31, 2008 and ~~2006 was a gain of $55.2 million and $16.2 million, respectively.~~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 ~~September 30, 2007,~~March 31, 2008, our open natural gas and crude oil commodity derivative contracts consisted of the following:

Period

Commodity

Notional

Fix Price

Fixed price swaps:

April 2007 — October 2007 Natural gas 4,280,000 MmBtu $ 7.02
April 2007 — October 2007 Natural gas 4,280,000 MmBtu $ 7.50
September 2007 — December 2007 Natural gas 1,220,000 MmBtu $ 8.88
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 7.60
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 7.82
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 8.00
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 8.04
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 8.77
October 2007 — December 2007 Natural gas 920,000 MmBtu $ 9.04
November 2007 — June 2008 Natural gas 4,860,000 MmBtu $ 8.05
November 2007 — June 2008 Natural gas 9,720,000 MmBtu $ 8.20
November 2007 — March 2008 Natural gas 1,520,000 MmBtu $ 8.51
January 2008 — June 2008 Natural gas 3,640,000 MmBtu $ 7.99
January 2008 — June 2008 Natural gas 3,640,000 MmBtu $ 7.99
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ 8.23
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ 8.48
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ 9.00
May 2008 — August 2008 Natural gas 2,460,000 MmBtu $ 8.38
July 2008 — September 2008 Natural gas 920,000 MmBtu $ 8.23
July 2008 — December 2008 Natural gas 1,840,000 MmBtu $ 8.31
Collars:

January 2007 — December 2007 Crude oil 60,000 Bbls $ 50.00 − $84.50
January 2008 — June 2008 Crude oil 42,000 Bbls $ 50.00 − $83.35
July 2008 — December 2008 Crude oil 54,000 Bbls $ 50.00 − $82.60
Waha basis swaps:

January 2007 — December 2007 Natural gas 7,300,000 MmBtu $ (0.5925 )
January 2007 — December 2007 Natural gas 14,600,000 MmBtu $ (0.70 )
April 2007 — October 2007 Natural gas 4,280,000 MmBtu $ (0.530 )
January 2008 — December 2008 Natural gas 10,980,000 MmBtu $ (0.57 )
January 2008 — December 2008 Natural gas 7,320,000 MmBtu $ (0.585 )
January 2008 — December 2008 Natural gas 7,320,000 MmBtu $ (0.59 )
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ (0.595 )
January 2008 — December 2008 Natural gas 3,660,000 MmBtu $ (0.625 )
January 2008 — December 2008 Natural gas 7,320,000 MmBtu $ (0.635 )
January 2008 — December 2008 Natural gas 7,320,000 MmBtu $ (0.6525 )
May 2008 — August 2008 Natural gas 2,460,000 MmBtu $ (0.45 )
January 2009 — December 2009 Natural gas 3,650,000 MmBtu $ (0.47 )
January 2009 — December 2009 Natural gas 3,650,000 MmBtu $ (0.49 )
January 2009 — December 2009 Natural gas 3,650,000 MmBtu $ (0.4975 )

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	)

4035


	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 ~~derivative instruments~~derivatives have not been designated as ~~hedges.~~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) to changes in market interest rates reflected in the fair value of the debt and (ii) to 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.

The indebtedness evidenced by our other notes payable related to our drilling rig fleet and related oil field services equipment, Sagebrush Pipeline, insurance financing, and other equipment and vehicles and a portion of our term loan is a fixed-rate debt, which exposes us to cash-flow risk from market interest rate changes on these notes. The fair value of that debt will vary as interest rates change.

~~Borrowings under our senior credit facility and a portion of our term loan expose us to certain market risks.~~ We use sensitivity analysis to determine the impact that market risk exposures may have on our variable interest rate borrowings. ~~At September 30, 2007, borrowings outstanding under our senior credit facility totaled $400 million.~~ Based on the approximately $350.0 million outstanding balance of the variable rate portion of our senior term ~~loan~~loans at ~~September 30, 2007,~~March 31, 2008, and $215.0 million outstanding balance on our senior credit facility a one percent change in the applicable ~~rate,~~rates, with all other variables held constant, would result in a change in our interest expense of approximately ~~$2.6~~$1.4 million for the ~~nine~~three months ended ~~September 30, 2007.~~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 ~~September 30, 2007,~~March 31, 2008, we ~~are~~did not ~~party to~~have any interest rate swap ~~instruments. Future~~contracts in effect. In January 2008, we entered into a $350.0 million notional amount interest rate ~~derivative instruments, if any, are expected to be~~swap agreement with ~~affiliates of the~~a financial institution that ~~are party to~~effectively fixed our ~~credit agreements.~~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.

~~ITEM 4.~~

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.

~~Controls and Procedures~~

~~In accordance with Rules 13a-15~~ITEM 4. Controls and ~~15d-15 under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), we carried out~~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 ~~(as defined in~~pursuant to Exchange ActRules~~13a-15(e)~~ 13a-15 and~~15d-15(e)~~15d-15 ~~under the Exchange Act)~~ as of ~~September 30, 2007.~~the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer ~~have~~ concluded that our ~~current~~ disclosure controls and procedures were effective ~~as of September 30, 2007~~ to provide reasonable assurance that the information required to be disclosed by us in our reports filed or submitted under the Exchange Act is ~~(i)~~ recorded, processed, summarized and reported within the time periods specified in the ~~SEC’s~~ rules and forms of the Securities and ~~(ii)~~Exchange Commission, and such information is accumulated and communicated to ~~our~~ management, ~~including our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions,~~ as appropriate to allow timely decisions regarding required disclosure. ~~During the three months ended September 30, 2007, there~~

There were no changes in our internal control over financial reporting ~~or in other factors~~during the quarter ended March 31, 2008 that have materially affected, or are reasonably likely to materially ~~effect~~affect, our internal control over financial reporting.

PART II. Other Information


ITEM 1.	*Legal Proceedings*

~~We are involved~~The Company is a defendant in ~~various disputes~~lawsuits from time to time in the normal course of business. ~~See further discussion of current litigation~~In management’s opinion, the Company is not currently involved in ~~Note 12 to~~any legal proceedings which, individually or in the ~~condensed consolidated financial statements. We believe that the ultimate resolution of currently pending litigation will not~~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 ~~Registration Statement on~~2007Form ~~S-1/A~~10-K. ~~dated October 23, 2007 and filed with the SEC on October 23, 2007 relating to our initial public~~

offering of common stock (the “Registration Statement”). The risk factors listed on pages 13 through 24 under the heading “Risk Factors” in the Registration Statement are incorporated herein by reference.


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

~~(b) The following use~~As part of ~~proceeds information is being provided with respect~~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 ~~Registration Statement, which was declared effective by~~tax obligation. The shares withheld are recorded as treasury shares. During the ~~SEC on November 5, 2007.~~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

~~The initial public offering of our common stock, par value $0.001 per share, commenced on November 5, 2007 following the effectiveness of our registration statement onForm S-1~~ ~~(FileNo. 333-144004).~~ Lehman Brothers, Goldman, Sachs & Co. and Banc of America Securities LLC acted as joint book-running managers and representatives of the underwriters in the offering. We issued and sold 28,700,000 shares of our common stock at $26 per share, including 4,170,000 shares sold directly to an entity controlled by Tom L. Ward, our Chairman, Chief Executive Officer and President. The offering generated gross proceeds of $746.2 million to us and net proceeds of approximately $705.4 million to us after deducting underwriters’ discounts of approximately $38.3 million and other expenses estimated to be approximately $2.5 million. This transaction priced after market close on November 5, 2007. In conjunction with this offering, the underwriters were granted an option to purchase 3,679,500 additional shares of our common stock. The underwriters fully exercised this option and purchased the additional shares on November 6, 2007. After deducting discounts of approximately $5.7 million, we received net proceeds of approximately $89.9 million from these additional shares. After the payment of offering expenses we used a portion of the aggregate net proceeds to repay the outstanding indebtedness under our senior credit facility as well as a note payable outstanding related to a recent acquisition. None of the offering expenses or net proceeds of the offering to us were direct or indirect payments to our directors, officers, affiliates, or to a person owning 10% or more of our common stock.


ITEM 6.	*Exhibits*

See the Exhibit Index accompanying this report.

4237

SIGNATURE

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

SandRidge Energy, Inc.


	By:	/s/ Dirk M. Van Doren

Dirk M. Van Doren

Executive Vice President and

Chief Financial Officer

Date: ~~December 3, 2007~~May 8, 2008

4338

EXHIBIT INDEX ~~TO EXHIBITS~~

31 .1 — Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
31 .2 — Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
32 — Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)


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

	3	.1	Certificate of Incorporation	3.1 to Registration Statement onForm S-1 filed on January 30, 2008	333-148956
	3	.2	Certificate of Designation of convertible preferred stock	3.2 to Registration Statement onForm 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 onForm 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 onForm 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				Nine Months Ended
	September 30, 2006				September 30, 2006
	(As Originally				(As Originally
	Presented)		(As Restated)		Presented)		(As Restated)

Income tax expense	$	4,844	$	1,781	$	8,998	$	6,931

Net income	$	13,308	$	4,895	$	15,175	$	18,927

Basic earnings per share	$	0.18	$	0.07	$	0.21	$	0.26

Diluted earnings per share	$	0.18	$	0.07	$	0.21	$	0.26


Balance at December 31, 2006	$	26,198
Adjustments		878

Balance at September 30, 2007	$	27,076


					Weighted Avg.
Period	Commodity		Notional		Fix Price

Fixed price swaps:
April 2007 — October 2007		Natural gas		4,280,000 MmBtu	$	7.02
April 2007 — October 2007		Natural gas		4,280,000 MmBtu	$	7.50
September 2007 — December 2007		Natural gas		1,220,000 MmBtu	$	8.88
October 2007 — December 2007		Natural gas		920,000 MmBtu	$	7.60
October 2007 — December 2007		Natural gas		920,000 MmBtu	$	7.82
October 2007 — December 2007		Natural gas		920,000 MmBtu	$	8.00
October 2007 — December 2007		Natural gas		920,000 MmBtu	$	8.04
October 2007 — December 2007		Natural gas		920,000 MmBtu	$	8.77
October 2007 — December 2007		Natural gas		920,000 MmBtu	$	9.04
November 2007 — June 2008		Natural gas		4,860,000 MmBtu	$	8.05
November 2007 — June 2008		Natural gas		9,720,000 MmBtu	$	8.20
November 2007 — March 2008		Natural gas		1,520,000 MmBtu	$	8.51
January 2008 — June 2008		Natural gas		3,640,000 MmBtu	$	7.99
January 2008 — June 2008		Natural gas		3,640,000 MmBtu	$	7.99
January 2008 — December 2008		Natural gas		3,660,000 MmBtu	$	8.23
January 2008 — December 2008		Natural gas		3,660,000 MmBtu	$	8.48
January 2008 — December 2008		Natural gas		3,660,000 MmBtu	$	9.00
May 2008 — August 2008		Natural gas		2,460,000 MmBtu	$	8.38
July 2008 — September 2008		Natural gas		920,000 MmBtu	$	8.23
July 2008 — December 2008		Natural gas		1,840,000 MmBtu	$	8.31
Collars:
January 2007 — December 2007		Crude oil		60,000 Bbls	$	50.00 − $84.50
January 2008 — June 2008		Crude oil		42,000 Bbls	$	50.00 − $83.35
July 2008 — December 2008		Crude oil		54,000 Bbls	$	50.00 − $82.60
Waha basis swaps:
January 2007 — December 2007		Natural gas		7,300,000 MmBtu	$	(0.5925	)
January 2007 — December 2007		Natural gas		14,600,000 MmBtu	$	(0.70	)
April 2007 — October 2007		Natural gas		4,280,000 MmBtu	$	(0.530	)
January 2008 — December 2008		Natural gas		10,980,000 MmBtu	$	(0.57	)
January 2008 — December 2008		Natural gas		7,320,000 MmBtu	$	(0.585	)
January 2008 — December 2008		Natural gas		7,320,000 MmBtu	$	(0.59	)
January 2008 — December 2008		Natural gas		3,660,000 MmBtu	$	(0.595	)
January 2008 — December 2008		Natural gas		3,660,000 MmBtu	$	(0.625	)
January 2008 — December 2008		Natural gas		7,320,000 MmBtu	$	(0.635	)
January 2008 — December 2008		Natural gas		7,320,000 MmBtu	$	(0.6525	)
May 2008 — August 2008		Natural gas		2,460,000 MmBtu	$	(0.45	)
January 2009 — December 2009		Natural gas		3,650,000 MmBtu	$	(0.47	)
January 2009 — December 2009		Natural gas		3,650,000 MmBtu	$	(0.49	)
January 2009 — December 2009		Natural gas		3,650,000 MmBtu	$	(0.4975	)


	Remainder		Payments Due by Year
	of 2007		2008		2009		2010		2011		After 2011		Total
							(In thousands)

Long-term debt	$	3,629	$	14,450	$	15,664	$	11,541	$	406,220	$	1,000,000	$	1,451,504
Interest on term loan(1)		35,502		85,944		85,944		85,944		85,944		249,436		628,714
Firm transportation(2)		237		949		949		949		949		4,592		8,625
Operating leases		1,209		4,525		2,707		110		46		—		8,597
Third party drilling rig commitments(3)		5,946		8,325		—		—		—		—		14,271
Dispute settlement payments(4)		—		5,000		5,000		5,000		5,000		—		20,000
Asset retirement obligations		—		846		150		199		8,582		47,731		57,508

Total	$	46,523	$	120,039	$	110,414	$	103,743	$	506,741	$	1,301,759	$	2,189,219


Remainder of 2007	$	800
2008		3,200
2009		3,200
2010		5,000
Thereafter		4,000

	$	16,200

Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)