e10vq

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

Form 10-Q


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended September 30, 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 (State or other jurisdiction of incorporation or organization)		20-8084793 (I.R.S. Employer Identification No.)
123 Robert S. Kerr Avenue Oklahoma City, Oklahoma (Address of principal executive offices)		73102 (Zip Code)

Registrant’s telephone number, including area code:

(405) 429-5500

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

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

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


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

(Do not check if a smaller reporting company)

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

As of October 31, 2008, 166,061,227 shares of the registrant’s common stock, par value $0.001 per share, were outstanding.

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Various statements contained in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements include projections and estimates concerning 2008 capital expenditures, our liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes and elements of our business strategy. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in the prospectus we filed with the Securities and Exchange Commission on September 17, 2008, and in Item 1A of Part II of this quarterly report, the opportunities that may be presented to and pursued by us, competitive actions by other companies, changes in laws or regulations and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.

PART I. Financial Information


ITEM 1.	*Financial Statements*

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets


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

ASSETS
Current assets:
Cash and cash equivalents	$	898		$	63,135
Accounts receivable, net:
Trade		99,062			94,741
Related parties		13,874			20,018
Derivative contracts		87,751			21,958
Inventories		7,318			3,993
Deferred income taxes		3,528			1,820
Other current assets		29,858			20,787

Total current assets		242,289			226,452
Natural gas and crude oil properties, using full cost method of accounting
Proved		4,155,044			2,848,531
Unproved		211,314			259,610
Less: accumulated depreciation and depletion		(434,561	)		(230,974	)

		3,931,797			2,877,167

Other property, plant and equipment, net		612,428			460,243
Derivative contracts		16,080			270
Investments		9,311			7,956
Restricted deposits		32,745			31,660
Other assets		45,852			26,818

Total assets	$	4,890,502		$	3,630,566


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current maturities of long-term debt	$	16,227		$	15,350
Accounts payable and accrued expenses:
Trade		314,444			215,497
Related parties		575			395
Asset retirement obligation		1,524			864
Billings in excess of costs incurred		11,885			—

Total current liabilities		344,655			232,106
Long-term debt		1,956,044			1,052,299
Other long-term obligations		11,817			16,817
Asset retirement obligation		64,574			57,716
Deferred income taxes		134,283			49,350

Total liabilities		2,511,373			1,408,288

Commitments and contingencies (Note 12)
Minority interest		28			4,672
Redeemable convertible preferred stock, $0.001 par value, 2,625 shares authorized; 0 and 2,184 issued and outstanding at September 30, 2008 and December 31, 2007, respectively		—			450,715
Stockholders’ equity:
Preferred stock, $0.001 par value; 47,375 shares authorized; no shares issued and outstanding in 2008 and 2007		—			—
Common stock, $0.001 par value, 400,000 shares authorized; 166,973 issued and 165,648 outstanding at September 30, 2008 and 141,847 issued and 140,391 outstanding at December 31, 2007		163			140
Additional paid-in capital		2,161,891			1,686,113
Treasury stock, at cost		(19,315	)		(18,578	)
Retained earnings		236,362			99,216

Total stockholders’ equity		2,379,101			1,766,891

Total liabilities and stockholders’ equity	$	4,890,502		$	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
	September 30,						September 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands, except per share amounts)

Revenues:
Natural gas and crude oil	$	259,141		$	113,106		$	756,762		$	319,556
Drilling and services		12,054			16,684			36,345			56,928
Midstream and marketing		58,343			19,030			174,240			71,131
Other		4,485			4,828			13,812			14,160

Total revenues		334,023			153,648			981,159			461,775
Expenses:
Production		41,070			28,689			115,512			77,707
Production taxes		6,717			4,402			29,456			12,328
Drilling and services		8,191			6,809			20,426			30,935
Midstream and marketing		51,908			14,444			157,059			61,191
Depreciation, depletion and amortization — natural gas and crude oil		71,964			45,177			209,296			115,876
Depreciation, depletion and amortization — other		17,597			14,282			51,342			36,545
General and administrative		29,235			20,421			76,432			45,781
(Gain) loss on derivative contracts		(292,526	)		(39,247	)		4,086			(55,228	)
Gain on sale of assets		(1,420	)		(1,045	)		(9,131	)		(1,704	)

Total expenses		(67,264	)		93,932			654,478			323,431

Income from operations		401,287			59,716			326,681			138,344

Other income (expense):
Interest income		923			544			3,068			3,671
Interest expense		(41,026	)		(28,522	)		(88,421	)		(88,630	)
Minority interest		(2	)		(164	)		(853	)		(321	)
(Loss) income from equity investments		(60	)		1,235			1,355			3,399
Other (expense) income, net		(83	)		31			856			530

Total other (expense) income		(40,248	)		(26,876	)		(83,995	)		(81,351	)

Income before income tax expense		361,039			32,840			242,686			56,993
Income tax expense		130,693			11,920			89,308			21,002

Net income		230,346			20,920			153,378			35,991
Preferred stock dividends and accretion		—			9,313			16,232			30,573

Income available to common stockholders	$	230,346		$	11,607		$	137,146		$	5,418

Income per share available to common stockholders:
Basic	$	1.41		$	0.11		$	0.90		$	0.05

Diluted	$	1.40		$	0.11		$	0.89		$	0.05

Weighted average number of common shares outstanding:
Basic		163,020			107,554			153,125			102,562

Diluted		164,554			109,049			154,489			103,778

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

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Statement of Changes in Stockholders’ Equity


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

Nine months ended September 30, 2008:
Balance, December 31, 2007	$	140	$	1,686,113	$	(18,578	)	$	99,216		$	1,766,891
Purchase of treasury stock		—		—		(3,536	)		—			(3,536	)
Common stock issued under retirement plans		—		3,167		2,799			—			5,966
Accretion on redeemable convertible preferred stock		—		—		—			(7,636	)		(7,636	)
Redeemable convertible preferred stock dividend		—		—		—			(8,596	)		(8,596	)
Stock-based compensation, net of tax		—		14,283		—			—			14,283
Conversion of redeemable convertible preferred stock to common stock		23		458,328		—			—			458,351
Net income		—		—		—			153,378			153,378

Balance, September 30, 2008	$	163	$	2,161,891	$	(19,315	)	$	236,362		$	2,379,101

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
	September 30,
	2008			2007
	(Unaudited)
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	153,378		$	35,991
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for doubtful accounts		1,623			—
Depreciation, depletion and amortization		260,638			152,421
Debt issuance cost amortization		4,026			14,903
Deferred income taxes		83,225			20,004
Unrealized gain on derivative contracts		(81,603	)		(36,052	)
Gain on sale of assets		(9,131	)		(1,704	)
Interest income — restricted deposits		(304	)		(1,024	)
Income from equity investments		(1,355	)		(3,399	)
Stock-based compensation, net of tax		14,283			4,962
Minority interest		853			321
Changes in operating assets and liabilities		108,735			53,133

Net cash provided by operating activities		534,368			239,556

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(1,609,355	)		(895,160	)
Acquisition of assets		—			(3,001	)
Proceeds from sale of assets		158,534			6,458
Loans to unconsolidated investees		(5,500	)		—
Fundings of restricted deposits		(781	)		(5,638	)

Net cash used in investing activities		(1,457,102	)		(897,341	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,768,722			1,262,769
Repayments of borrowings		(864,100	)		(879,592	)
Dividends paid — preferred		(17,552	)		(24,366	)
Minority interest (distributions) contributions		(5,497	)		192
Proceeds from issuance of common stock		—			319,966
Purchase of treasury stock		(3,536	)		(1,579	)
Debt issuance costs		(17,540	)		(26,540	)

Net cash provided by financing activities		860,497			650,850

NET DECREASE IN CASH AND CASH EQUIVALENTS		(62,237	)		(6,935	)
CASH AND CASH EQUIVALENTS, beginning of year		63,135			38,948

CASH AND CASH EQUIVALENTS, end of period	$	898		$	32,013

Supplemental Disclosure of Noncash Investing and Financing Activities:
Insurance premiums financed	$	—		$	1,496
Accretion on redeemable convertible preferred stock	$	7,636		$	1,062
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., together with its subsidiaries (collectively, the “Company” or “SandRidge”), is a natural gas and crude oil company with its principal focus on exploration, development and production. SandRidge also owns and operates natural gas gathering and processing facilities and CO₂ treating and transportation facilities and has marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc., (“LSI”) a wholly owned subsidiary of SandRidge, owns and operates drilling rigs and a related oil field services business. SandRidge’s primary exploration, development and production areas are concentrated in West Texas. The Company also operates interests in the Mid-Continent, the Cotton Valley Trend in East Texas, the Gulf Coast and the Gulf of Mexico.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2007 have been derived from the audited financial statements contained in the Company’s annual report on Form 10-K for the fiscal year ended December 31, 2007 (the “2007 Form 10-K”). The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2007 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These condensed financial statements should be read in conjunction with the financial statements and notes thereto included in the 2007 Form 10-K.


2.	Significant Accounting Policies

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

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

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

In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”). FSP 157-2 delays the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. The Company plans to implement this standard on January 1, 2009. The adoption of FSP 157-2 is not expected to have a material impact on the Company’s financial condition, operations or cash flows.

In October 2008, the FASB issued FASB Staff Position FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” (“FSP 157-3”). FSP 157-3 clarifies the application of SFAS No. 157 in determining the fair value of a financial asset when the market for that financial asset is not active. As of September 30, 2008, the Company has no financial assets with a market that is not active. Accordingly, FSP 157-3 has no effect on the Company’s current financial statements.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

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

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51,” which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. The Statement also establishes disclosure requirements to clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company is currently evaluating the potential impact of this standard.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which changes disclosure requirements for derivative instruments and hedging activities. The Statement requires enhanced disclosure, including qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008. The Company plans to implement this standard on January 1, 2009. The Company is currently evaluating the provisions of this standard. As SFAS No. 161 pertains to disclosure requirements, no effect to the Company’s financial condition or operations is expected.


3.	Property, Plant and Equipment

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


	September 30,			December 31,
	2008			2007

Natural gas and crude oil properties:
Proved	$	4,155,044		$	2,848,531
Unproved		211,314			259,610

Total natural gas and crude oil properties		4,366,358			3,108,141
Less accumulated depreciation and depletion		(434,561	)		(230,974	)

Net natural gas and crude oil properties capitalized costs		3,931,797			2,877,167

Land		9,929			1,149
Non natural gas and crude oil equipment		713,525			539,893
Buildings and structures		60,070			38,288

Total		783,524			579,330
Less accumulated depreciation, depletion and amortization		(171,096	)		(119,087	)

Net capitalized costs		612,428			460,243

Total property, plant and equipment	$	4,544,225		$	3,337,410

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

The Company completed the sale of all its assets located in the Piceance Basin of Colorado in May 2008. Net proceeds to the Company were approximately $147.2 million after closing adjustments. Assets sold included undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells. The portion of the Company’s net proceeds attributable to its gathering and compression systems and facilities disposed exceeded the book basis of those assets resulting in a gain on sale of approximately $7.5 million. The sale of its acreage and working interests in wells was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

The amount of capitalized interest included in the above non natural gas and crude oil equipment balance at September 30, 2008 and December 31, 2007 was $3.8 million and $3.4 million, respectively.


4.	Fair Value Measurements

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

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The Statement requires fair value measurements to 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. The determination of the fair values below takes into account the market for the Company’s financial assets and liabilities, the associated credit risk and other factors as required under SFAS No. 157.

Per SFAS No. 157, the Company has classified its derivative contracts into one of three levels based upon the data relied upon to determine the fair value. The fair values of the Company’s natural gas and crude oil swaps, crude oil collars and interest rate swap are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts; however, the Company does not have access to specific valuation models used by the counterparties. Included in these models are discount factors that the Company must estimate in its calculation. Therefore,

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

these derivative contract assets and liabilities are classified as Level 3. The following table summarizes the valuation of the Company’s financial assets and liabilities as of September 30, 2008 (in thousands):


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

Assets (liabilities):
Natural gas and crude oil derivative contracts	$	—	$	—	$	96,095	$	96,095
Interest rate swap		—		—		7,736		7,736

	$	—	$	—	$	103,831	$	103,831

The table below sets forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended September 30, 2008 (in thousands):


	Derivatives

Balance of Level 3, June 30, 2008	$	(213,261	)
Total gains or losses (realized/unrealized)		289,813
Purchases, issuances and settlements		27,279
Transfers in and out of Level 3		—

Balance of Level 3, September 30, 2008	$	103,831

Changes in unrealized gains (losses) on derivative contracts held as of September 30, 2008	$	317,092

The table below sets forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the nine months ended September 30, 2008 (in thousands):


	Derivatives

Balance of Level 3, December 31, 2007	$	22,228
Total gains or losses (realized/unrealized)		3,649
Purchases, issuances and settlements		77,954
Transfers in and out of Level 3		—

Balance of Level 3, September 30, 2008	$	103,831

Changes in unrealized gains (losses) on derivative contracts held as of September 30, 2008	$	81,603

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)


5.	Asset Retirement Obligation

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


Asset retirement obligation, December 31, 2007	$	58,580
Liability incurred upon acquiring and drilling wells		4,350
Revisions in estimated cash flows		—
Liability settled in current period		(764	)
Accretion of discount expense		3,932

Asset retirement obligation, September 30, 2008		66,098
Less: current portion		1,524

Asset retirement obligation, net of current	$	64,574


6.	Billings in Excess of Costs Incurred

In June 2008, the Company entered into an agreement with a subsidiary of Occidental Petroleum Corporation (“Occidental”) to construct a CO₂ extraction plant (the “Century Plant”) located in Pecos County, Texas and associated compression and pipeline facilities for $800.0 million. Occidental will pay a minimum of 100% of the contract price, plus any subsequent agreed-upon revisions, to the Company through periodic cost reimbursements based upon the percentage of the project completed. Upon start-up, the Century Plant will be owned and operated by Occidental for the purpose of extracting CO₂ from delivered natural gas. The Company will deliver high CO₂ natural gas to the Century Plant. Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will extract CO₂ from the Company’s delivered natural gas. The Company will retain all methane from the Century Plant and its other existing plants.

The Company accounts for construction of the Century Plant using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Provisions for a contract loss are recognized when it has been determined that a loss will be incurred. During July 2008, the Company issued and received payment for a progress billing in the amount of $68.1 million. Billings in excess of costs incurred during the nine months ended September 30, 2008 were $11.9 million and are reported in the accompanying condensed consolidated balance sheet.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)


7.	Long-Term Debt

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


	September 30,		December 31,
	2008		2007

Senior credit facility	$	166,486	$	—
Other notes payable:
Drilling rig fleet and related oil field services equipment		36,747		47,836
Mortgage		19,038		19,651
Other equipment and vehicles		—		162
8.625% Senior Term Loan		—		650,000
Senior Floating Rate Term Loan		—		350,000
8.625% Senior Notes due 2015		650,000		—
Senior Floating Rate Notes due 2014		350,000		—
8.0% Senior Notes due 2018		750,000		—

Total debt		1,972,271		1,067,649
Less: current maturities of long-term debt		16,227		15,350

Long-term debt	$	1,956,044	$	1,052,299

Senior Credit Facility. On November 21, 2006, the Company entered into a $750.0 million senior secured revolving credit facility (the “senior credit facility”). As discussed further below, the borrowing base was $1.1 billion at September 30, 2008. The senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid without restriction so long as the Company is in compliance with its terms, including certain financial covenants.

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

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 financial covenants under the senior credit facility as of September 30, 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 natural gas and crude oil reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of proved natural gas and crude oil reserves reviewed in determining the borrowing base for the senior credit facility. Additionally, the obligations under the senior credit facility are guaranteed by certain Company subsidiaries.

At the Company’s election, interest under the senior credit facility is determined by reference to (i) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

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 was 4.52% and 4.32% for the three-month and nine-month periods ended September 30, 2008, respectively.

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. The borrowing base of proved reserves was initially set at $300.0 million. The borrowing base was subsequently increased to $400.0 million on May 2, 2007, $700.0 million on September 14, 2007 and $1.2 billion on April 4, 2008. The Company incurred additional costs related to the senior credit facility as a result of changes to the borrowing base. These costs have been deferred and are included in other assets on the accompanying condensed consolidated balance sheets. As a result of the private placement of $750.0 million of senior notes in May 2008 discussed below, the borrowing base was reduced to $1.1 billion. At September 30, 2008, the Company had $166.5 million outstanding and approximately $906.5 million undrawn under this facility.

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

Other Indebtedness. The Company has financed a portion of its drilling rig fleet and related oil field services equipment through notes. At September 30, 2008, the aggregate outstanding balance of these notes was $36.7 million, with an annual fixed interest rate ranging from 7.64% to 8.67%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments of 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. These notes were substantially repaid during 2007. As of September 30, 2008, there were no amounts outstanding under these notes. The Company financed its insurance premium payment made in 2007. Also, in 2007, the Company repaid a $4.0 million loan incurred in 2005 for the purpose of completing a gas processing plant and pipeline in Colorado.

8.625% Senior Term Loan and Senior Floating Rate Term Loan. On March 22, 2007, the Company issued $1.0 billion of unsecured senior term loans. The closing of the senior term loans was generally contingent upon closing the private placement of common equity as described in Note 14. 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 repaid in full in March 2007. The senior term loans included both a floating rate term loan and a fixed rate term loan, as described below.

The Company issued a $350.0 million senior term loan at a variable rate with interest payable quarterly and principal due on April 1, 2014. The variable rate term loan bore interest, at the Company’s option, at LIBOR plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

The Company issued a $650.0 million senior term loan at a fixed rate of 8.625% with the principal due on April 1, 2015. Under the terms of the fixed rate term loan, interest was payable quarterly and during the first four years interest was payable, at the Company’s option, either entirely in cash or entirely with additional fixed rate term loans.

8.625% Senior Notes Due 2015 and Senior Floating Rate Notes Due 2014. In May 2008, the Company completed an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. The Company issued $650.0 million of 8.625% Senior Notes due 2015 in exchange for an equal outstanding principal amount of its fixed rate term loan and $350.0 million of Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of its variable rate term loan. 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 were issued with registration rights. These senior notes are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries except certain minor subsidiaries. See Note 16.

In conjunction with the issuance of the senior notes, the Company agreed to file a registration statement with the SEC in connection with its offer to exchange the notes for substantially identical notes that are registered under the Securities Act of 1933, as amended (“Securities Act”). The Company filed a registration statement relating to the exchange offer during the third quarter 2008, and all unregistered notes had been exchanged for registered notes by October 27, 2008.

The 8.625% Senior Notes due 2015 bear interest at a fixed rate of 8.625% per annum with the principal due on April 1, 2015. Under the terms of the fixed rate senior notes, interest is payable semi-annually and, through the interest payment due on April 1, 2011, interest may be paid, at the Company’s option, either entirely in cash or entirely with additional fixed rate senior notes. If the Company elects to pay the interest due during any period in additional fixed rate senior notes, the interest rate will increase to 9.375% during that period. All interest payments made to date related to the fixed rate notes have been paid in cash. The Senior Floating Rate Notes due 2014 bear interest at LIBOR plus 3.625%, except for the period from April 1, 2008 to June 30, 2008, for which the interest rate was 6.323%. Interest is payable quarterly with principal due on April 1, 2014. The average interest rate paid on amounts outstanding under the Company’s floating rate senior notes for the three-month period ended September 30, 2008 was 6.42%.

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

On or after April 1, 2011, the Company may redeem some or all of the 8.625% Senior Notes at specified redemption prices. On or after April 1, 2009, the Company may redeem some or all of the Senior Floating Rate Notes at specified redemption prices.

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

8.0% Senior Notes Due 2018. In May 2008, the Company issued $750.0 million of unsecured 8.0% Senior Notes due 2018. The Company used $478.0 million of the $735.0 million net proceeds from the offering to repay the total balance outstanding on the senior credit facility at that time. The remaining proceeds were used to fund a portion of the Company’s 2008 capital expenditure program. The notes bear interest at a fixed rate of 8.0% per annum, payable

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices.

In conjunction with the issuance of the 8.0% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to register these notes by May 19, 2009 if they are not already freely tradable at that time. The Company expects the notes to become freely tradable 180 days after their issuance pursuant to Rule 144 under the Securities Act. The Company is required to pay additional interest if it fails to fulfill its obligations under the agreement within the specified time periods.

The Company incurred $15.8 million of debt issuance costs in connection with the offering of the 8.0% Senior Notes. These costs are included in other assets on the accompanying condensed consolidated balance sheet and amortized over the term of the notes.

Debt covenants under all of the senior notes 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. The Company was in compliance with all of the covenants under the senior notes as of September 30, 2008.

Senior Bridge Facility. On November 21, 2006, the Company entered into an $850.0 million senior unsecured bridge facility (the “senior bridge facility”). Together with borrowings under the senior credit facility, the proceeds from the senior bridge facility were used to (i) partially finance the NEG Oil & Gas LLC (“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.

Interest Paid. For the three months ended September 30, 2008 and 2007, interest payments, net of amounts capitalized, were $9.4 million and $28.8 million, respectively. For the nine months ended September 30, 2008 and 2007, interest payments, net of amounts capitalized, were $60.2 million and $58.2 million, respectively.


8.	Other Long-Term Obligations

The Company has recorded a long-term obligation for amounts to be paid under a settlement agreement with Conoco, Inc. entered into in January 2007. The Company agreed to pay approximately $25.0 million plus interest, payable in $5.0 million increments on April 1, 2007, July 1, 2008, July 1, 2009, July 1, 2010 and July 1, 2011. The payment made on July 1, 2008 was included in accounts payable-trade in the accompanying condensed consolidated balance sheets as of December 31, 2007, and the payment to be made on July 1, 2009 has been included in accounts payable-trade in the accompanying condensed consolidated balance sheets as of September 30, 2008. The non-current unpaid settlement amounts of approximately $10.0 million and $15.0 million have been included in other long-term obligations in the accompanying condensed consolidated balance sheets as of September 30, 2008 and December 31, 2007, respectively.


9.	Derivative Contracts

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

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

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

Natural Gas


	Notional		Weighted Avg.
Period and Type of Contract	(MMcf)(1)		Fixed Price

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		16,200	$	9.60
Basis swap contracts		16,200	$	(0.74	)
April 2009 — June 2009
Price swap contracts		10,920	$	8.79
Basis swap contracts		16,380	$	(0.74	)
July 2009 — September 2009
Price swap contracts		8,590	$	8.97
Basis swap contracts		16,560	$	(0.74	)
October 2009 — December 2009
Price swap contracts		8,280	$	9.40
Basis swap contracts		16,560	$	(0.74	)
January 2010 — March 2010
Basis swap contracts		8,100	$	(0.71	)
April 2010 — June 2010
Basis swap contracts		8,190	$	(0.71	)
July 2010 — September 2010
Basis swap contracts		8,280	$	(0.71	)
October 2010 — December 2010
Basis swap contracts		8,280	$	(0.71	)
January 2011 — March 2011
Basis swap contracts		1,350	$	(0.47	)
April 2011 — September 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	)


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

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

October 2008 — December 2008
Price swap contracts		225	$	93.17
Collar contracts		27	$	50.00 — 82.60
January 2009 — March 2009
Price swap contracts		45	$	126.38
April 2009 — June 2009
Price swap contracts		46	$	126.71
July 2009 — September 2009
Price swap contracts		46	$	126.61
October 2009 — December 2009
Price swap contracts		46	$	126.51

In January 2008, the Company entered into an interest rate swap to fix the variable LIBOR interest rate on its variable rate term loan at 6.26% per annum for the period April 1, 2008 to April 1, 2011. Due to the exchange of the variable rate term loan for Senior Floating Rate Notes, the interest rate swap is now being used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at 6.26% per annum through April 2011.

The Company’s derivatives have not been designated as hedges. The Company records all derivatives on the balance sheet at fair value. Changes in derivative fair values are recognized in earnings. Cash settlements and valuation gains and losses for commodity derivative contracts are included in (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, 2008 and 2007 (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Realized loss (gain)	$	27,279		$	(19,969	)	$	77,954		$	(19,176	)
Unrealized gain		(319,805	)		(19,278	)		(73,868	)		(36,052	)

(Gain) loss on derivative contracts	$	(292,526	)	$	(39,247	)	$	4,086		$	(55,228	)

An unrealized loss of $2.7 million and an unrealized gain of $7.7 million related to the interest rate swap are included in interest expense in the condensed consolidated statements of operations for the three- and nine-month periods ended September 30, 2008, respectively.

A counterparty to one of the Company’s derivative contracts, Lehman Brothers, declared bankruptcy on October 3, 2008. The Company’s position on this derivative contract is immaterial. Due to Lehman Brothers’ bankruptcy and the declaration of bankruptcy by its parent, Lehman Brothers Holdings, Inc. on September 15, 2008, the Company has not assigned any value to this derivative contract as of September 30, 2008.


10.	Income Taxes

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

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

For the three months ended September 30, 2008 and 2007, income tax payments were $0.1 million and $1.4 million, respectively. For the nine months ended September 30, 2008 and 2007, income tax payments were $2.0 million and $2.7 million, respectively.


11.	Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock. The following table summarizes the 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, 2008 and 2007 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Weighted average basic common shares outstanding		163,020		107,554		153,125		102,562
Effect of dilutive securities:
Restricted stock		1,534		1,495		1,364		1,216

Weighted average diluted common and potential common shares outstanding		164,554		109,049		154,489		103,778

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding redeemable convertible preferred stock for the nine-month period ended September 30, 2008 and three- and nine-month periods ended September 30, 2007. (See Note 13.) Under this method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available to common stockholders. The Company determined the if-converted method is not more dilutive and has included preferred stock dividends in the determination of income available to common stockholders for the nine months ended September 30, 2008 and the 2007 periods presented. No shares of redeemable convertible preferred stock were outstanding during the three-month period ended September 30, 2008.


12.	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 that, individually or in the aggregate, could have a material effect on its financial condition, operations or cash flows.

BP Pipelines v. Panaco. During the second quarter 2008, the Company received notice of a motion to set trial for an administrative claim that was filed in December 2004 by BP Pipelines (“BP”) against Panaco (part of the NEG entities acquired in November 2006) in Panaco’s bankruptcy proceeding. In the administrative claim, BP seeks to recover unpaid charges billed to Panaco for repairs made by BP to a segment of offshore pipeline originally owned by Panaco and transferred by merger to National Offshore, LP, now SandRidge Offshore, LLC. In September 2008, the Company and BP signed a settlement agreement the approval of which is currently pending before the bankruptcy court. Under the terms of this agreement, the Company will remit $0.7 million to BP and BP will release the Company from further liability related to this claim. The Company has established a contingency reserve for amounts to be paid under the settlement agreement.

The Company, through its subsidiary LSI, has entered into a revolving promissory note with Larclay, L.P. for an aggregate principal amount of up to $15.0 million. See Note 15.

SemGroup, L.P. Bankruptcy Filing. The Company’s customer, SemGroup, L.P., and certain of its subsidiaries (“SemGroup”), filed for bankruptcy on July 22, 2008. During the third quarter, the Company established an

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

allowance for doubtful recovery in the amount of $1.5 million for all amounts due from SemGroup after the Company was unable to enter into a supplier protection agreement with SemGroup.


13.	Redeemable Convertible Preferred Stock

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

Dividends

Declared

Dividend Period

per Share

Total

Payment Date

January 31, 2007

November 21, 2006 — February 1, 2007

3.21

6,859

February 15, 2007

May 8, 2007

February 2, 2007 — May 1, 2007

3.97

8,550

May 15, 2007

June 8, 2007

May 2, 2007 — August 1, 2007

4.10

8,956

August 15, 2007

September 24, 2007

August 2, 2007 — November 1, 2007

4.10

8,956

November 15, 2007

December 16, 2007

November 2, 2007 — February 1, 2008

4.10

8,956

February 15, 2008

March 7, 2008

February 2, 2008 — May 1, 2008

4.01

8,095

(1)

May 7, 2008

May 2, 2008 — May 7, 2008

4.01

501

May 7, 2008


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

Approximately $9.0 million in paid and unpaid dividends has been included in the Company’s earnings per share calculations for the three-month period ended September 30, 2007 as presented in the accompanying condensed consolidated statements of operations. Approximately $8.6 million and $29.5 million in paid and unpaid dividends have been included in the Company’s earnings per share calculations for the nine-month periods ended September 30, 2008 and 2007, respectively, as presented in the accompanying condensed consolidated statements of operations. No shares of redeemable convertible preferred stock were outstanding during the three-month period ended September 30, 2008.

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

During March 2008, holders of 339,823 shares of the Company’s redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of the Company’s common stock. Additionally, during May 2008, the Company converted the remaining outstanding 1,844,464 shares of its redeemable convertible preferred stock into 18,810,260 shares of its common stock as permitted under the terms of the redeemable convertible preferred stock. These conversions resulted in increases to additional paid-in capital totaling $452.2 million, which represents the difference between the par value of the common stock issued and the carrying value of the redeemable convertible shares converted. The Company also recorded charges to retained earnings totaling $7.2 million in accelerated accretion expense related to the converted redeemable convertible preferred shares. Prorated dividends totaling $0.5 million for the period from May 2, 2008 to the date of conversion (May 7, 2008) were paid to the holders of the converted shares on May 7, 2008. On and after the conversion date, dividends ceased to accrue and the rights of common unit holders to exercise outstanding warrants to purchase redeemable convertible preferred shares terminated.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)


14.	Stockholders’ Equity

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


	September 30,		December 31,
	2008		2007

Shares authorized		400,000		400,000
Shares outstanding at end of period		165,648		140,391
Shares held in treasury		1,325		1,456

The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 2,625,000 shares are designated as redeemable convertible preferred stock. As of December 31, 2007, there were 2,184,286 shares of redeemable convertible preferred stock outstanding and no other shares of preferred stock were outstanding. All shares of redeemable convertible preferred stock outstanding were converted to shares of the Company’s common stock during the first six months of 2008. (See Note 13.) There were no shares of preferred stock outstanding as of September 30, 2008.

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

On November 9, 2007, the Company completed the initial public offering of its common stock. The Company sold 32,379,500 shares of its common stock, including 4,710,000 shares sold directly to an entity controlled by Tom L. Ward, at a price of $26 per share. After deducting underwriting discounts of approximately $44.0 million and 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. 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. See additional discussion in Note 13.

Treasury Stock. The Company makes required tax payments on behalf of employees as their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately 79,000 and 41,000 shares at a total value of $3.5 million and $0.7 million during the nine-month periods ended September 30, 2008 and 2007, respectively. These shares were accounted for as treasury stock.

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

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

During July 2008, the Company transferred 26,058 shares of its treasury stock into an account established for the benefit of the Company’s non-qualified deferred compensation plan. This transfer was made in order to satisfy the Company’s $1.0 million accrued payable to match participant contributions made to the non-qualified plan through March 31, 2008. The historical cost of the shares transferred totaled approximately $0.4 million and resulted in an increase to the Company’s additional paid-in capital of approximately $0.6 million.

Restricted Stock. Under incentive compensation plans, the Company makes restricted stock awards which vest over specified periods of time. Awards made prior to 2006 had vesting periods of one, four or seven years. Each award made during and after 2006 vests ratably over a four-year period. Shares of restricted common stock are subject to restriction on transfer and certain conditions to vesting.

For the three months ended September 30, 2008 and 2007, the Company recognized stock-based compensation expense related to restricted stock of $5.5 million and $2.7 million, respectively. For the nine months ended September 30, 2008 and 2007, the Company recognized stock-based compensation expense related to restricted stock of $12.8 million and $5.0 million, respectively. Stock-based compensation expense is reflected in general and administrative expense in the condensed consolidated statements of operations.


15.	Related Party Transactions

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Sales to and reimbursements from related parties	$	24,552	$	27,355	$	76,978	$	72,434

Purchases of equipment and services from related parties	$	11,380	$	32,093	$	50,441	$	42,544

The Company leases office space in Oklahoma City from a member of its Board of Directors. The Company believes that the payments made under this lease are at fair market rates. Rent expense related to the lease totaled $0.3 million and $1.1 million for the three-month periods ended September 30, 2008 and 2007, respectively. For the nine-month periods ended September 30, 2008 and 2007, rent expense under this lease was $1.0 million and $1.7 million, respectively. The lease expires in August 2009.

Larclay, L.P. LSI and Clayton Williams Energy, Inc. (“CWEI”) each own a 50% interest in Larclay, L.P. (“Larclay”), a limited partnership formed in 2006 to acquire drilling rigs and provide land drilling services. Larclay currently owns 12 rigs, one of which has not yet been assembled. LSI operates the rigs owned by the partnership. Under the partnership agreement, CWEI was responsible for rig financing and purchasing.

If Larclay has an operating shortfall, LSI and CWEI are obligated to provide loans to the partnership. In April 2008, LSI and CWEI each made loans of $2.5 million to Larclay under promissory notes. The notes bear interest at a floating rate based on a LIBOR average plus 3.25% (5.75% at September 30, 2008) as provided in the partnership agreement. In June 2008, Larclay executed a $15.0 million revolving promissory note with each LSI and CWEI. Amounts drawn under each revolving promissory note bear interest at a floating rate based on a LIBOR average plus 3.25% (5.75% at September 30, 2008) as provided in the partnership agreement. Amounts advanced to Larclay by LSI under the revolving promissory note during 2008 were $3.0 million. The advances outstanding to Larclay, totaling $5.5 million ($2.5 million promissory note and $3.0 million drawn on revolving promissory note) at September 30, 2008 are included in other assets on the accompanying condensed consolidated balance sheets. Larclay’s current cash shortfall is a result of principal payments pursuant to its rig loan agreement.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

The following table summarizes the Company’s other transactions with Larclay for the three- and nine-month periods ended September 30, 2008 and 2007 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Sales to and reimbursements from Larclay	$	11,259	$	22,176	$	34,232	$	48,885

Purchases of services from Larclay	$	7,118	$	20,053	$	31,076	$	25,595


	As of		As of
	September 30,		December 31,
	2008		2007

Accounts receivable from Larclay	$	8,867	$	16,625
Accounts payable to Larclay	$	575	$	274


16.	Condensed Consolidating Financial Information

The Company is providing condensed consolidating financial information for its subsidiaries that are guarantors of its public debt registered in October 2008. Subsidiary guarantors are wholly owned and have, jointly and severally, unconditionally guaranteed on an unsecured basis the Company’s 8.625% Senior Notes due 2015 and Senior Floating Rate Notes due 2014. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors.

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

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc. and its wholly owned subsidiary guarantors, prepared on the equity basis of accounting. The non-guarantor subsidiaries are minor and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiary guarantors operated as independent entities.

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Condensed Consolidating Balance Sheet
(Unaudited)
(In Thousands)


	September 30, 2008									December 31, 2007
	Parent		Guarantor							Parent		Guarantor
	Company		Subsidiaries		Eliminations			Consolidated		Company		Subsidiaries		Eliminations			Consolidated

	ASSETS
Current assets:
Cash and cash equivalents	$	28	$	870	$	—		$	898	$	62,967	$	168	$	—		$	63,135
Accounts and notes receivable, net		681,734		76,895		(645,693	)		112,936		557,527		85,947		(528,715	)		114,759
Derivative contracts		87,751		—		—			87,751		21,958		—		—			21,958
Other current assets		6,819		33,885		—			40,704		5,936		20,664		—			26,600

Total current assets		776,332		111,650		(645,693	)		242,289		648,388		106,779		(528,715	)		226,452
Property, plant and equipment, net		1,672,081		2,872,144		—			4,544,225		967,259		2,370,151		—			3,337,410
Investment in subsidiaries		2,041,591		—		(2,041,591	)		—		1,817,330		—		(1,817,330	)		—
Other assets		106,938		48,434		(51,384	)		103,988		77,614		40,474		(51,384	)		66,704

Total assets	$	4,596,942	$	3,032,228	$	(2,738,668	)	$	4,890,502	$	3,510,591	$	2,517,404	$	(2,397,429	)	$	3,630,566


	LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	150,586	$	810,126	$	(645,693	)	$	315,019	$	224,015	$	520,592	$	(528,715	)	$	215,892
Other current liabilities		—		29,636		—			29,636		—		16,214		—			16,214

Total current liabilities		150,586		839,762		(645,693	)		344,655		224,015		536,806		(528,715	)		232,106
Long-term debt		1,916,486		90,942		(51,384	)		1,956,044		1,000,000		103,683		(51,384	)		1,052,299
Asset retirement obligations		6,486		58,088		—			64,574		4,620		53,096		—			57,716
Other liabilities		10,000		1,817		—			11,817		15,000		1,817		—			16,817
Deferred income taxes		134,283		—		—			134,283		49,350		—		—			49,350

Total liabilities		2,217,841		990,609		(697,077	)		2,511,373		1,292,985		695,402		(580,099	)		1,408,288

Minority interest		—		28		—			28		—		4,672		—			4,672
Redeemable convertible preferred stock		—		—		—			—		450,715		—		—			450,715
Stockholders’ equity		2,379,101		2,041,591		(2,041,591	)		2,379,101		1,766,891		1,817,330		(1,817,330	)		1,766,891

Total liabilities and stockholders’ equity	$	4,596,942	$	3,032,228	$	(2,738,668	)	$	4,890,502	$	3,510,591	$	2,517,404	$	(2,397,429	)	$	3,630,566

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Condensed Consolidating Statements of Operations
(Unaudited)
(In Thousands)


	Three Months Ended September 30,
	2008												2007
	Parent			Guarantor									Parent			Guarantor
	Company			Subsidiaries			Eliminations			Consolidated			Company			Subsidiaries			Eliminations			Consolidated

Revenues	$	98,320		$	234,415		$	1,288		$	334,023		$	44,011		$	109,637		$	—		$	153,648
Operating expenses:
Direct operating expenses		18,806			86,372			1,288			106,466			9,748			43,551			—			53,299
General and administrative		10,722			18,513			—			29,235			9,566			10,855			—			20,421
Depreciation, depletion, and amortization		31,400			58,161			—			89,561			10,932			48,527			—			59,459
(Gain) on derivative contracts		(292,526	)		—			—			(292,526	)		(19,305	)		(19,942	)		—			(39,247	)

Total operating expenses		(231,598	)		163,046			1,288			(67,264	)		10,941			82,991			—			93,932

Income from operations		329,918			71,369			—			401,287			33,070			26,646			—			59,716
Equity earnings from subsidiaries		70,172			—			(70,172	)		—			27,687			—			(27,687	)		—
Interest expense		(39,920	)		(1,106	)		—			(41,026	)		(27,851	)		(671	)		—			(28,522	)
Other income (expense), net		833			(55	)		—			778			7			1,639			—			1,646

Income before income taxes		361,003			70,208			(70,172	)		361,039			32,913			27,614			(27,687	)		32,840
Income tax expense (benefit)		130,657			36			—			130,693			11,993			(73	)		—			11,920

Net income	$	230,346		$	70,172		$	(70,172	)	$	230,346		$	20,920		$	27,687		$	(27,687	)	$	20,920


	Nine Months Ended September 30,
	2008												2007
	Parent			Guarantor									Parent			Guarantor
	Company			Subsidiaries			Eliminations			Consolidated			Company			Subsidiaries			Eliminations			Consolidated

Revenues	$	266,929		$	715,308		$	(1,078	)	$	981,159		$	84,296		$	377,479		$	—		$	461,775
Operating expenses:
Direct operating expenses		54,327			260,073			(1,078	)		313,322			24,263			156,194			—			180,457
General and administrative		28,021			48,411			—			76,432			24,869			20,912			—			45,781
Depreciation, depletion, and amortization		83,336			177,302			—			260,638			25,583			126,838			—			152,421
Loss (gain) on derivative contracts		4,086			—			—			4,086			(36,195	)		(19,033	)		—			(55,228	)

Total operating expenses		169,770			485,786			(1,078	)		654,478			38,520			284,911			—			323,431

Income from operations		97,159			229,522			—			326,681			45,776			92,568			—			138,344
Equity earnings from subsidiaries		228,249			—			(228,249	)		—			97,363			—			(97,363	)		—
Interest expense		(85,253	)		(3,168	)		—			(88,421	)		(86,064	)		(2,566	)		—			(88,630	)
Other income (expense), net		2,495			1,931			—			4,426			(84	)		7,363			—			7,279

Income before income taxes		242,650			228,285			(228,249	)		242,686			56,991			97,365			(97,363	)		56,993
Income tax expense (benefit)		89,272			36			—			89,308			21,000			2			—			21,002

Net income	$	153,378		$	228,249		$	(228,249	)	$	153,378		$	35,991		$	97,363		$	(97,363	)	$	35,991

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

Condensed Consolidating Statements of Cash Flows
(Unaudited)
(In Thousands)


	Nine Months Ended September 30,
	2008									2007
	Parent			Guarantor						Parent			Guarantor
	Company			Subsidiaries			Consolidated			Company			Subsidiaries			Eliminations			Consolidated

Net cash (used in) provided by operating activities	$	(150,969	)	$	685,337		$	534,368		$	(245,582	)	$	494,122		$	(8,984	)	$	239,556
Net cash used in investing activities		(789,828	)		(667,274	)		(1,457,102	)		(432,451	)		(464,890	)		—			(897,341	)
Net cash provided by (used in) financing activities		877,858			(17,361	)		860,497			675,848			(33,982	)		8,984			650,850

Net (decrease) increase in cash and cash equivalents		(62,939	)		702			(62,237	)		(2,185	)		(4,750	)		—			(6,935	)
Cash and cash equivalents at beginning of period		62,967			168			63,135			31,447			7,501			—			38,948

Cash and cash equivalents at end of period	$	28		$	870		$	898		$	29,262		$	2,751		$	—		$	32,013


17.	Subsequent Events

On October 9, 2008, the Company purchased certain working interests and related reserves in company wells owned by its Chairman and Chief Executive Officer, Tom L. Ward, and certain of his affiliates. Mr. Ward had acquired the interests pursuant to SandRidge’s Well Participation Plan, which commenced in June 2006. In connection with the acquisition, Mr. Ward and SandRidge agreed to terminate the plan. The Company paid $60.0 million in cash for the interests, subject to post-closing adjustments based on excess investments made by Mr. Ward and the value of actual production in respect of the acquired interests as compared to projected amounts. At closing, the amount of the adjustment was estimated to be $7.1 million payable by the Company. Final settlement is expected to occur in December 2008.


18.	Industry Segment Information

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

SandRidge Energy, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements — (Continued)

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Revenues:
Exploration and production	$	259,878		$	113,105		$	760,316		$	320,984
Elimination of inter-segment revenue		(66	)		(—	)		(154	)		(574	)

Exploration and production, net of inter-segment revenue		259,812			113,105			760,162			320,410

Drilling and oil field services		121,376			70,728			309,934			188,887
Elimination of inter-segment revenue		(109,343	)		(53,957	)		(273,715	)		(131,888	)

Drilling and oil field services, net of inter-segment revenue		12,033			16,771			36,219			56,999

Midstream gas services		198,220			55,395			566,274			189,143
Elimination of inter-segment revenue		(140,510	)		(36,364	)		(395,181	)		(118,012	)

Midstream gas services, net of inter-segment revenue		57,710			19,031			171,093			71,131

Other		5,851			7,209			17,358			19,780
Elimination of inter-segment revenue		(1,383	)		(2,468	)		(3,673	)		(6,545	)

Other, net of inter-segment revenue		4,468			4,741			13,685			13,235

Total revenues	$	334,023		$	153,648		$	981,159		$	461,775

Operating (Loss) Income:
Exploration and production	$	418,751		$	61,843		$	364,817		$	138,306
Drilling and oil field services		4,054			5,376			6,550			14,252
Midstream gas services		(1,359	)		3,657			5,226			5,958
Other		(20,159	)		(11,160	)		(49,912	)		(20,172	)

Total operating income		401,287			59,716			326,681			138,344
Interest income		923			544			3,068			3,671
Interest expense		(41,026	)		(28,522	)		(88,421	)		(88,630	)
Other income		(145	)		1,102			1,358			3,608

Income before income tax expense	$	361,039		$	32,840		$	242,686		$	56,993

Capital Expenditures:
Exploration and production	$	590,167		$	329,430		$	1,404,067		$	706,550
Drilling and oil field services		25,749			20,883			61,540			104,796
Midstream gas services		40,696			22,297			110,125			45,427
Other		18,442			30,406			33,623			38,387

Total capital expenditures	$	675,054		$	403,016		$	1,609,355		$	895,160


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

Introduction

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the accompanying notes included in this report, as well as our audited consolidated financial statements and the accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2007 (the “2007 Form 10-K”).

The financial information with respect to the three- and nine-month periods ended September 30, 2008 and September 30, 2007 that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Overview of Our Company

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

On November 21, 2006, we acquired all of the outstanding membership interests in NEG Oil & Gas LLC (“NEG”) for total consideration of approximately $1.5 billion, excluding cash acquired. With core assets in the Val Verde and Permian Basins of West Texas, including overlapping or contiguous interests in the WTO, the NEG acquisition dramatically increased our exploration and production segment operations. In addition to the NEG acquisition, we have completed numerous acquisitions of additional working interests in the WTO during the period from late 2005 through September 30, 2008. We also operate interests in the Mid-Continent, the Cotton Valley Trend in East Texas, the Gulf Coast area and the Gulf of Mexico.

During November 2007, we completed the initial public offering of our common stock. We used the proceeds from this offering to repay indebtedness outstanding under our senior credit facility as well as a note payable related to a 2007 acquisition and to fund the remainder of our 2007 capital expenditure program and a portion of our 2008 capital expenditure program. See further discussion of these transactions in Note 14 to the condensed consolidated financial statements contained in Part I, Item 1 of this report.

Recent Events

Production Shut-Ins. We entered the third quarter with 25 MMcfe per day shut in due to the closing of the Grey Ranch Plant in Pecos County, Texas following a fire on June 27, 2008 and well work along the Gulf Coast. During the quarter, we were also affected by Hurricanes Gustav and Ike. Overall, we shut in approximately 3.0 Bcfe of production during the third quarter. The Grey Ranch Plant was placed back in service on November 1, 2008, and other significant production curtailments are expected to be resolved by year end 2008.

Potential Asset Sale. In July 2008, we announced our intent to offer certain properties for sale and to retain third parties to assist in the marketing efforts. Assets subject to the potential sale include our developed and undeveloped properties in East Texas and our undeveloped properties in North Louisiana. The marketing process is ongoing as of the date of this filing.

SemGroup, L.P. Bankruptcy Filing. Our customer, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”), filed for bankruptcy on July 22, 2008. During the third quarter, we established an allowance for doubtful recovery in the amount of $1.5 million for all amounts due from SemGroup after we were unable to enter into a supplier protection agreement with SemGroup.

Acquisition of Additional Interests and Termination of Executive Well Participation Plan. On October 9, 2008, we purchased certain working interests and related reserves in company wells owned by our Chairman and Chief Executive Officer, Tom L. Ward, and certain of his affiliates. Mr. Ward had acquired the interests pursuant to SandRidge’s Well Participation Plan, which commenced in June 2006. In connection with the acquisition, Mr. Ward and SandRidge agreed to terminate the plan. We paid $60.0 million in cash for the interests, subject to post-closing adjustments based on excess investments made by Mr. Ward and the value of actual production in respect of the acquired interests as compared to projected amounts. At closing, the amount of the adjustment was estimated to be $7.1 million payable by us. Final settlement is expected to occur in December 2008. We estimate that the acquisition and termination of the plan increased our net proved reserves by approximately 43 Bcfe. Termination of the plan will permit us to retain a greater working interest in our future wells.

Segment Overview

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Segment income and expense (in thousands):
Revenue:
Exploration and production	$	259,812		$	113,105		$	760,162		$	320,410
Drilling and oil field services		12,033			16,771			36,219			56,999
Midstream gas services		57,710			19,031			171,093			71,131
Other		4,468			4,741			13,685			13,235

Total revenues		334,023			153,648			981,159			461,775
Operating (loss) income:
Exploration and production		418,751			61,843			364,817			138,306
Drilling and oil field services		4,054			5,376			6,550			14,252
Midstream gas services		(1,359	)		3,657			5,226			5,958
Other		(20,159	)		(11,160	)		(49,912	)		(20,172	)

Total operating income		401,287			59,716			326,681			138,344
Interest income		923			544			3,068			3,671
Interest expense		(41,026	)		(28,522	)		(88,421	)		(88,630	)
Other income		(145	)		1,102			1,358			3,608

Income before income taxes	$	361,039		$	32,840		$	242,686		$	56,993

Production data:
Natural gas (MMcf)		22,209			12,856			63,097			35,148
Crude oil (MBbls)		521			535			1,751			1,441
Combined equivalent volumes (MMcfe)		25,335			16,067			73,603			43,793
Average daily combined equivalent volumes (MMcfe/d)		275.4			174.6			268.6			160.4


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008		2007

Average prices — as reported(1):
Natural gas (per Mcf)	$	9.04	$	5.99		$	9.09	$	6.56
Crude oil (per Bbl)(2)	$	112.24	$	67.57		$	104.73	$	61.67
Combined equivalent (per Mcfe)	$	10.23	$	7.04		$	10.28	$	7.30
Average prices — including impact of derivative contract settlements:
Natural gas (per Mcf)	$	8.09	$	7.54		$	8.10	$	7.11
Crude oil (per Bbl)(2)	$	100.19	$	67.57		$	95.66	$	61.67
Combined equivalent (per Mcfe)	$	9.15	$	8.28		$	9.22	$	7.73
Drilling and oil field services:
Number of operational drilling rigs owned at end of period		28.0		27.0	(3)		28.0		27.0	(3)
Average number of operational drilling rigs owned during the period		28.0		27.0	(3)		27.0		26.0	(3)


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

(2)		Includes natural gas liquids.

(3)		Does not include five rigs being retrofitted as of September 30, 2007.

Exploration and Production Segment

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

The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our natural gas and crude oil production, the quantity of our natural gas and crude oil production and changes in the fair value of derivative contracts we use to reduce the volatility of the prices we receive for our natural gas and crude oil production. Because we are vertically integrated, our exploration and production activities affect the results of our drilling and oil field services and midstream gas services segments. The NEG acquisition in 2006 substantially increased our revenues and operating income in our exploration and production segment. As additional acquisitions have further increased our working interest in the WTO, a larger percentage of the work performed by our services segment is being performed for our own account.

Exploration and Production Segment — Three months ended September 30, 2008 compared to the three months ended September 30, 2007

Exploration and production segment revenues increased to $259.8 million in the three months ended September 30, 2008 from $113.1 million in the three months ended September 30, 2007, an increase of 129.7%, as a result of a 57.7% increase in combined production volumes and a 45.3% 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, 2008, natural gas production increased by 9.3 Bcf to 22.2 Bcf and crude oil production decreased by 14 MBbls to 521 MBbls from the comparable period in 2007. The total combined 9.3 Bcfe increase in production was due primarily to an increase in our average working interest in the WTO to 93% at September 30, 2008 from 85% at September 30, 2007 and successful drilling in the WTO throughout 2007 and the first nine months of 2008. We owned interests in a total of 2,075 producing wells at September 30, 2008 compared to 1,523 producing wells at September 30, 2007.

The average price we received for our natural gas production for the three-month period ended September 30, 2008 increased 50.9%, or $3.05 per Mcf, to $9.04 per Mcf from $5.99 per Mcf in the comparable period in 2007. The average price received for our crude oil production increased 66.1%, or $44.67 per barrel, to $112.24 per barrel during the three months ended September 30, 2008 from $67.57 per barrel during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended September 30, 2008 was $8.09 per Mcf compared to $7.54 per Mcf during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for crude oil for the three-month period ended September 30, 2008 was $100.19 per barrel. Our derivative contracts had no impact on effective oil prices during the three months ended September 30, 2007. Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded as an operating expense. Internally, management views the settlement of such derivative contracts as adjustments to the price received for natural gas and crude oil production to determine “effective prices.”

For the three months ended September 30, 2008, we had $418.8 million in operating income in our exploration and production segment, compared to $61.8 million in operating income for the same period in 2007. Our $146.7 million increase in exploration and production revenues and $292.5 million gain on our commodity derivative contracts of which $319.8 million was unrealized, were partially offset by a $12.4 million increase in production expenses and a $27.1 million increase in depreciation, depletion and amortization (“DD&A”) due to the increase in production. The increase in production expenses was attributable to the increase in number of operating wells we own and an increase in our average working interest in those wells. During the three-month period ended September 30, 2008, the exploration and production segment reported a $292.5 million net gain on our commodity derivative positions ($27.3 million realized loss and $319.8 million unrealized gain) compared to a $39.2 million gain ($19.9 million realized gain and $19.3 million unrealized gains) in the comparable period in 2007. During 2007 and 2008, we entered into natural gas and crude oil swaps and natural gas basis swaps. Given the long term nature of our investment in the WTO development program, management believes it prudent to enter into natural gas and crude oil swaps and natural gas basis swaps for a portion of our production in order to stabilize future cash inflows for planning purposes. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period-end prices compared to the contract price. The unrealized gain on natural gas and crude oil derivative contracts recorded in the three-month period ended September 30, 2008 was attributable to a decrease in average natural gas and crude oil prices at September 30, 2008 compared to the average natural gas and crude oil prices at June 30, 2008 or the contract price for contracts entered into during the period.

Exploration and Production Segment — Nine months ended September 30, 2008 compared to the nine months ended September 30, 2007

Exploration and production segment revenues increased to $760.2 million in the nine months ended September 30, 2008 from $320.4 million in the nine months ended September 30, 2007, an increase of 137.2%, as a result of a 68.1% increase in combined production volumes and a 40.8% increase in the combined average price we received for the natural gas and crude oil we produced. In the nine-month period ended September 30, 2008, we increased natural gas production by 27.9 Bcf to 63.1 Bcf and increased crude oil production by 310 MBbls to 1,751 MBbls from the comparable period in 2007.

The average price we received for our natural gas production for the nine-month period ended September 30, 2008 increased 38.6%, or $2.53 per Mcf, to $9.09 per Mcf from $6.56 per Mcf in the comparable period in 2007. The average price received for our crude oil production increased 69.8%, or $43.06 per barrel, to $104.73 per barrel during the nine months ended September 30, 2008 from $61.67 per barrel during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for natural gas for the nine-month period ended September 30, 2008 was $8.10 per Mcf compared to $7.11 per Mcf during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for crude oil for the nine-month period ended September 30, 2008 was $95.66 per barrel. Our derivative contracts had no impact on effective oil prices during the nine months ended September 30, 2007.

For the nine months ended September 30, 2008, we had $364.8 million in operating income in our exploration and production segment, compared to $138.3 million in operating income for the same period in 2007. Our

$439.8 million increase in exploration and production revenues was offset by a $4.1 million loss on our commodity derivative contracts, a $37.8 million increase in production expenses and a $94.0 million increase in DD&A, due to the increase in production. The increase in production expenses was attributable to the increase in number of operating wells we own and the increase in our average working interest in those wells. During the nine-month period ended September 30, 2008, the exploration and production segment reported a $4.1 million net loss on our commodity derivative positions ($78.0 million realized loss and $73.9 million unrealized gain) compared to a $55.2 million gain ($19.2 million realized gains and $36.0 million in unrealized gains) in the comparable period in 2007. The unrealized gain on natural gas and crude oil derivative contracts recorded in the nine-month period ended September 30, 2008 was attributable to a decrease in average natural gas and crude oil prices at September 30, 2008 compared to the average natural gas and crude oil prices at December 31, 2007 or the contract price for contracts entered into during the period.

Drilling and Oil Field Services Segment

We drill for our own account primarily in the WTO through our drilling and oil field services subsidiary, Lariat Services, Inc. (“LSI”). We also drill wells for other natural gas and crude oil companies, primarily located in the West Texas region. As of September 30, 2008, our drilling rig fleet consisted of 37 operational rigs, 26 of which we owned directly and 11 of which were owned by Larclay, L.P. (“Larclay”), a limited partnership in which we have a 50% interest. Our oil field services business conducts operations that complement our drilling services operations. These services include providing pulling units, trucking, rental tools, location and road construction and roustabout services to us and our subsidiaries as well as to third parties.

In 2006, LSI and its partner, CWEI, formed Larclay, which acquired twelve sets of rig components and other related equipment to assemble into completed land drilling rigs. The drilling rigs were to be used for drilling on CWEI’s prospects, our prospects or for contracting to third parties on daywork drilling contracts. All of these rigs have been delivered, although one rig has not been assembled. CWEI was responsible for securing financing and the purchase of the rigs. Larclay financed 100% of the acquisition cost of the rigs utilizing a guarantee by CWEI. LSI operates the rigs owned by the partnership. Larclay and CWEI are responsible for all costs related to the initial construction and equipping of the drilling rigs. If Larclay has an operating shortfall, LSI and CWEI are obligated to provide loans to the partnership. In April 2008, LSI and CWEI each made loans of $2.5 million to Larclay under promissory notes. The notes bear interest at a floating rate based on a London Interbank Offered Rate (“LIBOR”) average plus 3.25% (5.75% at September 30, 2008) as provided in the partnership agreement. In June 2008, Larclay executed a $15.0 million revolving promissory note with each of LSI and CWEI. Amounts drawn under each revolving promissory note bear interest at a floating rate based on a LIBOR average plus 3.25% (5.75% at September 30, 2008) as provided in the partnership agreement. LSI advanced $3.0 million to Larclay under the revolving promissory note during the first nine months of 2008. Larclay’s current cash shortfall is a result of principal payments pursuant to its rig loan agreement.

Although LSI’s 50% interest in Larclay affords us access to Larclay’s 11 operational rigs, we do not control Larclay. We account for our investment in Larclay under the equity method of accounting and, therefore, do not consolidate the results of its operations with ours. Only the activities of our wholly owned drilling and oil field services subsidiaries are included in the financial results of our drilling and oil field services segment. The financial results of our drilling and oil field services segment depend on many factors, particularly the demand for and the price we can charge for our services. We provide drilling services for our account and for others, generally on a daywork, and less often on a turnkey, contract basis. We generally assess the complexity and risk of operations, the on-site drilling conditions, the type of equipment to be used, the anticipated duration of the work to be performed and the prevailing market rates in determining the contract terms we offer.

Daywork Contracts. As of September 30, 2008, 26 of LSI’s rigs were operating under daywork contracts and 24 of these were working for our account. Under a daywork drilling contract, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs, and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.

Turnkey Contracts. Under a typical turnkey contract, a customer pays us to drill a well to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide most of the equipment and drilling supplies required to drill the well. We subcontract for related services such as the provision of casing crews, cementing and well logging. Generally, we do not receive progress payments and are paid only after the well is drilled. We enter into turnkey contracts in areas where our experience and expertise permit us to drill wells more profitably than under a daywork contract. As of September 30, 2008, there were no rigs operating under a turnkey contract.

Drilling and Oil Field Services Segment — Three months ended September 30, 2008 compared to the three months ended September 30, 2007

Drilling and oil field services segment revenues decreased to $12.0 million for the three-month period ended September 30, 2008 compared to $16.8 million in the three-month period ended September 30, 2007. Operating income also decreased to $4.1 million in the three-month period ended September 30, 2008 compared to operating income of $5.4 million in the same period in 2007. The decline in revenues and operating income is primarily attributable to an increase in the average number of our rigs operating on our properties, an increase in our ownership interest in our natural gas and crude oil properties and a decline in revenue earned per day by rigs working for third parties during the three months ended September 30, 2008 compared to the same period in 2007. 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.

During the three months ended September 30, 2008, an average of 26 of the 28 operational rigs we owned were working for our account compared to an average 20 of 24 operational rigs working for our account during the same period in 2007. As a result, during the three months ended September 30, 2008, 90.1%, or $109.3 million, of our drilling and oil service revenues were generated by work performed on our account and eliminated in consolidation compared to 76.3%, or $54.0 million, during the same period in 2007. Additionally, the average daily rate received per rig working for third parties declined to an average of $13,600 per rig per working day for the three months ended September 30, 2008 from an average of $15,900 per rig per working day during the same period in 2007. During the third quarter of 2007, two of our rigs working for third parties operated under turnkey contracts, which resulted in higher average revenues earned per day compared to revenues earned per day by rigs working under day rate contracts. None of our rigs operated under turnkey contracts during the three months ended September 30, 2008.

Drilling and Oil Field Services Segment — Nine months ended September 30, 2008 compared to the nine months ended September 30, 2007

Drilling and oil field services segment revenues decreased to $36.2 million in the nine-month period ended September 30, 2008 from $57.0 million in the nine-month period ended September 30, 2007. This resulted in operating income of $6.6 million in the nine-month period ended September 30, 2008 compared to operating income of $14.3 million in the same period in 2007. The decline in revenues and operating income is primarily attributable to an increase in the average number of our rigs operating on our properties, an increase in our ownership interest in our natural gas and crude oil properties and a decline in revenues earned per day by rigs working for third parties during the nine months ended September 30, 2008 compared to the same period in 2007.

During the nine months ended September 30, 2008, an average of 25 of the 27 operational rigs we owned were working for our account compared to an average of 16 of our 22 operational rigs working for our account during the same period in 2007. As a result, during the nine-month period ended September 30, 2008, 88.3%, or $273.7 million, of our drilling and oil field service revenues were generated by work performed on our account and eliminated in consolidation compared to 69.8%, or $131.9 million, for the same period in 2007. Additionally, the average daily rate we received per rig working for third parties declined to an average of $14,600 per rig per working day during the first nine months of 2008 from an average of $22,200 per rig per working day during the first nine months of 2007. During the nine months ended September 30, 2007, two of our rigs working for third parties operated under turnkey contracts, while none of our rigs operated under turnkey contracts during the nine months ended September 30, 2008.

Midstream Gas Services Segment

We provide gathering, compression, processing and treating services for natural gas in West Texas primarily through our wholly owned subsidiary, SandRidge Midstream, Inc. (formerly known as ROC Gas Company, Inc.). Through our gas marketing subsidiary, Integra Energy LLC, we buy and sell natural gas produced from our operated wells as well as third-party operated wells. Although gas marketing revenue is one of our largest revenue components, it is a very low margin business. On a consolidated basis, natural gas purchases and other costs of sales include the total value we receive from third parties for the natural gas we sell and the amount we pay for natural gas, which are reported as midstream and marketing expense in our condensed consolidated statements of operations. 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 Segment — Three months ended September 30, 2008 compared to the three months ended September 30, 2007

Midstream gas services revenues for the three months ended September 30, 2008 were $57.7 million compared to $19.0 million in the comparable period in 2007. The quarterly increase in midstream gas services revenues is attributable to larger third-party volumes transported and marketed through our gathering systems during the three months ended September 30, 2008 compared to the same period in 2007 as well as an overall increase in natural gas prices from the 2007 period to the 2008 period. We generally charge a flat fee per unit transported and charge a percentage of sales for marketed volumes.

Our midstream gas services segment generated an operating loss of $1.4 million for the three months ended September 30, 2008 compared to operating income of $3.7 million for the same period in 2007 primarily due to an increase in depreciation and property tax expenses. Upgrades made to midstream gathering and processing assets throughout 2007 and the first nine months of 2008 resulted in higher asset-related expenses in the third quarter of 2008 as compared to the third quarter of 2007.

Midstream Gas Services Segment — Nine months ended September 30, 2008 compared to the nine months ended September 30, 2007

Midstream gas services revenues for the nine months ended September 30, 2008 were $171.1 million compared to $71.1 million in the comparable period in 2007. The increase in midstream gas services revenues is attributable to larger third-party volumes transported and marketed through our gathering systems during the nine months ended September 30, 2008 compared to the same period in 2007 as well as an overall increase in natural gas prices from the 2007 period to the 2008 period.

Operating income generated by our midstream gas services segment decreased slightly to $5.2 million for the nine months ended September 30, 2008 from $6.0 million for the same period in 2007 due primarily to an increase in depreciation expense attributable to higher carrying values of midstream gathering and processing assets.

Other Segment

Our other segment consists primarily of our CO₂ gathering and sales operations and corporate operations. We conduct our CO₂ gathering and sales operations through our wholly owned subsidiary, SandRidge CO₂, LLC (formerly operated through PetroSource Energy Company, LLC). SandRidge CO₂ gathers CO₂ from natural gas treatment plants located in West Texas and transports and sells this CO₂ for use in our and third parties’ tertiary oil recovery operations. The operating loss in the other segment was $20.2 million for the three months ended September 30, 2008 compared to a loss of $11.2 million during the same period in 2007. The operating loss in the other segment was $49.9 million for the nine months ended September 30, 2008 compared to a loss of $20.2 million during the same period in 2007. The increases are primarily attributable to significant increases in corporate and support staff throughout 2007 and the first nine months of 2008.

Results of Operations

Three months ended September 30, 2008 compared to the three months ended September 30, 2007

Revenues. Total revenues increased 117.4% to $334.0 million for the three months ended September 30, 2008 from $153.6 million in the same period in 2007. This increase was primarily due to a $146.0 million increase in natural gas and crude oil sales and a $39.3 million increase in midstream and marketing revenues.


	Three Months Ended
	September 30,
	2008		2007		$ Change			% Change
	(In thousands)

Revenues:
Natural gas and crude oil	$	259,141	$	113,106	$	146,035			129.1	%
Drilling and services		12,054		16,684		(4,630	)		(27.8	)%
Midstream and marketing		58,343		19,030		39,313			206.6	%
Other		4,485		4,828		(343	)		(7.1	)%

Total revenues	$	334,023	$	153,648	$	180,375			117.4	%

Total natural gas and crude oil revenues increased $146.0 million to $259.1 million for the three months ended September 30, 2008 compared to $113.1 million in the same period in 2007, primarily as a result of the previously discussed increases in natural gas and crude oil production volumes and prices received for our production. Total natural gas production increased 72.8% to 22,209 MMcf in the 2008 period compared to 12,856 MMcf in the 2007 period, while crude oil production decreased 2.6% to 521 MBbls in the 2008 period from 535 MBbls in the 2007 period. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production increased 45.3% in the 2008 period to $10.23 per Mcfe compared to $7.04 per Mcfe in the 2007 period.

Drilling and services revenues decreased to $12.1 million for the three months ended September 30, 2008 compared to $16.7 million in the same period in 2007. The decline in revenues is primarily attributable to an increase in the average number of our rigs operating on our properties, the increase in our ownership interest in our natural gas and crude oil properties and the decrease in revenue earned per day by rigs working for third parties.

Midstream and marketing revenues increased $39.3 million, or 206.6%, with revenues of $58.3 million in the three-month period ended September 30, 2008 compared to $19.0 million in the three-month period ended September 30, 2007. This increase is due primarily to larger production volumes transported and marketed, during the three months ended September 30, 2008 compared to the same period in 2007, for the third parties with ownership in our wells or ownership in other wells connected to our gathering systems. Higher natural gas prices prevalent during the third quarter of 2008 compared to the third quarter of 2007 also contributed to the increase.

Other revenues remained constant at $4.5 million for the three months ended September 30, 2008 compared to $4.8 million in the same period in 2007. Other revenue is generated primarily by our CO₂ gathering and sales operations.

Operating Costs and Expenses. Total operating costs and expenses decreased to $(67.3) million for the three months ended September 30, 2008 compared to $93.9 million for the same period in 2007. The decrease was primarily due to a $292.5 million gain on derivative contracts during the three months ended September 30, 2008 of which $319.8 million was unrealized compared to a $39.2 million gain for the same period in 2007 of which $19.3 million was unrealized. Partially offsetting the gain on derivative contracts were increases in production-related costs, midstream and marketing expenses, general and administrative expenses and depreciation, depletion and amortization.


	Three Months Ended
	September 30,
	2008			2007			$ Change			% Change
	(In thousands)

Operating costs and expenses:
Production	$	41,070		$	28,689		$	12,381			43.2	%
Production taxes		6,717			4,402			2,315			52.6	%
Drilling and services		8,191			6,809			1,382			20.3	%
Midstream and marketing		51,908			14,444			37,464			259.4	%
Depreciation, depletion, and amortization — natural gas and crude oil		71,964			45,177			26,787			59.3	%
Depreciation, depletion and amortization — other		17,597			14,282			3,315			23.2	%
General and administrative		29,235			20,421			8,814			43.2	%
Gain on derivative contracts		(292,526	)		(39,247	)		(253,279	)		645.3	%
Gain on sale of assets		(1,420	)		(1,045	)		(375	)		35.9	%

Total operating costs and expenses	$	(67,264	)	$	93,932		$	(161,196	)		(171.6	)%

Production expenses include the costs associated with our production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $12.4 million primarily due to the increase in the number of producing wells in which we have a working interest (2,075 at September 30, 2008 compared to 1,523 at September 30, 2007). Production taxes increased $2.3 million, or 52.6%, to $6.7 million as a result of the increase in production and the increased prices received on our production during the three months ended September 30, 2008. The effect of the increased prices received for our production was offset by an increase in production tax exemptions realized during the three months ended September 30, 2008 compared to the same period in 2007. As a result, production taxes on a unit-of-production basis remained constant at $0.27 per Mcfe for both the three-month periods ended September 30, 2008 and 2007.

Drilling and services expenses, which includes operating expenses of the drilling, oil services and CO₂ services companies, increased to $8.2 million for the three months ended September 30, 2008 from $6.8 million for the comparable period in 2007. The increase was primarily attributable to a one-time payment and severance tax on CO₂recorded during the 2008 period.

Midstream and marketing expenses increased $37.5 million, or 259.4%, to $51.9 million due to the larger production volumes transported and marketed on behalf of third parties during the three months ended September 30, 2008 than during the comparable period in 2007.

DD&A for our natural gas and crude oil properties increased to $72.0 million for the three months ended September 30, 2008 from $45.2 million in the same period in 2007. DD&A per Mcfe increased $0.03 to $2.84 in the third quarter of 2008 from $2.81 in the comparable period in 2007. The increase was primarily attributable to an increase in our depreciable properties, higher future development costs and increased production. Our production increased 57.7% to 25.3 Bcfe from 16.1 Bcfe in the three months ended September 30, 2007.

DD&A for our other assets consists primarily of depreciation of our drilling rigs, midstream gathering and compression facilities and other equipment. The increase in DD&A for our other assets was attributable primarily to higher carrying costs of our rigs, due to upgrades and retrofitting during 2007, and our midstream gathering and processing assets, due to upgrades made throughout 2007 and the first nine months of 2008. 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 39 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life.

General and administrative expenses increased $8.8 million to $29.2 million for the three months ended September 30, 2008 from $20.4 million for the comparable period in 2007. The increase was principally attributable to a $9.7 million increase in corporate salaries and wages due to a significant increase in corporate and support staff.

As of September 30, 2008, we had 2,504 employees compared to 2,205 at September 30, 2007. General and administrative expenses include non-cash stock compensation expense of $5.5 million for the three months ended September 30, 2008 compared to $2.7 million for the same period in 2007. The increases in salaries and wages as well as stock compensation were partially offset by $6.3 million in capitalized general and administrative expenses for the three months ended September 30, 2008. There were no general and administrative expenses capitalized during the three months ended September 30, 2007.

Due to an overall decline in natural gas and crude oil prices, we recorded a gain of $292.5 million ($319.8 million unrealized gain and $27.3 million realized loss) on our derivative contracts for the three-month period ended September 30, 2008, compared to a $39.2 million gain ($19.3 million unrealized gain and $19.9 million realized gain) for the same period in 2007. The unrealized gain recorded in the third quarter of 2008 was a result of the decrease in average natural gas and crude oil commodity prices from June 30, 2008 to September 30, 2008.

Other Income (Expense). Total net other expense increased to $40.2 million in the three-month period ended September 30, 2008 from $26.9 million in the three-month period ended September 30, 2007. The decrease is reflected in the table below.


	Three Months Ended
	September 30,
	2008			2007			$ Change			% Change
	(In thousands)

Other income (expense):
Interest income	$	923		$	544		$	379			69.7	%
Interest expense		(41,026	)		(28,522	)		(12,504	)		43.8	%
Minority interest		(2	)		(164	)		162			(98.8	)%
(Loss) income from equity investments		(60	)		1,235			(1,295	)		(104.9	)%
Other income, net		(83	)		31			(114	)		(367.7	)%

Total other expense, net		(40,248	)		(26,876	)		(13,372	)		49.8	%

Income before income tax expense		361,039			32,840			328,199			999.4	%
Income tax expense		130,693			11,920			118,773			996.4	%

Net income	$	230,346		$	20,920		$	209,426			1,001.1	%

Interest income increased slightly to $0.9 million for the three months ended September 30, 2008 from $0.5 million for the same period in 2007. This increase generally was due to higher excess cash levels during third quarter 2008 compared to the same period in 2007.

Interest expense increased to $41.0 million for the three months ended September 30, 2008 from $28.5 million, net of $0.6 million of capitalized interest, for the same period in 2007. There was no interest capitalized during the three months ended September 30, 2008. The increase for the three months ended September 30, 2008 from the same period in 2007 was a result of higher average debt balances outstanding during the 2008 period compared to the same period in 2007. A $2.7 million unrealized loss related to our interest rate swap also contributed to the increase in interest expense for the three months ended September 30, 2008.

(Loss) income from equity investments decreased $1.3 million for the three months ended September 30, 2008 from the same period in 2007 primarily due to a decrease in profitability experienced by our unconsolidated equity investee, Grey Ranch, L.P. Grey Ranch L.P. operates the Grey Ranch processing plant, which was shut down on June 27, 2008 due to a fire. The plant was placed back in service on November 1, 2008.

During the three months ended September 30, 2008, income tax expense increased to $130.7 million compared to $11.9 million for the same period in 2007 due to higher net income. The current period effective tax rate of 36.2% remained relatively unchanged from that in the comparable period in 2007.

Nine months ended September 30, 2008 compared to the nine months ended September 30, 2007

Revenues. Total revenues increased 112.5% to $981.2 million for the nine months ended September 30, 2008 from $461.8 million in the same period in 2007. This increase was due to a $437.2 million increase in natural gas and crude oil sales. Lower drilling and services revenues partially offset the increase in midstream and marketing revenues.


	Nine Months Ended
	September 30,
	2008		2007		$ Change			% Change
	(In thousands)

Revenues:
Natural gas and crude oil	$	756,762	$	319,556	$	437,206			136.8	%
Drilling and services		36,345		56,928		(20,583	)		(36.2	)%
Midstream and marketing		174,240		71,131		103,109			145.0	%
Other		13,812		14,160		(348	)		(2.5	)%

Total revenues	$	981,159	$	461,775	$	519,384			112.5	%

Total natural gas and crude oil revenues increased $437.2 million to $756.8 million for the nine months ended September 30, 2008 compared to $319.6 million for the same period in 2007, primarily as a result of the increases in our natural gas and crude oil production volumes and prices received for our production. Total natural gas production increased 79.5% to 63,097 MMcf in the 2008 period compared to 35,148 MMcf in the 2007 period, while crude oil production increased 21.5% to 1,751 MBbls in the 2008 period from 1,441 MBbls in the 2007 period. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production increased 40.8% in the 2008 period to $10.28 per Mcfe compared to $7.30 per Mcfe in the 2007 period.

Drilling and services revenues decreased 36.2% to $36.3 million for the nine months ended September 30, 2008 compared to $56.9 million in the same period in 2007. The decline in revenues is due to the increase in the number of company-owned rigs operating on company-owned natural gas and crude oil properties, the increase in working interest in these properties and the decline in daily revenues earned by rigs working for third parties from the first nine months of 2007 to the first nine months of 2008.

Midstream and marketing revenues increased $103.1 million, or 145.0%, with revenues of $174.2 million in the nine-month period ended September 30, 2008 compared to $71.1 million in the nine-month period ended September 30, 2007 due to the larger third-party production volumes transported and marketed, during the nine months ended September 30, 2008 compared to the same period in 2007. Higher natural gas prices prevalent during the nine months ended September 30, 2008 compared to the first nine months of 2007 also contributed to the increase.

Operating Costs and Expenses. Total operating costs and expenses increased to $654.5 million for the nine months ended September 30, 2008 compared to $323.4 million for the same period in 2007 due to a $4.1 million loss on derivative contracts, increases in production-related costs, midstream and marketing expenses, general and administrative expenses and depreciation, depletion and amortization. These increases were partially offset by a decrease in expenses attributable to drilling and services.


	Nine Months Ended
	September 30,
	2008			2007			$ Change			% Change
	(In thousands)

Operating costs and expenses:
Production	$	115,512		$	77,707		$	37,805			48.7	%
Production taxes		29,456			12,328			17,128			138.9	%
Drilling and services		20,426			30,935			(10,509	)		(34.0	)%
Midstream and marketing		157,059			61,191			95,868			156.7	%
Depreciation, depletion, and amortization — natural gas and crude oil		209,296			115,876			93,420			80.6	%
Depreciation, depletion and amortization — other		51,342			36,545			14,797			40.5	%
General and administrative		76,432			45,781			30,651			67.0	%
Loss (gain) on derivative contracts		4,086			(55,228	)		59,314			(107.4	)%
Gain on sale of assets		(9,131	)		(1,704	)		(7,427	)		435.9	%

Total operating costs and expenses	$	654,478		$	323,431		$	331,047			102.4	%

Production expenses increased $37.8 million primarily due to the increase from September 30, 2007 to September 30, 2008 in the number of producing wells in which we have a working interest. Production taxes increased $17.1 million, or 138.9%, to $29.5 million primarily as a result of the increase in production and the increased prices received for production during the nine months ended September 30, 2008.

Drilling and services expenses decreased 34.0% to $20.4 million for the nine months ended September 30, 2008 compared to $30.9 million for the same period in 2007 primarily due to the increase in the number and working interest ownership of the wells we drilled for our own account.

Midstream and marketing expenses increased $95.9 million, or 156.7%, to $157.1 million due to the larger production volumes transported and marketed during the nine months ended September 30, 2008 on behalf of third parties compared to the same period in 2007.

DD&A for our natural gas and crude oil properties increased to $209.3 million for the nine months ended September 30, 2008 from $115.9 million in the same period in 2007. Our DD&A per Mcfe increased $0.19 to $2.84 in the first nine months of 2008 from $2.65 in the same period in 2007. The increase is primarily attributable to the increase in our depreciable properties, higher future development costs and increased production. Our production increased 68.1% to 73.6 Bcfe in the 2008 period from 43.8 Bcfe in the 2007 period.

DD&A for other assets increased to $51.3 million for the nine months ended September 30, 2008 from $36.5 million for the comparable period of 2007 due to the higher average carrying costs of our drilling rigs and gathering and compression facilities during the 2008 period compared to the 2007 period.

General and administrative expenses increased $30.7 million to $76.4 million for the nine months ended September 30, 2008 from $45.8 million for the same period in 2007. The increase was principally attributable to a $30.9 million increase in corporate salaries and wages due to the significant increase in corporate and support staff. General and administrative expenses include non-cash stock compensation expense of $12.8 million for the nine months ended September 30, 2008 compared to $5.0 million for the same period in 2007. The increases in salaries and wages as well as stock compensation were partially offset by $13.9 million in capitalized general and administrative expenses for the nine months ended September 30, 2008. There were no general and administrative expenses capitalized during the nine months ended September 30, 2007.

For the nine-month period ended September 30, 2008, we recorded a loss of $4.1 million ($73.9 million unrealized gain and $78.0 million realized loss) on our derivative contracts compared to a $55.2 million gain ($36.1 million unrealized gain and $19.1 million realized gain) for the same period in 2007. The unrealized loss

recorded in the nine-month period ended September 30, 2008 resulted primarily from increases in natural gas and crude oil commodity prices from December 31, 2007 to September 30, 2008 as compared to our contract positions.

Gain on sale of assets increased to $9.1 million in the nine months ended September 30, 2008 compared to $1.7 million in the same period in 2007, primarily due to the $7.5 million gain associated with our sale of assets located in the Piceance Basin of Colorado in May 2008.

Other Income (Expense). Total net other expense increased to $84.0 million in the nine-month period ended September 30, 2008 from $81.4 million in the nine-month period ended September 30, 2007. The decrease is reflected in the table below.


	Nine Months Ended
	September 30,
	2008			2007			$ Change			% Change
	(In thousands)

Other income (expense):
Interest income	$	3,068		$	3,671		$	(603	)		(16.4	)%
Interest expense		(88,421	)		(88,630	)		209			(0.2	)%
Minority interest		(853	)		(321	)		(532	)		165.7	%
Income from equity investments		1,355			3,399			(2,044	)		(60.1	)%
Other income, net		856			530			326			61.5	%

Total other expense, net		(83,995	)		(81,351	)		(2,644	)		3.3	%

Income before income tax expense		242,686			56,993			185,693			325.8	%
Income tax expense		89,308			21,002			68,306			325.2	%

Net income	$	153,378		$	35,991		$	117,387			326.2	%

Interest income decreased slightly to $3.1 million for the nine months ended September 30, 2008 from $3.7 million in the same period in 2007. This decrease generally was due to lower excess cash levels during the nine months ended September 30, 2008 compared to the same period in 2007.

Interest expense remained relatively unchanged at $88.4 million, net of $0.4 million of capitalized interest, for the nine months ended September 30, 2008 from $88.6 million, net of $1.5 million of capitalized interest, for the same period in 2007. During the nine months ended September 30, 2008, the gain of $7.7 million on our interest rate swap partially offset the increase in interest expense due to higher average debt balances outstanding during the period compared to the same period in 2007. In March 2007, the unamortized debt issuance costs related to our senior bridge facility were expensed, resulting in higher interest expense.

Income from equity investments decreased to $1.4 million for the nine months ended September 30, 2008, from $3.4 million in the same period in 2007 due to decreases in profitability experienced by our unconsolidated equity investees, Larclay and Grey Ranch, L.P.

During the nine months ended September 30, 2008, income tax expense increased to $89.3 million compared to $21.0 million for the same period in 2007 primarily due to higher net income. The effective tax rate remained relatively unchanged between the two periods.

Liquidity and Capital Resources

Summary

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

The debt and equity capital markets have recently experienced adverse conditions. Continued volatility in the capital markets may increase costs associated with issuing debt instruments due to increased interest rate spreads and affect our ability to access these markets. Currently, we do not believe our liquidity has been, or in the near future will be, materially affected by recent events in the global financial markets. Nevertheless, we continue to monitor events and circumstances surrounding each of the 27 lenders under our senior credit facility. To date, the only disruption in our ability to access the full amounts available under our senior credit facility was the bankruptcy of Lehman Brothers Commodity Services, Inc. (“Lehman Brothers”), a lender responsible for 0.29% of the obligations under our senior credit facility. We cannot predict with any certainty the impact to us of any further disruptions in the credit markets.

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


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

Total	$	794.7

In May 2008, we privately placed $750.0 million of our 8.0% Senior Notes due 2018. We used $478.0 million of the $735.0 million net proceeds received from the offering to repay the total balance outstanding on our senior credit facility. The remaining proceeds were used to fund a portion of our capital expenditures budget for 2008.

As of September 30, 2008, our cash and cash equivalents were $0.9 million, and we had approximately $906.5 million undrawn under our senior credit facility. Amounts outstanding under our senior credit facility at September 30, 2008 totaled $166.5 million. As of September 30, 2008, we had approximately $2.0 billion in total debt outstanding.

Capital Expenditures

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

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


	Nine Months Ended
	September 30,
	2008		2007
	(In thousands)

Capital Expenditures:
Exploration and production	$	1,404,067	$	706,550
Drilling and oil field services		61,540		104,796
Midstream gas services		110,125		45,427
Other		33,623		38,387

Total	$	1,609,355	$	895,160

We estimate that our total capital expenditures for 2008, excluding acquisitions, will be approximately $2.0 billion. As in 2007, our 2008 capital expenditures for our exploration and production segment will be focused on growing and developing our reserves and production on our existing acreage and acquiring additional leasehold interests, primarily in the WTO. Of our total $2.0 billion capital expenditure budget, approximately $1.76 billion is budgeted for exploration and production activities, including $1.36 billion for drilling and $0.4 billion for the acquisition of leases and seismic data.

We continue to upgrade and modernize our rig fleet. We expect to spend approximately $65.0 million of our 2008 capital expenditure budget on our drilling and oil field services segment. During 2008, we completed our rig fleet expansion program that we began in 2005. Final delivery of all of the rigs ordered from Chinese manufacturers occurred during 2007, and a portion of these rigs had been retrofitted. All of these rigs joined our fleet by second quarter 2008.

We anticipate spending approximately $176.0 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.

For 2009, we have budgeted $1.0 billion for capital expenditures, excluding acquisitions. Based upon the current level of operations and anticipated growth, we believe our cash flows from operations, current cash and investments on hand, availability under our senior credit facility and anticipated proceeds from the sale of our East Texas and North Louisiana properties, together with potential access to the capital and credit markets, will be sufficient to meet our capital expenditures budget, debt service requirements and working capital needs for the next 12 months. The majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels or we are unable to obtain capital on attractive terms. We may increase or decrease planned capital expenditures depending on natural gas prices, asset sales and the availability of capital through the issuance of additional long-term debt or equity. However, our ongoing ability to meet our debt service and other obligations will be dependent on our future performance which will be subject to business, financial and other factors. We will not be able to control many of these factors, such as economic conditions in the markets where we operate and future volatility in natural gas and crude oil prices.

Working Capital

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

At September 30, 2008, we had a working capital deficit of $102.4 million compared to a deficit of $5.7 million at December 31, 2007. The working capital deficit at September 30, 2008 is primarily a result of an increase of $98.9 million in accounts payable due to an increase in our drilling program.

Cash Flows

Our cash flows for the nine months ended September 30, 2008 and 2007 were as follows:


	Nine Months Ended
	September 30,
	2008			2007
	(In thousands)

Cash flows provided by operating activities	$	534,368		$	239,556
Cash flows used in investing activities		(1,457,102	)		(897,341	)
Cash flows provided by financing activities		860,497			650,850

Net decrease in cash and cash equivalents	$	(62,237	)	$	(6,935	)

Operating Activities. Net cash provided by operating activities for the nine months ended September 30, 2008 and 2007 was $534.4 million and $239.6 million, respectively. The increase in cash provided by operating activities from 2007 to 2008 was primarily due to a 68.1% increase in production volumes as a result of our drilling activities in the WTO as well as various acquisitions throughout 2007 and the first nine months of 2008. Also, contributing to this increase was a 40.8% increase in the combined average prices we received for the natural gas and crude oil produced. These increases were partially offset by increases in general and administrative costs, such as salaries and wages.

Investing Activities. Cash flows used in investing activities increased to $1,457.1 million in the nine-month period ended September 30, 2008 from $897.3 million in the comparable 2007 period as we continued to ramp up our capital expenditure program. For the nine-month period ended September 30, 2008, our capital expenditures were $1.4 billion in our exploration and production segment, $61.5 million for drilling and oil field services, $110.1 million for midstream gas services and $33.6 million for other capital expenditures. During the same period in 2007, capital expenditures were $706.6 million in our exploration and production segment, $104.8 million for drilling and oil field services, $45.4 million for midstream gas services and $38.4 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 to $1.8 billion for the nine months ended September 30, 2008 from $1.3 billion in the same period in 2007, mainly as a result of our issuance of $750.0 million in 8.0% Senior Notes due 2018 in May 2008. We repaid approximately $864.1 million during the first nine months of 2008, leaving net borrowings of approximately $904.6 million at the end of the period. Our financing activities provided $860.5 million in cash for the nine-month period ended September 30, 2008 compared to $650.9 million in the same period in 2007.

Indebtedness

Senior Credit Facility. On November 21, 2006, we entered into a $750.0 million senior secured revolving credit facility with Bank of America, N.A., as Administrative Agent. The senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid without restriction so long as we are in compliance with its terms, including certain financial covenants.

The senior credit facility bank group is comprised of 27 financial institutions. The largest commitment from any lender in the syndicate is 6.31% of the facility. The credit agreement for the facility contains various covenants that limit our ability and that of certain of our subsidiaries to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the senior credit facility limits our ability and the ability of certain of our subsidiaries to incur additional indebtedness with certain exceptions, including under the senior notes (as discussed below).

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

The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), which may not exceed 4.5:1.0 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) ratio of EBITDAX to interest expense plus current maturities of long-term debt, which must be at least 2.5:1.0 calculated using the last four completed fiscal quarters, and (iii) current ratio, which must be at least 1.0:1.0. As of September 30, 2008, we were in compliance with all of the financial 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 of our intercompany debt and our subsidiaries; and substantially all of our assets and the assets of our guarantor subsidiaries, including proved natural gas and crude oil reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of our proved natural gas and crude oil reserves reviewed in determining the borrowing base for the senior credit facility (as determined by the administrative agent). Additionally, the obligations under the senior credit facility are guaranteed by certain of our subsidiaries.

At our election, interest under the senior credit facility is determined by reference to (i) LIBOR plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the

prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rate paid on amounts outstanding under our senior credit facility for the three-month and nine-month periods ended September 30, 2008 was 4.52% and 4.32%, respectively.

The borrowing base of the senior credit facility is subject to review semi-annually; however, the lenders reserve the right to have one additional redetermination of the borrowing base per calendar year. Unscheduled redeterminations may be made at our request, but are limited to two requests per year. The borrowing base is determined based on proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves and was $1.1 billion as of September 30, 2008. As of September 30, 2008, we had total outstanding indebtedness of $166.5 million under our senior credit facility, including outstanding letters of credit of $22.0 million. In April 2008, the committed loan amount for the facility was increased to $1.75 billion and the borrowing base was increased to $1.2 billion. After our private placement of $750.0 million of senior notes in May 2008 described below under “— 8.0% Senior Notes due 2018”, we caused the borrowing base to be reduced to $1.1 billion. As of November 3, 2008, the balance outstanding under our senior credit facility was $415.6 million and total undrawn under our senior credit facility was $654.9 million.

Other Indebtedness. We have financed a portion of our drilling rig fleet and related oil field services equipment through notes. At September 30, 2008, the aggregate outstanding balance of these notes was $36.7 million, with annual fixed interest rates ranging from 7.64% to 8.67%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments of principal and interest in the amount of $1.2 million and are secured by the equipment. The notes have a prepayment penalty (currently ranging from 1% to 3%) that is triggered if we repay the notes prior to maturity.

On November 15, 2007, we entered into a $20.0 million note payable, which is fully secured by one of the buildings and a parking garage located on our property in downtown Oklahoma City, Oklahoma. We purchased the property in July 2007 to serve as our corporate headquarters. The mortgage bears interest at 6.08% per annum, and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date. We expect to make payments of principal and interest on this note totaling $0.8 million and $1.2 million, respectively, during 2008.

We have financed the purchase of other equipment used in our business. At September 30, 2007, the aggregate outstanding balance on these financings was $6.2 million. We substantially repaid such borrowings during July 2007.

8.625% Senior Term Loan and Senior Floating Rate Term Loan. On March 22, 2007, we issued $1.0 billion principal amount of unsecured senior term loans. A portion of the proceeds of the senior term loans was used to repay the senior bridge facility described below under “— Senior Bridge Facility.” The senior term loans included both a floating rate tranche and fixed rate tranche as described below.

We issued a $350.0 million senior term loan at a variable rate with interest payable quarterly and principal due on April 1, 2014. The variable rate term loan bore interest, at our option, at LIBOR plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%.

We also issued a $650.0 million senior term loan at a fixed rate of 8.625% per annum with principal due on April 1, 2015. Under the terms of the fixed rate term loan, interest was payable quarterly and during the first four years interest could be paid, at our option, either entirely in cash or entirely with additional fixed rate term loans.

As discussed below, the senior term loans were exchanged pursuant to the senior term loan credit agreement.

8.625% Senior Notes Due 2015 and Senior Floating Rate Notes Due 2014. On May 1, 2008, we completed an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. We issued $650.0 million of 8.625% Senior Notes due 2015 in exchange for an equal outstanding principal amount of our fixed rate term loan and $350.0 million of Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of our variable rate term loan. 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.

In conjunction with the issuance of the senior notes, we agreed to file a registration statement with the SEC in connection with our offer to exchange the notes for substantially identical notes that are registered under the Securities Act of 1933, as amended (the “Securities Act”). We filed a registration statement relating to the exchange offer during the third quarter 2008, and all unregistered notes had been exchanged for registered notes by October 27, 2008.

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

On or after April 1, 2011, we may redeem some or all of the 8.625% Senior Notes at specified redemption prices. On or after April 1, 2009, we may redeem some or all of the Senior Floating Rate Notes at specified redemption prices.

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

8.0% Senior Notes Due 2018. In May 2008, we privately placed $750.0 million of our unsecured 8.0% Senior Notes due 2018. We used $478.0 million of the $735.0 million net proceeds to repay the total balance outstanding at that time on our senior credit facility. The remaining proceeds were used to fund a portion of our 2008 capital expenditure program. The notes bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices.

In conjunction with the issuance of the 8.0% Senior Notes, we entered into a Registration Rights Agreement requiring us to register these notes by May 19, 2009 if they are not already freely tradable by that time. We are required to pay additional interest if we fail to fulfill our obligations under the agreement within specified time periods. We expect the notes to become freely tradable 180 days after their issuance pursuant to Rule 144 under the Securities Act.

We incurred $15.8 million of debt issuance costs in connection with the 8.0% Senior Notes. These costs are being amortized over the term of these senior notes.

Debt covenants under all of the senior notes include financial covenants similar to those of the senior credit facility and included limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties and consolidation or merger agreements. As of September 30, 2008, we were in compliance with all of the covenants under all of the senior notes.

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

Redeemable Convertible Preferred Stock

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

During March 2008, holders of 339,823 shares of our redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of our common stock. In May 2008, we converted the remaining outstanding 1,844,464 shares of our redeemable convertible preferred stock into 18,810,260 shares of our common stock as permitted under the terms of the redeemable convertible preferred stock. These conversions resulted in total

charges to retained earnings of $7.2 million in accelerated accretion expense related to the converted redeemable convertible preferred shares. We paid all dividends on our redeemable convertible preferred stock in cash, including $33.3 million in 2007 and $17.6 million in 2008. On and after the conversion date, dividends ceased to accrue and the rights of common unit holders to exercise outstanding warrants to purchase shares of redeemable convertible preferred stock terminated.


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

General

The following discussion provides information about the financial instruments we use to manage commodity price and interest rate volatility. All contracts are financial contracts, which are settled in cash and do not require the delivery of a physical quantity to satisfy settlement.

Commodity Price Risk. Our most significant market risk is the prices we receive for our natural gas and crude oil production. For example, crude oil prices have declined from a record high of $147.55 per barrel in July 2008 to approximately $62.73 per barrel in October 2008. Meanwhile, natural gas futures prices during 2008 have ranged from as high as $14.27 per Mcf in July 2008 to as low as $6.12 per Mcf in October 2008. In light of the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of natural gas and crude oil prices we receive for our production. From time to time, we enter into commodity pricing derivative contracts for a portion of our anticipated production volumes depending upon management’s view of opportunities under the then current market conditions. We do not intend to enter into derivative contracts that would exceed our expected production volumes for the period covered by the derivative arrangement. Our current credit agreement limits our ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. Future credit agreements could require a minimum level of commodity price hedging.

The use of derivative contracts also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We currently have 17 approved derivative counterparties, 16 of which are lenders under our senior credit facility. We currently have derivative contracts outstanding with 12 of these counterparties. We have no trades in 2009 and beyond with counterparties outside of those that are also part of our senior credit facility. Lehman Brothers is a counterparty on one of our derivative contracts; however, our position on this contract is immaterial. Due to the bankruptcy of Lehman Brothers and the declaration of bankruptcy by its parent, Lehman Brothers Holdings, Inc., we have not assigned any value to this derivative contract at September 30, 2008.

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

Our fixed price swap transactions are settled based upon NYMEX and our basis protection swap transactions are settled based upon the index price of natural gas at the Waha hub, a West Texas gas marketing and delivery center. Settlement for natural gas derivative contracts occurs in the production month. Generally, our trade counterparties are affiliates of the financial institution that is a party to our credit agreement, although we do have transactions with counterparties that are not affiliated with this institution.

While we believe that the natural gas and crude oil price derivative arrangements we enter into are important to our program to manage price variability for our production, we have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which reflects changes in natural gas and crude oil prices. We establish fair value of our derivative contracts by price quotations obtained from counterparties to the derivative contracts. Changes in fair values of our derivative contracts are recognized as unrealized gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in fair value of our commodities derivative arrangements. Changes in fair value are principally measured based on period-end prices compared to the contract price.

Cash settlements and valuation gains and losses on commodity derivative contracts are included in loss (gain) on derivative contracts in the consolidated statements of operations. The following table summarizes the cash settlements and valuation gains and losses on our natural gas and crude oil commodity derivative contracts for the nine months ended September 30, 2008 and 2007:


	Nine Months Ended
	September 30,
	2008			2007
	(In thousands)

Realized loss (gain)	$	77,954		$	(19,176	)
Unrealized gain		(73,868	)		(36,052	)

Loss (gain) on derivative contracts	$	4,086		$	(55,228	)

At September 30, 2008, our open natural gas and crude oil commodity derivative contracts consisted of the following:

Natural Gas


	Notional		Weighted Avg.
Period and Type of Contract	(MMcf)(1)		Fixed Price

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		16,200	$	9.60
Basis swap contracts		16,200	$	(0.74	)
April 2009 — June 2009
Price swap contracts		10,920	$	8.79
Basis swap contracts		16,380	$	(0.74	)
July 2009 — September 2009
Price swap contracts		8,590	$	8.97
Basis swap contracts		16,560	$	(0.74	)
October 2009 — December 2009
Price swap contracts		8,280	$	9.40
Basis swap contracts		16,560	$	(0.74	)
January 2010 — March 2010
Basis swap contracts		8,100	$	(0.71	)
April 2010 — June 2010
Basis swap contracts		8,190	$	(0.71	)
July 2010 — September 2010
Basis swap contracts		8,280	$	(0.71	)
October 2010 — December 2010
Basis swap contracts		8,280	$	(0.71	)
January 2011 — March 2011
Basis swap contracts		1,350	$	(0.47	)
April 2011 — September 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	)


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

Crude Oil


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

October 2008 — December 2008
Price swap contracts		225	$	93.17
Collar contracts		27	$	50.00 — 82.60
January 2009 — March 2009
Price swap contracts		45	$	126.38
April 2009 — June 2009
Price swap contracts		46	$	126.71
July 2009 — September 2009
Price swap contracts		46	$	126.61
October 2009 — December 2009
Price swap contracts		46	$	126.51

Credit Risk. Credit risk relates to the risk of loss as a result of non-performance by one or more of our counterparties under any of our credit facilities. Recently, the ability of certain investment banks and other financial institutions to meet their financial obligations has been of increasing concern. A portion of our liquidity is concentrated in derivative contracts that enable us to mitigate a portion of our exposure to natural gas and crude oil prices and interest rate volatility. We periodically review the credit quality of each counterparty to our derivative contracts and the level of financial exposure we have to each counterparty to limit our credit risk exposure with respect to these contracts.

A counterparty to one of our derivative contracts, Lehman Brothers, declared bankruptcy on October 3, 2008. The Company’s position on this derivative contract is immaterial. Due to Lehman Brothers’ bankruptcy and the declaration of bankruptcy by its parent, Lehman Brothers Holdings, Inc. on September 15, 2008, the Company has not assigned any value to this derivative contract as of September 30, 2008.

Similarly, our ability to fund our capital expenditure budget is partially dependent upon the availability of funds under our senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in our senior credit facility, our bank group consists of 27 financial institutions with commitments ranging from 0.25% to 6.31%. Lehman Brothers is a lender under our senior credit facility. As a result of its bankruptcy and the declaration of bankruptcy by its parent company, Lehman Brothers Holdings, Inc. on September 15, 2008, Lehman Brothers elected not to fund its pro rata share, or 0.29%, of borrowings requested by us under the facility. Although we do not currently expect this reduced availability of amounts under the senior credit facility to impact our liquidity or business operations, the inability of one or more of our other lenders to fund their obligations under the facility could have a material effect on our financial condition.

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

We use sensitivity analysis to determine the impact that market risk exposures may have on our variable interest rate borrowings. Based on the $350.0 million outstanding balance of our Senior Floating Rate Notes at September 30, 2008, a one percent change in the applicable rates, with all other variables held constant, would have resulted in a change in our interest expense of approximately $2.6 million for the nine months ended September 30, 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 agreement. In January 2008, we entered into a $350.0 million notional amount interest rate swap agreement with a financial institution that effectively fixed our

financial markets may not restore consumer confidence, stabilize the markets or increase liquidity and the availability of credit.

In addition, we could be required to write down the carrying value of our crude oil and natural gas properties if crude oil and natural gas prices continue to decrease. We do not have an impairment of these assets at September 30, 2008. However, if crude oil and natural gas prices were to drop below the current level, it is possible an impairment of these assets could exist at December 31, 2008.


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

As part of our incentive compensation program, we make required tax payments on behalf of employees as their restricted stock awards vest and then withhold a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The shares withheld are recorded as treasury shares. During the quarter ended September 30, 2008, the following shares of common stock 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

July 1, 2008 — July 31, 2008

26,392

61.12

N/A

August 1, 2008 — August 31, 2008

237

35.00

N/A

September 1, 2008 — September 30, 2008

190

33.01

N/A


ITEM 6.	*Exhibits*

See the Exhibit Index accompanying this report.

EXHIBIT INDEX


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

	3	.1	Certificate of Incorporation	3.1 to Registration Statement on Form S-1 filed on January 30, 2008	333-148956

	3	.2	Bylaws	3.3 to Quarterly Report on Form 10-Q filed on May 8, 2008	1-33784

	10	.1†	Executive Nonqualified Excess Plan dated as of July 11, 2008	10.1 to Current Report on Form 8-K/A filed on July 16, 2008	1-33784

	10	.2	Purchase and Sale Agreement, dated October 9, 2008, among the Company and Tom L. Ward, TLW Investments, L.L.C. and TLW Holdings, L.L.C	10.1 to Current Report on Form 8-K filed on October 16, 2008	1-33784

	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	*

	100	.INS	XBRL Instance Document	*

	100	.SCH	XBRL Taxonomy Extension Schema Document	*

	100	.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	*

	100	.LAB	XBRL Taxonomy Extension Label Linkbase Document	*

	100	.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	*

	100	.DEF	XBRL Taxonomy Extension Definition Document	*


†		Management contract or compensatory plan or arrangement


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Depreciation, Depletion and Amortization:
Exploration and production	$	72,702	$	45,643	$	211,290	$	117,329
Drilling and oil field services		10,015		10,092		31,707		25,962
Midstream gas services		4,057		1,688		10,190		4,182
Other		2,787		2,036		7,451		4,948

Total depreciation, depletion and amortization	$	89,561	$	59,459	$	260,638	$	152,421


PART I. FINANCIAL INFORMATION
ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statement of Changes in Stockholders’ Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	47
ITEM 4.	Controls and Procedures	50
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	50
ITEM 1A.	Risk Factors	50
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
ITEM 6.	Exhibits	51
EX-31.1
EX-31.2
EX-32.1
INSTANCE DOCUMENT
SCHEMA DOCUMENT
CALCULATION LINKBASE DOCUMENT
LABELS LINKBASE DOCUMENT
PRESENTATION LINKBASE DOCUMENT
DEFINITION LINKBASE DOCUMENT