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

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

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

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on ~~April~~July 30, 2010, was ~~210,732,588.~~405,104,814.

This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. These forward-looking statements include statements about our projections and estimates concerning capital expenditures, our liquidity and capital resources, effects of ~~our pending~~the acquisition of Arena Resources, Inc. (“Arena”) on our financial condition and financial results, ~~timing and likelihood of consummation of our pending acquisition of Arena,~~ 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, 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 risks associated with our ability to ~~consummate our pending acquisition of Arena and to~~ realize the benefits anticipated from ~~such~~the acquisition of Arena, as well as the risk factors discussed in Item 1A of this Quarterly Report and of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 (the “2009 Form 10-K”). 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, business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.


	March 31, 2010			December 31, 2009			June 30, 2010			December 31, 2009
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,571		$	7,861		$	2,083		$	7,861
Accounts receivable, net		96,155			105,476			103,409			105,476
Derivative contracts		141,569			105,994			63,737			105,994
Inventories		3,741			3,707			4,295			3,707
Costs in excess of billings		31,965			12,346			46,452			12,346
Other current assets		14,216			20,580			6,150			20,580

Total current assets		290,217			255,964			226,126			255,964

Oil and natural gas properties, using full cost method of accounting
Proved		6,160,856			5,913,408			6,356,837			5,913,408
Unproved		226,452			281,811			249,840			281,811
Less: accumulated depreciation, depletion and impairment		(4,272,882	)		(4,223,437	)		(4,322,819	)		(4,223,437	)

		2,114,426			1,971,782			2,283,858			1,971,782

Other property, plant and equipment, net		482,183			461,861			499,915			461,861
Restricted deposits		27,820			32,894			27,860			32,894
Derivative contracts								25,792			—
Other assets		57,019			57,816			65,112			57,816

Total assets	$	2,971,665		$	2,780,317		$	3,128,663		$	2,780,317

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	10,367		$	12,003		$	9,610		$	12,003
Accounts payable and accrued expenses		303,603			203,908			315,893			203,908
Derivative contracts		7,590			7,080			7,480			7,080
Asset retirement obligation		2,553			2,553			2,553			2,553

Total current liabilities		324,113			225,544			335,536			225,544

Long-term debt		2,610,410			2,566,935			2,749,423			2,566,935
Other long-term obligations		16,257			14,099			15,348			14,099
Derivative contracts		80,614			61,060			31,419			61,060
Asset retirement obligation		111,601			108,584			115,475			108,584

Total liabilities		3,142,995			2,976,222			3,247,201			2,976,222

Commitments and contingencies (Note 14)
Equity:
SandRidge Energy, Inc. stockholders’ equity:
Preferred stock, $0.001 par value, 50,000 shares authorized:
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at March 31, 2010 and December 31, 2009; aggregate liquidation preference of $265,000		3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at March 31, 2010 and December 31, 2009; aggregate liquidation preference of $200,000		2			2
Common stock, $0.001 par value, 400,000 shares authorized; 212,961 issued and 210,788 outstanding at March 31, 2010 and 210,581 issued and 208,715 outstanding at December 31, 2009		204			203
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at June 30, 2010 and December 31, 2009; aggregate liquidation preference of $265,000								3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at June 30, 2010 and December 31, 2009; aggregate liquidation preference of $200,000								2			2
Common stock, $0.001 par value, 400,000 shares authorized; 212,836 issued and 210,600 outstanding at June 30, 2010 and 210,581 issued and 208,715 outstanding at December 31, 2009								204			203
Additional paid-in capital		2,969,652			2,961,613			2,978,252			2,961,613
Treasury stock, at cost		(28,283	)		(25,079	)		(28,726	)		(25,079	)
Accumulated deficit		(3,124,094	)		(3,142,699	)		(3,079,210	)		(3,142,699	)

Total SandRidge Energy, Inc. stockholders’ (deficit) equity		(182,516	)		(205,957	)		(129,475	)		(205,957	)
Noncontrolling interest		11,186			10,052			10,937			10,052

Total (deficit) equity		(171,330	)		(195,905	)		(118,538	)		(195,905	)

Total liabilities and equity	$	2,971,665		$	2,780,317		$	3,128,663		$	2,780,317

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


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009			2010			2009
	(Unaudited)									(Unaudited)
Revenues:
Oil and natural gas	$	169,585		$	121,241		$	149,995		$	103,039		$	319,580		$	224,280
Drilling and services		5,760			6,311			3,901			5,097			9,661			11,408
Midstream and marketing		27,988			25,956			22,598			19,642			50,587			45,598
Other		7,661			5,505			5,945			6,321			13,606			11,826

Total revenues		210,994			159,013			182,439			134,099			393,434			293,112

Expenses:
Production		50,272			45,734			56,009			41,591			106,281			87,325
Production taxes		4,838			1,491			5,404			593			10,242			2,084
Drilling and services		7,209			4,925			1,024			5,791			8,233			10,716
Midstream and marketing		25,506			23,888			19,779			18,933			45,285			42,821
Depreciation and depletion — oil and natural gas		52,278			60,093			54,319			34,350			106,597			94,443
Depreciation, depletion and amortization — other		12,303			12,726			11,820			14,034			24,123			26,760
Impairment		—			1,304,418			—			—			—			1,304,418
General and administrative		31,674			28,485			33,865			23,632			65,539			52,117
Gain on derivative contracts		(61,952	)		(206,647	)
(Gain) loss on sale of assets		(304	)		180
(Gain) loss on derivative contracts								(119,621	)		18,992			(181,573	)		(187,655	)
Loss on sale of assets								388			26,170			84			26,350

Total expenses		121,824			1,275,293			62,987			184,086			184,811			1,459,379

Income (loss) from operations		89,170			(1,116,280	)		119,452			(49,987	)		208,623			(1,166,267	)

Other income (expense):
Interest income		69			11			98			188			167			199
Interest expense		(62,089	)		(40,748	)		(64,259	)		(42,419	)		(126,348	)		(83,167	)
Income from equity investments		—			234			—			200			—			434
Other income, net		1,236			760
Other (expense) income, net								(530	)		483			706			1,243

Total other (expense) income		(60,784	)		(39,743	)		(64,691	)		(41,548	)		(125,475	)		(81,291	)

Income (loss) before income tax expense (benefit)		28,386			(1,156,023	)
Income (loss) before income taxes								54,761			(91,535	)		83,148			(1,247,558	)
Income tax expense (benefit)		12			(1,169	)		150			(365	)		162			(1,534	)

Net income (loss)		28,374			(1,154,854	)		54,611			(91,170	)		82,986			(1,246,024	)
Less: net income attributable to noncontrolling interest		1,138			3			1,096			4			2,234			7

Net income (loss) attributable to SandRidge Energy, Inc.		27,236			(1,154,857	)		53,515			(91,174	)		80,752			(1,246,031	)
Preferred stock dividends		8,631			—			8,631			—			17,263			—

Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$	18,605		$	(1,154,857	)	$	44,884		$	(91,174	)	$	63,489		$	(1,246,031	)

Basic and diluted earnings (loss) per share:
Basic.	$	0.09		$	(7.07	)
Earnings (loss) per share:
Basic							$	0.21		$	(0.52	)	$	0.30		$	(7.38	)

Diluted	$	0.09		$	(7.07	)	$	0.20		$	(0.52	)	$	0.30		$	(7.38	)

Weighted average number of common shares outstanding:
Basic		209,145			163,321			209,161			174,154			209,153			168,767

Diluted		209,932			163,321			261,605			174,154			210,022			168,767

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


	SandRidge Energy, Inc. Stockholders																											SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock			Common Stock					Additional Paid-In Capital				Treasury Stock				Accumulated Deficit				Noncontrolling Interest			Total				Convertible Perpetual Preferred Stock					Common Stock					Additional Paid-In Capital			Treasury Stock				Accumulated Deficit				Noncontrolling Interest			Total
	Convertible Perpetual Preferred Stock											Shares								Amount							Shares			Amount								Additional Paid-In Capital			Treasury Stock				Accumulated Deficit				Noncontrolling Interest			Total
	Shares	Amount		Common Stock				Shares								Amount																						(Unaudited)
									(Unaudited)
Three months ended March 31, 2010
Six months ended June 30, 2010
Balance, December 31, 2009	4,650	$	5	208,715		$	203		$	2,961,613			$	(25,079	)		$	(3,142,699	)			$	10,052		$	(195,905	)		4,650		$	5		208,715		$	203		$	2,961,613		$	(25,079	)		$	(3,142,699	)		$	10,052		$	(195,905	)
Distributions to noncontrolling interest owners	—		—	—			—			—				—				—				(4	)		(4	)		—			—		—			—			—			—				—				(1,506	)		(1,506	)
Contributions from noncontrolling interest owners																												—			—		—			—			—			—				—				157			157
Stock issuance expense	—		—	—			—			(87	)			—				—				—			(87	)		—			—		—			—			(87	)		—				—				—			(87	)
Purchase of treasury stock	—		—	—			—			—				(2,770	)			—				—			(2,770	)		—			—		—			—			—			(2,852	)			—				—			(2,852	)
Stock purchases — retirement plans, net of distributions	—		—	(45	)		—			(18	)			(434	)			—				—			(452	)
Stock purchase — retirement plans, net of distributions																												—			—		(95	)		—			(45	)		(795	)			—				—			(840	)
Stock-based compensation	—		—	—			—			8,133				—				—				—			8,133			—			—		—			—			16,758			—				—				—			16,758
Stock-based compensation excess tax benefit	—		—	—			—			12				—				—				—			12			—			—		—			—			14			—				—				—			14
Issuance of restricted stock awards, net of cancellations	—		—	2,118			1			(1	)			—				—				—			—			—			—		1,980			1			(1	)		—				—				—			—
Net income	—		—	—			—			—				—				27,236				1,138			28,374			—			—		—			—			—			—				80,752				2,234			82,986
Convertible perpetual preferred stock dividends	—		—	—			—			—				—				(8,631	)			—			(8,631	)		—			—		—			—			—			—				(17,263	)			—			(17,263	)

Balance, March 31, 2010	4,650	$	5	210,788		$	204		$	2,969,652			$	(28,283	)		$	(3,124,094	)		$	11,186		$	(171,330	)
Balance, June 30, 2010																												4,650		$	5		210,600		$	204		$	2,978,252		$	(28,726	)		$	(3,079,210	)		$	10,937		$	(118,538	)

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


	Three Months Ended March 31,						Six Months Ended June 30,
	2010			2009			2010			2009
	(Unaudited)						(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	28,374		$	(1,154,854	)	$	82,986		$	(1,246,024	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for doubtful accounts		84			—			84			62
Inventory obsolescence								124			—
Depreciation, depletion and amortization		64,581			72,819			130,720			121,203
Impairment		—			1,304,418			—			1,304,418
Debt issuance costs amortization		2,218			1,611			5,121			3,677
Discount amortization on long-term debt		519			—			1,049			—
Unrealized gain on derivative contracts		(15,511	)		(108,010	)
(Gain) loss on sale of assets		(304	)		180
Investment (income) loss		(427	)		47
Unrealized (gain) loss on derivative contracts								(12,776	)		1,823
Loss on sale of assets								84			26,350
Investment loss (income)								261			(17	)
Income from equity investments		—			(234	)		—			(434	)
Stock-based compensation		6,882			5,205			14,218			10,368
Changes in operating assets and liabilities		61,186			(45,838	)		36,588			(77,279	)

Net cash provided by operating activities		147,602			75,344			258,459			144,147

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(190,580	)		(350,184	)		(427,336	)		(524,266	)
Proceeds from sale of assets		5,606			247			6,042			253,968
Refunds of restricted deposits		5,095			—			5,095			—

Net cash used in investing activities		(179,879	)		(349,937	)		(416,199	)		(270,298	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		273,343			559,099			841,914			1,431,765
Repayments of borrowings		(232,023	)		(525,718	)		(662,869	)		(1,645,278	)
Dividends paid — preferred		(11,263	)		—			(11,263	)		—
Noncontrolling interest distributions		(4	)		(11	)		(1,506	)		(11	)
Noncontrolling interest contributions								157			—
Proceeds from issuance of convertible perpetual preferred stock, net		(87	)		243,289			(87	)		243,289
Proceeds from issuance of common stock, net								—			107,699
Stock-based compensation excess tax benefit		12			(2,113	)		14			(2,165	)
Purchase of treasury stock		(2,770	)		(513	)		(2,852	)		(522	)
Debt issuance costs		(221	)		—			(11,546	)		(8,641	)

Net cash provided by financing activities		26,987			274,033			151,962			126,136

NET DECREASE IN CASH AND CASH EQUIVALENTS		(5,290	)		(560	)		(5,778	)		(15	)
CASH AND CASH EQUIVALENTS, beginning of year		7,861			636			7,861			636

CASH AND CASH EQUIVALENTS, end of period	$	2,571		$	76		$	2,083		$	621

Supplemental Disclosure of Noncash Investing and Financing Activities:
Change in accrued capital expenditures	$	38,001		$	(53,024	)	$	50,209		$	(79,782	)
Convertible perpetual preferred stock dividends payable	$	5,814		$	—		$	14,447		$	—

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

Nature of Business. SandRidge Energy, Inc. (including its subsidiaries, the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on exploration, development and production activities. The Company also owns and operates natural gas gathering and treating facilities and carbon dioxide (“CO₂”) treating and transportation facilities and has marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc. (“Lariat”), a wholly owned subsidiary of the Company, owns and operates drilling rigs and a related oil field services business. The Company’s primary exploration, development and production areas are concentrated in west Texas. The Company also operates interests in the Mid-Continent, ~~the~~ Cotton Valley Trend in east Texas, ~~the~~ Gulf Coast and ~~the~~ Gulf of Mexico.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2009 have been derived from the audited financial statements contained in the Company’s 2009 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 2009 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2009 Form 10-K.

For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2009 Form 10-K.

Reclassifications.Certain reclassifications have been made to prior period financial statements to conform with current period presentation. These reclassifications had no impact on the Company’s financial position or results of operations.

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depend on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. The energy markets and oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on the Company’s cash flows, and while derivative contracts for the majority of expected ~~2010,~~ 2011 and 2012 oil production are in place, there are no fixed price swap contracts in place for the Company’s natural gas production beyond 2010. See Note 11 for the Company’s open oil and natural gas commodity derivative contracts. ~~In addition, the~~The Company has and will continue to need to incur capital expenditures in 2010 in order to achieve production targets contained in certain gathering and treating arrangements. The Company is dependent on the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”), along with cash flows from operating activities, to fund those capital expenditures. Based on anticipated oil and natural gas prices, ~~and~~the availability of borrowings under its senior credit facility and anticipated proceeds from the sale of assets, the Company expects to be able to fund its planned capital expenditures for 2010. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil

and natural gas reserves that may be economically ~~produced, which~~produced. These events could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. See Note 10 for discussion of the financial covenants in the senior credit facility.

Recently Adopted Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-03 (“ASU 2010-03”) to align the oil and natural gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule,Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and was effective for the year ended December 31, 2009.Modernization of the Oil and Gas Reporting Requirements was designed to modernize and update the oil and gas disclosure requirements to align with current practices and changes in technology. The Company implemented ASU 2010-03 prospectively as a change in accounting principle inseparable from a change in accounting estimate at December 31, 2009.

In December 2009, the FASB issued Accounting Standards Update 2009-17, “Consolidations — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU 2009-17”), which ~~codifies~~codified FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R)”. ASU 2009-17 represents a revision to former FASB Interpretation No. 46(R), “Consolidation of Variable Interest ~~Entities,”~~Entities” (“FIN 46(R)”), and changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting or similar rights should be consolidated. ASU 2009-17 also requires enhanced disclosures about a reporting entity’s involvement with variable interest entities. The Company implemented ASU 2009-17 on January 1, 2010 with no impact on its financial position or results of operations. See Note 6.

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value ~~Measurements~~”Measurements” (“ASU 2010-06”). ASU 2010-06 requires additional disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in ASC Topic 820, Fair Value Measurements and Disclosures. The Company implemented the new disclosures and clarifications of existing disclosure requirements under ASU 2010-06 ~~for~~effective with the first quarter ~~ended March 31,~~of 2010, except for certain disclosure requirements regarding activity in Level 3 fair value measurements which isare effective for fiscal years beginning after December 15, 2010. The implementation of ASU 2010-06 had no impact on the Company’s financial position or results of operations. See Note 3.

The Company applies the guidance provided under ASC Topic 820 to its financial assets and liabilities and nonfinancial liabilities that are measured and reported on a fair value basis. Pursuant to this guidance, the Company has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels as described in ASC Topic 820. The

determination of the fair values, stated below, takes into account the market for the Company’s financial assets and liabilities, the associated credit risk and other factors as required by ASC Topic 820. 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.

Restricted deposits. The fair value of restricted deposits is based on quoted market prices.

Other long-term assets. The fair value of other long-term assets, consisting of assets attributable to the Company’s deferred compensation plan, is based on quoted market prices.

Derivative Contracts. The fair values of the Company’s oil, natural gas and interest rate swaps are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or other market participants. Included in these models are discount factors that the Company must estimate in its calculation. Additionally, the Company applies a value weighted average credit default risk rating factor for its counterparties or gives effect to its credit risk, as applicable, in determining the fair value of its derivative contracts. Based on the inputs for the fair value measurement, the Company has classified its derivative contract assets and liabilities as Level 3.

The following tables summarize the Company’s financial assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):


	Fair Value Measurements									Assets/ Liabilities at Fair Value		Fair Value Measurements									Assets/ Liabilities at Fair Value
Description	Level 1		Level 2		Level 3		Netting(1)			Assets/ Liabilities at Fair Value		Level 1		Level 2		Level 3		Netting(1)			Assets/ Liabilities at Fair Value
Assets:
Commodity derivative contracts	$	—	$	—	$	210,322	$	(68,753	)	$	141,569	$	—	$	—	$	150,076	$	(60,547	)	$	89,529
Restricted deposits		27,820		—		—		—			27,820		27,860		—		—		—			27,860
Other long-term assets		6,992		—		—		—			6,992		6,662		—		—		—			6,662

	$	34,812	$	—	$	210,322	$	(68,753	)	$	176,381	$	34,522	$	—	$	150,076	$	(60,547	)	$	124,051

Liabilities:
Commodity derivative contracts	$	—	$	—	$	144,810	$	(68,753	)	$	76,057	$	—	$	—	$	82,898	$	(60,547	)	$	22,351
Interest rate swaps		—		—		12,147		—			12,147		—		—		16,548		—			16,548

	$	—	$	—	$	156,957	$	(68,753	)	$	88,204	$	—	$	—	$	99,446	$	(60,547	)	$	38,899


	Fair Value Measurements						Netting(1)			Assets/ Liabilities at Fair Value		Fair Value Measurements									Assets/ Liabilities at Fair Value
Description	Level 1		Level 2		Level 3		Netting(1)			Assets/ Liabilities at Fair Value		Level 1		Level 2		Level 3		Netting(1)			Assets/ Liabilities at Fair Value
Assets:
Commodity derivative contracts	$	—	$	—	$	161,197	$	(55,203	)	$	105,994	$	—	$	—	$	161,197	$	(55,203	)	$	105,994
Restricted deposits		32,894		—		—		—			32,894		32,894		—		—		—			32,894
Other long-term assets		6,251		—		—		—			6,251		6,251		—		—		—			6,251

	$	39,145	$	—	$	161,197	$	(55,203	)	$	145,139	$	39,145	$	—	$	161,197	$	(55,203	)	$	145,139

Liabilities:
Commodity derivative contracts	$	—	$	—	$	115,044	$	(55,203	)	$	59,841	$	—	$	—	$	115,044	$	(55,203	)	$	59,841
Interest rate swaps		—		—		8,299		—			8,299		—		—		8,299		—			8,299

	$	—	$	—	$	123,343	$	(55,203	)	$	68,140	$	—	$	—	$	123,343	$	(55,203	)	$	68,140

The ~~table~~tables below ~~sets~~set 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~~and six-month periods ended ~~March 31,~~June 30, 2010 and 2009 (in thousands):


	Derivatives			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, December 31, 2009	$	37,854
Three Months Ended June 30, 2010
Balance of Level 3, March 31, 2010				$	65,512		$	(12,147	)	$	53,365
Total gains or losses (realized/unrealized)		56,017			119,621			(6,477	)		113,144
Purchases, issuances and settlements		(40,506	)		(117,955	)		2,076			(115,879	)
Transfers in and out of Level 3		—			—			—			—

Balance of Level 3, March 31, 2010	$	53,365
Balance of Level 3, June 30, 2010				$	67,178		$	(16,548	)	$	50,630

Three Months Ended June 30, 2009
Balance of Level 3, March 31, 2009				$	354,905		$	(8,992	)	$	345,913
Total gains or losses (realized/unrealized)					(18,992	)		2,641			(16,351	)
Purchases, issuances and settlements					(94,747	)		1,265			(93,482	)
Transfers in and out of Level 3					—			—			—

Balance of Level 3, June 30, 2009				$	241,166		$	(5,086	)	$	236,080

During the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2010, the Company did not have any transfers in or out of Level 1, Level 2 or Level 3 fair value measurements.

See Note 11 for further discussion and total (gains) losses, realized and unrealized, included in earnings for the period of the Company’s derivative contracts.

The Company measures fair value of its long-term debt based on quoted market prices and with consideration given to the effect of the Company’s credit risk. The estimated fair ~~value~~values of the Company’s senior notes and the carrying ~~value~~values at ~~March 31,~~June 30, 2010 and December 31, 2009 were as follows (in thousands):


	March 31, 2010				December 31, 2009				June 30, 2010				December 31, 2009
	Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	324,619	$	350,000	$	316,859	$	350,000	$	313,462	$	350,000	$	316,859	$	350,000
8.625% Senior Notes due 2015		638,806		650,000		655,470		650,000		638,560		650,000		655,470		650,000
9.875% Senior Notes due 2016(1)		382,171		351,426		390,692		351,021		374,176		351,842		390,692		351,021
8.0% Senior Notes due 2018		716,775		750,000		739,778		750,000		717,416		750,000		739,778		750,000
8.75% Senior Notes due 2020(2)		443,761		442,704		451,890		442,590		432,857		442,818		451,890		442,590

The carrying ~~value for~~values of the Company’s senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 10 for further discussion of the Company’s long-term debt.


	March 31, 2010		December 31, 2009		June 30, 2010		December 31, 2009
Debt issuance costs, net of amortization	$	47,104	$	49,103	$	55,528	$	49,103
Investments		6,992		6,251		6,662		6,251
Other		2,923		2,462		2,922		2,462

Total other assets	$	57,019	$	57,816	$	65,112	$	57,816

In accordance with the guidance in ASC Topic 810, Consolidation, including the guidance in ASU 2009-17, the Company consolidates the activities of variable interest entities (“VIEs”) of which it is the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether or not the Company owns a variable interest in a VIE, ~~it performs~~ a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial ~~agreements.~~agreements is prepared.

The Company’s significant associated VIEs, including those for which the Company has determined it is the primary beneficiary and those for which it has determined it is not, are described below.

Grey Ranch, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch, L.P. (“GRLP”) is a limited partnership that operates the Company’s Grey Ranch Plant (the “Plant”) located in Pecos County, Texas. The Company has long-term operating and gathering agreements with GRLP and also owns a 50% ownership interest in GRLP. Income or losses of GRLP are allocated to the partners based on ownership percentage and any operating or cash shortfalls require contributions from the partners. The Company has determined that GRLP qualifies as a VIE under the provisions of ASC Topic 810. During October 2009, the Company executed amendments to certain agreements related to the ownership and operation of GRLP. The amended operating agreements provide for GRLP to pay management fees to the Company to operate the Plant as well as lease payments on the Plant. Under the operating agreements, lease payments are reduced if throughput volumes are below those expected. The Company has determined that it is the primary beneficiary of GRLP as it has both (i) the power to direct the activities of GRLP that most significantly impact its economic performance as operator of the Plant and (ii) the obligation to absorb losses, as a result of the operating and gathering agreements, that could potentially be significant to GRLP.

Prior to October 2009, the Company accounted for its ownership interest in GRLP using the equity method of accounting; however, due to the amendments discussed above, the Company began consolidating the activity of GRLP in its consolidated financial statements prospectively on the effective date of the amendments, October 1, 2009. The change from equity method accounting to the consolidation of GRLP activity had no effect on the Company’s net income. The ownership interest not held by the Company is presented as noncontrolling interest in the consolidated financial statements.

At ~~March 31,~~June 30, 2010 and December 31, 2009, consolidated amounts related to GRLP included total assets of ~~$19.8~~$18.1 million and $22.5 million, respectively, and total liabilities of $0.8 million and $2.0 million, respectively.

GRLP’s assets can only be used to settle its obligations. Although GRLP is included in the Company’s ~~condensed~~ consolidated financial statements, the Company’s interest in GRLP’s assets is limited to its 50% ownership. At ~~March 31,~~June 30, 2010 and December 31, 2009, ~~$11.2~~$10.9 million and $10.0 million, respectively, of noncontrolling interest in the accompanying condensed consolidated ~~financial statements~~balance sheets were related to ~~GRLP, respectively.~~GRLP. GRLP’s creditors have no recourse to the general credit of the Company.

Grey Ranch Plant Genpar, LLC. The Company owns a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP. Additionally, the Company serves as Genpar’s administrative manager. Genpar’s ownership interest in GRLP is its only asset.

As managing partner of GRLP, Genpar has the sole right to manage, control and conduct the business of GRLP. However, Genpar is restricted from making certain major decisions, including the decision to remove the Company as operator of the Plant. The rights afforded the Company under the Plant operating agreement and the restrictions on Genpar serve to limit Genpar’s ability to make decisions on behalf of GRLP. Therefore, Genpar is considered a VIE. Although both the Company and Genpar’s other equity owner share equally in Genpar’s economic losses and benefits and also have agreements that may be considered variable interests, the Company determined it was the primary beneficiary due to (i) its ability, as administrative manager, to direct the activities of Genpar that most significantly impact its performance and (ii) its obligation or right, as operator of the Plant, to absorb the losses of or receive benefits from Genpar that could potentially be significant to Genpar. As the primary beneficiary, the Company consolidates Genpar’s activity. However, its sole asset, the investment in GRLP, is eliminated in consolidation. Genpar has no liabilities.

Piñon Gathering Company, LLC.The Company has ~~20 year~~20-year gas gathering and operations and maintenance agreements with Piñon Gathering Company, LLC (“PGC”), the entity that purchased the Company’s gathering and compression assets located in the Piñon Field in June 2009. Under the gas gathering agreement, the Company is required to compensate PGC for any throughput shortfalls below a required minimum volume. By guaranteeing a minimum throughput, the Company absorbs the risk that lower than projected volumes will be gathered by the gathering system. Therefore, PGC is a VIE. While the Company operates the assets of PGC as directed under the operations and management agreement, the member and managers of PGC have the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. As the Company does not have the ~~power~~ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company is not the primary beneficiary of PGC.

Under the full cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenue from proved oil and natural gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas properties, plus the cost of properties not subject to amortization. In calculating future net revenues ~~for the three-month period ended March 31,~~as of June 30, 2010, prices and costs used ~~are~~were based on the most recent 12-month average. Prior to December 31, 2009, prices and costs used to calculate future net revenues were based on prices on the last day of the applicable period. These prices ~~are not changed~~were held constant except where different prices ~~are~~were fixed and determinable from applicable contracts for the remaining term of those contracts. The Company has entered into various commodity derivative contracts; however, these derivative contracts are not accounted for as cash flow hedges. Accordingly, the effect of these derivative contracts has not been considered in calculating the full cost ceiling limitation.

The net book value, less related deferred tax liabilities, is compared to the ceiling limitation on both a quarterly and annual basis. Any excess of the net book value, less related deferred taxes over the ceiling

limitation, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher average oil and natural gas prices may have increased the ceiling limitation in the subsequent period. During the first ~~quarter~~six months of 2009, the Company reduced the carrying value of its oil and natural gas properties by $1,304.4 million due to a full cost ceiling ~~limitation.~~limitation at March 31, 2009. There ~~was~~were no full cost ceiling ~~impairment at March 31,~~impairments during the first six months of 2010.

~~In June 2008, the~~The Company ~~entered into~~is constructing a CO₂treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with a subsidiary of Occidental Petroleum Corporation (“Occidental”) ~~to construct a CO~~₂ ~~treating plant in Pecos County, Texas (the “Century Plant”) and associated compression and pipeline facilities for $800.0 million.~~. Under ~~this~~the terms of the agreement, the Company will construct the Century Plant and Occidental will pay the Company a minimum of 100% of the contract price, or $800.0 million, plus any ~~subsequent~~subsequently agreed-upon revisions, ~~to the Company~~ through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Century Plant is expected to be completed in two phases with the start-up of Phase I expected in ~~mid~~the third quarter of 2010. Upon start-up, the Century Plant will be owned and operated by Occidental for the purpose of separating and removing CO₂ from natural gas delivered by the Company. Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO₂ from the Company’s delivered production volumes. The Company will retain all methane gas from the Century Plant.

The Company accounts for construction of the Century Plant using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract gains or losses will be recorded, as development costs within the Company’s oil and natural gas properties as part of the full cost pool, when it is determined that a gain or loss will be incurred. At ~~March 31,~~June 30, 2010 and December 31, 2009, no amounts had been recorded to the full cost pool in anticipation of probable and estimable gains or losses. Costs in excess of billings were ~~$32.0~~$46.5 million and $12.3 million and ~~are~~were reported as a current ~~asset~~assets in the accompanying condensed consolidated balance sheets at ~~March 31,~~June 30, 2010 and December 31, 2009, respectively.

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2009 to ~~March 31,~~June 30, 2010 is as follows (in thousands):


Asset retirement obligation, December 31, 2009	$	111,137		$	111,137
Liability incurred upon acquiring and drilling wells		1,073			2,779
Revisions in estimated cash flows		—			—
Liability settled in current period		(326	)		(450	)
Accretion of discount expense		2,270			4,562

Asset retirement obligation, March 31, 2010		114,154
Asset retirement obligation, June 30, 2010					118,028
Less: Current portion		2,553			2,553

Asset retirement obligation, net of current	$	111,601		$	115,475

For the three months ended June 30, 2010 and 2009, interest payments were approximately $83.3 million and $65.4 million, respectively. For the six months ended June 30, 2010 and 2009, interest payments were approximately $92.3 million and $75.4 million, respectively.

~~For the three months ended March 31, 2010 and 2009, interest payments, net of amounts capitalized, were approximately $9.0 million and $10.0 million, respectively.~~

Senior Credit Facility. The amount the Company can borrow under its senior ~~secured revolving~~ credit facility ~~(the “senior credit facility”)~~ is limited to a borrowing ~~base, which was $850.4 million at March 31, 2010.~~base. The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. In April 2010, the Company’s senior credit facility was amended and restated, affirming the borrowing base at $850.0 million and extending the maturity date to April 15, 2014. Under the terms of the amended and restated facility, the required ratio of total funded debt to EBITDAX (as defined in the senior credit facility) will decrease in future periods as described below. Additionally, the ratio of EBITDAX to interest expense plus current maturities of long-term debt was eliminated and the Company’s ability to make investments was increased from the previous terms. The remaining covenants were largely unchanged from the previous agreement and are described further below.

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

The senior credit facility contains financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDAX, ~~(as defined in the senior credit facility),~~ which may not exceed 4.5:1.0 (4.25:1.0 effective June 30, 2011 and 4.0:1.0 by June 30, 2012) at each quarter end calculated using the last four completed fiscal quarters ~~(ii) ratio~~(adjusted for annualized amounts of ~~EBITDAX to interest expense plus current maturities~~the post-acquisition results of ~~long-term debt, which must be at least 2.5:1.0 at each quarter end calculated using the last four completed fiscal quarters,~~operations of newly acquired properties/entities) and ~~(iii)~~(ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at ~~each~~ quarter end. In the current ratio calculation (as defined in the senior credit facility), any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded. As of and for the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2010, the Company was in compliance with all of the financial covenants under the senior credit facility.

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

At the Company’s election, interest under the senior credit facility is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum or (b) the ‘base rate,’ which is the higher of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 1.00% and 2.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest ~~rate~~rates paid on amounts outstanding under the senior credit facility ~~was 2.26%~~were 2.65% and 2.52% for the ~~three-month period~~three and six-month periods ended ~~March 31, 2010.~~June 30, 2010, respectively.

Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. The Company’s borrowing base is redetermined in April and October of each year. ~~See below for a discussion of the April 2010 redetermination.~~ With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider

several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. The Company has, at times, incurred additional costs related to the senior credit facility as a result of changes to the borrowing base.

At ~~March 31,~~June 30, 2010, the Company had ~~$45.2~~$186.0 million outstanding under the senior credit facility and ~~$25.6~~$25.4 million in outstanding letters of credit, which affect the availability under the senior credit facility on a dollar-for-dollar basis.

In April 2010, the Company’s senior credit facility was amended and restated, extending the maturity date to April 15, 2014 from November 21, 2011 and affirming the borrowing base at $850.0 million. The amended and restated senior credit facility contains substantially the same covenants as described above. The ratio of total funded debt to EBITDAX changes from the current limit of 4.5:1.0 to 4.25:1.0 effective June 30, 2011 and then to 4.0:1.0 by June 30, 2012. The ratio of EBITDAX to interest expense plus current maturities of long-term debt covenant has been eliminated and the Company’s ability to make investments has been increased.

Other Notes Payable. The Company has financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by such equipment. At ~~March 31,~~June 30, 2010, the aggregate outstanding balance of these notes was ~~$13.7~~$10.9 million, with annual fixed interest rates ranging from ~~7.77%~~7.84% to 8.67%. The notes have a final maturity date of December 1, 2011 and require aggregate monthly installments of principal and interest in the amount of ~~$0.7~~$0.6 million. The notes have a prepayment penalty (currently ranging from 0.50% to 1.00%) that is triggered if the Company repays the notes prior to maturity.

The debt incurred to purchase the downtown Oklahoma City property that serves as the Company’s corporate headquarters is fully secured by a mortgage on one of the buildings and a parking garage located on the property. The note underlying the mortgage bears interest at 6.08% annually and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date. During 2010, the Company expects to make payments of principal and interest on this note ~~totalling~~totaling $0.9 million and $1.1 million, respectively.

Senior Floating Rate Notes Due 2014 and 8.625% Senior Notes Due 2015. The Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) and 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”) were issued in May 2008 and are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries. See Note 19 for condensed financial information of the subsidiary guarantors.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% ~~(3.88%~~(3.92% at ~~March 31,~~June 30, 2010). Interest is payable quarterly with the principal due on April 1, 2014. The average interest ~~rate~~rates paid on the outstanding Senior Floating Rate Notes for the three months and six months ended ~~March 31,~~June 30, 2010 ~~was 3.88%~~were 3.92% and 3.90%, respectively, without consideration of the interest rate swap discussed below. The 8.625% Senior Notes bear interest at a fixed rate of 8.625% per annum with the principal due on April 1, 2015. Under the terms of the 8.625% Senior Notes, interest is payable semi-annually and, through the interest payment due on April 1, 2011, ~~interest~~ may be paid, at the Company’s option either entirely in cash or entirely with additional fixed rate senior notes. If the Company elects to pay the interest due during any period in additional fixed rate senior notes, the interest rate will increase to 9.375% during that period. All interest payments made to date on the 8.625% Senior Notes have been paid in cash. Based on the terms of the 8.625% Senior Notes, there is one remaining interest period in which the Company has the option to pay interest due in additional fixed rate senior notes.

The Company has entered into two $350.0 million notional interest rate swap agreements to fix the variable ~~LIBOR~~ interest rate on the Senior Floating Rate Notes through April 1, 2013. The first interest rate swap agreement fixes the ~~LIBOR interest~~rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 1, 2011. The second interest rate swap agreement fixes the ~~LIBOR~~ rate on the Senior Floating Rate Notes at an annual rate of 6.69% for the period

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

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

The $26.3 million of debt issuance costs associated with the Senior Floating Rate Notes and the 8.625% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

9.875% Senior Notes Due 2016. The Company’s unsecured 9.875% Senior Notes due 2016 (the “9.875% Senior Notes”) were issued in May 2009 and bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. The 9.875% Senior Notes were issued at a discount, which will be amortized into interest expense over the term of the notes. The 9.875% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor ~~subsidiaries.~~

In conjunction with the issuance of the 9.875% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to register these notes by May 16, 2010 if they are not alreadysubsidiaries, and became freely tradable at that time. 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 expects the 9.875% Senior Notes to become fully tradable on May 14, 2010.

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

8.0% Senior Notes Due 2018. The Company’s unsecured 8.0% Senior Notes due 2018 (the “8.0% Senior Notes”) were issued in May 2008 and 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 and are jointly and severally, unconditionally guaranteed on an unsecured basis, by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries, and are freely tradable.

The Company incurred $16.0 million of debt issuance costs in connection with the offering of the 8.0% Senior Notes. These costs are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

8.75% Senior Notes Due 2020. The Company’s unsecured 8.75% Senior Notes due 2020 (the “8.75% Senior Notes”) were issued in December 2009 and bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due on January 15, 2020. The 8.75% Senior Notes were issued at a discount which is amortized into interest expense over the term of the notes. The ~~notes~~8.75% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries.

In conjunction with the issuance of the 8.75% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to register these notes by December 16, 2010. The Company is required to pay additional interest if it fails to fulfill its obligations under the agreement within the specified time periods.

Debt issuance costs of $9.7 million incurred in connection with the offering of the 8.75% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.

The indentures governing all of the senior notes contain financial covenants similar to those of the senior credit facility and include limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and for the ~~three-month~~three and six-month period ended ~~March 31,~~June 30, 2010, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

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

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company ~~manages~~seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to a portion of its projected oil and natural gas sales. None of the Company’s derivative contracts may be terminated early as a result of a party to the contract having its credit rating downgraded. At ~~March 31,~~June 30, 2010 and December 31, 2009, the Company’s commodity derivative contracts consisted of fixed price swaps and basis swaps, which are described below:

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

The Company has entered into two interest rate swap agreements to manage the interest rate risk on a portion of its floating rate debt by effectively fixing the variable interest rate on its Senior Floating Rate Notes. See Note 10 for further discussion of the Company’s interest rate swaps.

Fair Value of Derivatives. In accordance with ASC Topic 815, Derivatives and Hedging, the following table presents the fair value of the Company’s derivative contracts as of ~~March 31,~~June 30, 2010 and December 31, 2009 on a gross basis without regard to same-counterparty netting (in thousands):


Type of Contract	Balance Sheet Classification	March 31, 2010			December 31, 2009			Balance Sheet Classification	June 30, 2010			December 31, 2009
Derivative assets:
Oil price swaps	Derivative contracts-current	$	9,030		$	2,849		Derivative contracts-current	$	18,158		$	2,849
Natural gas swaps	Derivative contracts-current		190,984			152,986		Derivative contracts-current		76,232			152,986
Oil price swaps	Derivative contracts-noncurrent		10,308			5,362		Derivative contracts-noncurrent		55,686			5,362

Derivative liabilities:
Oil price swaps	Derivative contracts-current		(10,248	)		(4,127	)	Derivative contracts-current		—			(4,127	)
Natural gas swaps	Derivative contracts-current		(48,350	)		(45,714	)	Derivative contracts-current		(30,924	)		(45,714	)
Interest rate swaps	Derivative contracts-current		(7,437	)		(7,080	)	Derivative contracts-current		(7,208	)		(7,080	)
Oil price swaps	Derivative contracts-noncurrent		(10,888	)		(2,262	)	Derivative contracts-noncurrent		—			(2,262	)
Natural gas swaps	Derivative contracts-noncurrent		(75,325	)		(62,941	)	Derivative contracts-noncurrent		(51,974	)		(62,941	)
Interest rate swaps	Derivative contracts-noncurrent		(4,709	)		(1,219	)	Derivative contracts-noncurrent		(9,340	)		(1,219	)

Total net derivative contracts		$	53,365		$	37,854
Total derivative contracts, net									$	50,630		$	37,854

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

The following table summarizes the effect of the Company’s derivative contracts on the accompanying condensed consolidated statements of operations for the three and six-month periods ended June 30, 2010 and 2009 (in thousands):

The following table summarizes the cash settlements and valuation gains and losses on our commodity derivative contracts for the three and six-month periods ended June 30, 2010 and 2009 (in thousands):

The following table summarizes the ~~effect of the Company’s derivative contracts on the condensed consolidated statements of operations for the three-month periods ended March 31, 2010 and 2009 (in thousands):~~

~~The following table summarizes the~~ cash settlements and valuation gains and losses on ~~the commodity derivative contracts~~our interest rate swaps for the ~~three-month~~three and six-month periods ended ~~March 31,~~June 30, 2010 and 2009 (in thousands):

Net losses of $5.9 million ($3.8 million unrealized loss and $2.1 million realized loss) and $1.3 million ($0.3 million unrealized loss and $1.0 million realized loss) related to the interest rate swaps discussed above were included in interest expense in the accompanying condensed consolidated statements of operations for the three-month periods ended March 31, 2010 and 2009, respectively.

On ~~March 31,~~June 30, 2010, the Company’s open oil and natural gas commodity derivative contracts consisted of the following:


Period and Type of Contract	Notional (in MBbls)	Weighted Avg. Fixed Price		Notional (in MBbl)	Weighted Avg. Fixed Price
April 2010 — June 2010
Price swap contracts	1,092	$	82.05
July 2010 — September 2010
Price swap contracts	1,104	$	82.05
October 2010 — December 2010
Price swap contracts	1,196	$	82.11
January 2011 — March 2011
Price swap contracts	1,260	$	86.26	1,260	$	86.26
April 2011 — June 2011
Price swap contracts	1,274	$	86.26	1,274	$	86.26
July 2011 — September 2011
Price swap contracts	1,472	$	85.90	1,472	$	85.90
October 2011 — December 2011
Price swap contracts	1,472	$	85.90	1,472	$	85.90
January 2012 — March 2012
Price swap contracts				1,638	$	87.08
April 2012 — June 2012
Price swap contracts				1,729	$	86.98
July 2012 — September 2012
Price swap contracts				1,778	$	86.96
October 2012 — December 2012
Price swap contracts				1,840	$	86.91


Period and Type of Contract	Notional (MMcf)(1)	Weighted Avg. Fixed Price			Notional (MMcf)(1)	Weighted Avg. Fixed Price
April 2010 — June 2010
Price swap contracts	19,793	$	7.32
Basis swap contracts	20,475	$	(0.74	)
July 2010 — September 2010
Price swap contracts	20,010	$	7.55
Basis swap contracts	20,700	$	(0.74	)
October 2010 — December 2010
Price swap contracts	20,010	$	7.97
Basis swap contracts	20,700	$	(0.74	)
January 2011 — March 2011
Basis swap contracts	25,650	$	(0.47	)
April 2011 — June 2011
Basis swap contracts	25,935	$	(0.47	)
July 2011 — September 2011
Basis swap contracts	26,220	$	(0.47	)	26,220	$	(0.47	)
October 2011 — December 2011
Basis swap contracts	26,220	$	(0.47	)	26,220	$	(0.47	)
January 2012 — March 2012
Basis swap contracts	28,210	$	(0.55	)	28,210	$	(0.55	)
April 2012 — June 2012
Basis swap contracts	28,210	$	(0.55	)	28,210	$	(0.55	)
July 2012 — September 2012
Basis swap contracts	28,520	$	(0.55	)	28,520	$	(0.55	)
October 2012 — December 2012
Basis swap contracts	28,520	$	(0.55	)	28,520	$	(0.55	)
January 2013 — March 2013
Basis swap contracts	3,600	$	(0.46	)	3,600	$	(0.46	)
April 2013 — June 2013
Basis swap contracts	3,640	$	(0.46	)	3,640	$	(0.46	)
July 2013 — September 2013
Basis swap contracts	3,680	$	(0.46	)	3,680	$	(0.46	)
October 2013 — December 2013
Basis swap contracts	3,680	$	(0.46	)	3,680	$	(0.46	)

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

The provision (benefit) for income taxes consisted of the following components for the ~~three-month~~three and six-month periods ended ~~March 31,~~June 30, 2010 and 2009 (in thousands):


						Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009			2010		2009
Current:
Federal	$	—	$	(2,166	)	$	—	$	(50	)	$	—	$	(2,216	)
State		12		997			150		(315	)		162		682

		12		(1,169	)		150		(365	)		162		(1,534	)

Deferred:
Federal		—		—			—		—			—		—
State		—		—			—		—			—		—

		—		—			—		—			—		—

Total provision (benefit)	$	12	$	(1,169	)		150		(365	)		162		(1,534	)
Less: income tax provision attributable to noncontrolling interest							89		—			89		—

Total provision (benefit) attributable to SandRidge Energy, Inc.						$	61	$	(365	)	$	73	$	(1,534	)

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements. Deferred tax assets are reduced by a valuation allowance as necessary when a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. As of December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. For the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2010 and 2009, the Company continued to have a full valuation allowance against its net deferred tax asset resulting in a low effective tax rate for the period.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected $305.0 million of federal net operating loss carryforwards to the IRC Section 382 limitation which could result in a material amount of these carryforwards expiring unused. The limitation did not result in a current federal tax liability at June 30, 2010 and December 31, 2009. See Note 17 for discussion of tax consequences associated with the ~~three-month period ended March 31, 2010.~~Arena Resources, Inc. (“Arena”) acquisition.

No reserves for uncertain income tax positions have been recorded pursuant to the guidance for uncertainty in income taxes under ASC Topic 740, Income Taxes. Tax years 1999 to present remain open for the majority of taxing authorities due to net operating loss carryforwards from those years. The Company’s accounting policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense. The Company did not have an accrued liability for interest and penalties at ~~March~~June 30, 2010 or December 31, ~~2010.~~2009.

For the ~~three months~~three-month period ended ~~March 31,~~June 30, 2010 and ~~March 31,~~ 2009, income tax payments, net of refunds, were approximately ~~($3.4)~~$(0.1) million and ~~($0.5)~~$3.6 million, respectively. For the six-month period ended June 30, 2010 and 2009, income tax payments, net of refunds, were approximately $(3.5) million and $3.0 million, respectively.

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during

the period, but also include the dilutive effect of awards of restricted stock and outstanding convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the ~~three-month~~three and six-month periods ended ~~March 31,~~June 30, 2010 and 2009 (in thousands):


			Three Months Ended June 30,		Six Months Ended June 30,
	2010	2009	2010	2009	2010	2009
Weighted average basic common shares outstanding	209,145	163,321	209,161	174,154	209,153	168,767
Effect of dilutive securities:
Restricted stock	787	—	948	—	869	—
Convertible preferred stock	—	—
Convertible preferred stock outstanding			51,496	—	—	—

Weighted average diluted common and potential common shares outstanding	209,932	163,321	261,605	174,154	210,022	168,767

For the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2009, restricted stock awards covering ~~4.2~~2.4 million shares and 2.5 million shares, respectively, were excluded from the computation of net loss per share because their effect would have been antidilutive.

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock and 6.0% convertible perpetual preferred stock (see Note 15) for the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2010 and its outstanding 8.5% convertible perpetual preferred stock for the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2009. 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~~For the three-month period ended June 30, 2010, the Company determined the if-converted method was more dilutive and did not include preferred stock dividends in the determination of income available to common stockholders. For the six-month period ended June 30, 2010 and the three and six-month periods ended June 30, 2009, the Company determined the if-converted method was not more dilutive and included preferred stock dividends in the determination of income available to common ~~stockholders for the three-month periods ended March 31, 2010 and 2009.~~stockholders.

On ~~April 3,~~July 16, 2010, the Company and one of its subsidiaries ~~entered into an agreement to acquire~~completed the acquisition of all of the outstanding shares of common stock of Arena for a combination of ~~company~~Company common stock and cash. ~~Since~~See Note 17. As disclosed in the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2010, after the April 3, 2010 announcement of the transaction, nine putative class action lawsuits ~~have been~~challenging the transaction were filed in Oklahoma and in Nevada by Arena ~~shareholders, purportedly on behalf of persons similarly situated, challenging the transaction. The~~stockholders. All nine lawsuits ~~contain~~contained substantially ~~the same~~similar allegations — that Arena’s directors breached their fiduciary duties by negotiating and approving the transaction and by administering a sale process that failed to maximize ~~shareholder~~stockholder value and that Arena, the Company and/or a subsidiary of the Company aided and abetted such alleged breaches of fiduciary duty. One lawsuit was filed in federal court and also alleged violations of federal securities laws in connection with allegedly issuing an incomplete and misleading proxy statement. The lawsuits ~~seek,~~sought, among other relief, an injunction preventing the consummation of the merger and, in certain cases, unspecified damages. On May 27, 2010, the Company and Arena reached an agreement in principle — and without admitting any liability or wrongdoing — for the coordinated settlement of six of the putative stockholder class actions related to the merger, including five of the lawsuits filed in state courts in Nevada and Oklahoma and the lawsuit filed in federal court. In connection with this agreement, the Company and Arena agreed to provide certain additional disclosures about the merger and to amend certain provisions of the merger agreement with respect to payment of termination fees and non-solicitation of alternative takeover proposals. The additional disclosures about the merger were made in joint Current Reports on Form 8-K filed by the Company and Arena on May 28, 2010. The three remaining lawsuits arising from the acquisition of Arena were stayed by the District Court of Oklahoma County on May 10, 2010. On July 1, 2010, the Plaintiffs commenced appellate proceedings before the Oklahoma Supreme Court challenging the stay and filed an emergency motion seeking to expedite the appeal. On July 8, 2010, the Oklahoma Supreme Court denied the emergency motion and, as of the date of this Quarterly Report, there has been no further action with respect to these proceedings. The Company believes ~~all of the~~these lawsuits are without merit and intends to defend itself vigorously against them.

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

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


	March 31, 2010	December 31, 2009	June 30, 2010	December 31, 2009
Shares authorized	50,000	50,000	50,000	50,000
Shares outstanding at end of period:
8.5% Convertible perpetual preferred stock	2,650	2,650	2,650	2,650
6.0% Convertible perpetual preferred stock	2,000	2,000	2,000	2,000

The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 4,650,000 shares were designated as convertible perpetual preferred stock at ~~March 31,~~June 30, 2010 and December 31, 2009. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions and none of such shares are listed on a stock exchange.

8.5% Convertible perpetual preferred stock. The Company’s 8.5% convertible perpetual preferred stock was issued in January 2009. Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of ~~$100~~$100.00 and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of the Company’s common stock based on an initial conversion price of $8.01, subject to adjustments upon the occurrence of certain events. Each holder of the convertible perpetual preferred stock is entitled to an annual dividend of $8.50 per share to be paid semi-annually in cash, common stock or a combination thereof, at the Company’s election. The first dividend payment was paid in cash in February 2010. Approximately ~~$2.8~~$5.6 million in ~~both~~dividends (all unpaid) and $11.3 million in dividends ($2.8 million paid and ~~unpaid dividends, totaling approximately $5.6~~$8.5 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 8.5% convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to automatically convert into common stock at the then-prevailing conversion rate if certain conditions are met.

6.0% Convertible perpetual preferred stock. The Company’s 6.0% convertible perpetual preferred stock was issued in December 2009. Each share of the 6.0% convertible perpetual preferred stock has a liquidation preference of ~~$100~~$100.00 and is entitled to an annual dividend of $6.00 payable semi-annually in cash, common stock or any combination thereof, at the Company’s election, beginning on July 15, 2010. Approximately $3.0 million and $6.0 million in unpaid dividends on the 6.0% convertible perpetual preferred stock has been included in the Company’s earnings per share calculations for the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The first dividend payment was paid in cash in July 2010. The 6.0% convertible perpetual preferred stock is not redeemable by the Company at any time. Each share is initially convertible into 9.21 shares of the Company’s common stock, at the holder’s option ~~at any time on or after February 1, 2010~~ based on an initial conversion price of $10.86 and subject to customary adjustments in certain circumstances. Five years after their issuance, all outstanding shares of the convertible preferred stock will be converted automatically into shares of the Company’s common stock at the then-prevailing conversion price as long as all dividends accrued at that time have been paid.

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


	March 31, 2010	December 31, 2009	June 30, 2010	December 31, 2009
Shares authorized	400,000	400,000	400,000	400,000
Shares outstanding at end of period	210,788	208,715	210,600	208,715
Shares held in treasury	2,173	1,866	2,236	1,866

On July 16, 2010, in conjunction with stockholder approval of the issuance of shares of Company common stock in connection with the Company’s acquisition of Arena, the Company’s stockholders approved an amendment to the Company’s certificate of incorporation to increase the number of authorized shares of common stock from 400.0 million shares to 800.0 million shares. See Note 17 for further discussion regarding the Arena transaction.

Treasury Stock. The Company makes required tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately ~~261,000~~274,000 shares with a total value of ~~$2.8~~$2.9 million and approximately ~~70,000~~71,000 shares with a total value of $0.5 million during the ~~three-month~~six-month periods ended ~~March 31,~~June 30, 2010 and 2009, respectively. These shares were accounted for as treasury stock. Also accounted for as treasury ~~shares~~stock are any shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan. These shares ~~are~~were therefore not included as outstanding shares of common stock in this Quarterly Report. For corporate purposes and for purposes of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

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

For the ~~three-month~~three and six-month periods ended ~~March 31,~~June 30, 2010, the Company recognized stock-based compensation expense of $7.3 million and $14.2 million, net of $1.3 million and $2.6 million capitalized, respectively, related to restricted common stock. For the three and six-month periods ended June 30, 2009, the Company recognized ~~equity~~stock-based compensation expense of $5.2 million and $10.4 million, net of ~~amounts~~$0.8 million and $2.0 million capitalized, ~~of $1.2 million,~~respectively, related to restricted common ~~stock of $6.9 million and $5.2 million, respectively.~~stock.

Noncontrolling Interest. Noncontrolling interests in certain of the Company’s subsidiaries represent third-party ownership interests in the consolidated entity and are included as a component of equity in the ~~condensed~~ consolidated balance ~~sheets~~sheet and ~~condensed~~ consolidated statement of changes in equity as required by ASC Topic ~~810, Consolidation.~~810.

The following table presents a reconciliation of the activity for noncontrolling interest in certain of the Company’s subsidiaries for the ~~three-month~~six-month periods ended ~~March 31,~~June 30, 2010 and 2009 (in thousands):


	2010			2009			2010			2009
Beginning balance, December 31	$	10,052		$	30
Beginning balance, January 1,							$	10,052		$	30
Distributions to noncontrolling interest owners		(4	)		(11	)		(1,506	)		(11	)
Contributions from noncontrolling interest owners								157			—
Net income attributable to noncontrolling interest		1,138			3			2,234			7

Ending balance, March 31	$	11,186		$	22
Ending balance, June 30							$	10,937		$	26

The Company enters into transactions in the ordinary course of business with certain of its stockholders and other related parties. These transactions primarily consist of purchases ofrelated to drilling and completion activities, gas treating services and drilling equipment and sales of oil field services, equipment and natural gas. Following is a summary of significant transactions with such related parties (in thousands):


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009		2010		2009
Sales to and reimbursements from related parties	$	6,613	$	3,813	$	4,166	$	974	$	6,823	$	4,406

Purchases from related parties	$	2,176	$	8,942	$	48	$	5,464	$	90	$	14,406


	March 31, 2010		December 31, 2009
Accounts Receivable due from related parties	$	113	$	64

Accounts Payable due to related parties	$	50	$	860

Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer owns a minority interest in a limited liability company which owns and operates the Oklahoma City Thunder, a National Basketball Association team playing in Oklahoma City, where the Company is headquartered. The Company, like four other Oklahoma City companies, has a five-year sponsorship agreement whereby the Company pays approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder. Additionally, the Company entered into an agreement to license a suite at the arena where the Oklahoma City Thunder plays its home games. Under this four-year agreement, the Company ~~will pay~~pays an annual license fee of $0.2 million.

Larclay, L.P. Until April 15, 2009, Lariat and its partner Clayton Williams Energy, Inc. (“CWEI”) each owned a 50% interest in Larclay, L.P. (“Larclay”), a limited partnership, and, until such time, Lariat operated the rigs owned by Larclay. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay pursuant to the terms of an Assignment and Assumption Agreement (the “Larclay Assignment”) entered into between Lariat and CWEI on March 13, 2009. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay. ~~The Company fully impaired both~~For the ~~investment in and notes receivable due from Larclay at December 31, 2008. There were no additional losses on Larclay during the three-month~~six-month period ended ~~March 31, 2009 or as a result of the Larclay Assignment. For the three-month period ended March 31,~~June 30, 2009, sales to and reimbursements from Larclay were ~~$2.7~~$2.9 million and purchases of services from Larclay were $1.8 million.

Events occurring after ~~March 31,~~June 30, 2010 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this report have been included.

~~In April~~Arena Acquisition. On July 16, 2010, the stockholders of each of the Company and ~~a subsidiary~~Arena approved the Company’s acquisition of all of the outstanding common stock of Arena, and the transaction was completed. At the time of the acquisition, Arena was engaged in oil and natural gas exploration, development and production, with activities in Oklahoma, Texas, New Mexico and Kansas. In conjunction with this approval, the stockholders of the Company ~~entered into a merger agreement~~also approved an amendment to the Company’s certificate of incorporation to increase the number of authorized shares of common stock to 800.0 million. In connection with ~~Arena whereby~~the acquisition, the Company ~~will acquire Arena and, in connection therewith, issue~~issued 4.7771 shares of ~~Company~~its common stock and ~~pay $2.50~~paid $4.50 in cash to Arena stockholders for each ~~share of Arena common stock outstanding. Based upon the closing price of the Company’s stock on April 1, 2010, the consideration to be received by Arena shareholders is valued~~outstanding

~~at $40.00 per share. Completion~~share of Arena unrestricted common stock. In addition, outstanding options to purchase Arena common stock that were deemed exercised pursuant to the merger agreement were converted into shares of Company common stock pursuant to a formula in the merger agreement, and outstanding shares of Arena restricted common stock were converted into restricted shares of Company common stock pursuant to a formula in the merger agreement. Approximately 39.8 million shares of Arena common stock, comprised of 39.5 million shares of Arena common stock outstanding and 0.3 million common shares attributable to Arena options exercised immediately prior to the acquisition in accordance with the merger agreement, were outstanding on the acquisition date. This resulted in the issuance of approximately 190.3 million shares of common stock of the ~~transaction~~Company and payment of approximately $177.9 million in cash for an aggregate estimated purchase price of approximately $1.4 billion. For purposes of purchase accounting, the value of the common shares issued was determined based on the closing price of the Company’s common stock on the New York Stock Exchange at the acquisition date, July 16, 2010. The Company has incurred approximately $4.8 million in fees related to the acquisition, which was included in general and administrative expenses in the accompanying condensed consolidated statements of operations for the six months ended June 30, 2010.

The following allocation of the purchase price as of July 16, 2010, is ~~contingent upon approval~~preliminary and includes significant use of estimates. This preliminary allocation is based on information that was available to management at the time these condensed consolidated financial statements were prepared. Management has not yet had the opportunity to complete its assessment of the fair values of the assets acquired and liabilities assumed. Accordingly, the allocation will change as additional information becomes available and is assessed by ~~stockholders~~the Company, and the impact of ~~both companies~~such changes may be material.

The following table summarizes the estimated values of assets acquired and liabilities assumed (in thousands):

IRC Section 382 addresses company ownership changes and provides for the calculation of a limitation regarding the amount of certain deductions and other tax attributes that can be claimed on an annual basis following an ownership change. The Company has an existing IRC Section 382 limitation as a result of an ownership change that occurred on December 31, 2008. The Company anticipates that the acquisition of Arena will result in another IRC Section 382 ownership change, but has not yet determined whether the existing limitation will be impacted. The acquisition will also result in an ownership change for Arena resulting in a possible limitation on the amount of the acquired tax attributes that can be claimed on an annual basis. The Company does not expect the application of IRC Section 382 to cause the Company to have a current federal tax liability for the period ending December 31, 2010.

The following pro forma results of operations are provided for the three and six-month periods ended June 30, 2010 and 2009 as though the Arena acquisition had been completed as of the beginning of each three and six-month period presented (in thousands except per share amounts). The following supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. Future results may vary significantly from the results reflected in the following pro forma financial information because of future events and transactions, as well as other ~~customary closing conditions.~~factors.

The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of Arena, certain reclassifications to conform Arena’s presentation to

the Company’s accounting policies and the impact of the preliminary purchase price allocation discussed above. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate Arena.

Sale of Oklahoma Deep Rights. On ~~April 30,~~July 22, 2010, the companies were notified that early termination of the waiting period mandated under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 had been granted effective immediately. The meetings of the Company’s and Arena’s stockholders to approve the transaction have been set for June 8, 2010, and the record date for such meetings is May 5, 2010. SandRidge will be the surviving parent company after completion of the merger. Arena isCompany signed an agreement with an oil and gas ~~exploration, development~~company to sell certain deep acreage rights in the Cana Shale play in western Oklahoma for approximately $139.0 million in cash. The Company will retain the shallow rights associated with this acreage. The sale is expected to close in the third quarter of 2010 and ~~production company with current operations in Texas, Oklahoma, Kansas and New Mexico.~~

~~In April 2010, the Company amended and restated its $1.75 billion senior credit facility, extending the maturity date~~is subject to ~~April 15, 2014 from November 21, 2011 and affirming the borrowing base at $850.0 million.~~customary closing adjustments.

The Company has three business segments: exploration and production, drilling and oil field services and midstream gas services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of oil and natural gas properties. The drilling and oil field services segment is engaged in the land contract drilling of oil and natural gas wells. The midstream gas services segment is engaged in ~~the~~ purchasing, gathering, processing, treating and selling of natural gas. The All Other column in the tables below includes items not related to the Company’s reportable segments, including the Company’s CO₂ gathering and sales operations and corporate operations.

As further discussed in Note 19, SandRidge Energy, Inc., the parent company, contributed its oil and natural gas related assets and liabilities to one of its wholly owned subsidiaries effective as of May 1, 2009. As a result, the financial information of SandRidge Energy, Inc. is now included in the All Other column in the ~~table below.~~tables below, which is consistent with management’s evaluation of the business segments. This information was previously included in the exploration and production segment. ~~This presentation is consistent with how the Company’s management evaluates the business segments.~~ All periods presented below reflect this change in presentation.

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


	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total			Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Three Months Ended March 31, 2010
Three Months Ended June 30, 2010
Revenues	$	170,184		$	86,074		$	82,537		$	10,453		$	349,248		$	150,571		$	55,975		$	66,379		$	8,744		$	281,669
Inter-segment revenue		(65	)		(80,314	)		(55,011	)		(2,864	)		(138,254	)		(66	)		(52,063	)		(44,223	)		(2,878	)		(99,230	)

Total revenues	$	170,119		$	5,760		$	27,526		$	7,589		$	210,994		$	150,505		$	3,912		$	22,156		$	5,866		$	182,439

Operating income (loss)	$	110,023		$	(4,301	)	$	1,254		$	(17,806	)	$	89,170		$	136,465		$	(294	)	$	902		$	(17,621	)	$	119,452
Interest income (expense), net		79			(313	)		(138	)		(61,648	)		(62,020	)		121			(254	)		(161	)		(63,867	)		(64,161	)
Other income, net		768			—			—			468			1,236
Other income (expense), net																	13			—			56			(599	)		(530	)

Income (loss) before income taxes	$	110,870		$	(4,614	)	$	1,116		$	(78,986	)	$	28,386		$	136,599		$	(548	)	$	797		$	(82,087	)	$	54,761

Capital expenditures(1)	$	192,077		$	9,417		$	20,422		$	6,665		$	228,581		$	218,973		$	8,195		$	16,337		$	5,459		$	248,964

Depreciation, depletion and amortization	$	52,993		$	7,330		$	876		$	3,382		$	64,581		$	55,041		$	6,833		$	927		$	3,338		$	66,139

At March 31, 2010
Total assets	$	2,411,894		$	219,109		$	123,895		$	216,767		$	2,971,665

Three Months Ended March 31, 2009
Three Months Ended June 30, 2009
Revenues	$	121,933		$	93,814		$	94,367		$	5,896		$	316,010		$	103,727		$	55,975		$	71,838		$	6,511		$	238,051
Inter-segment revenue		(66	)		(87,503	)		(68,953	)		(475	)		(156,997	)		(64	)		(50,877	)		(52,742	)		(269	)		(103,952	)

Total revenues	$	121,867		$	6,311		$	25,414		$	5,421		$	159,013		$	103,663		$	5,098		$	19,096		$	6,242		$	134,099

Operating (loss) income(2)	$	(1,095,862	)	$	(2,755	)	$	210		$	(17,873	)	$	(1,116,280	)
Interest expense, net		(359	)		(633	)		—			(39,745	)		(40,737	)
Operating loss																$	(5,215	)	$	(2,801	)	$	(28,030	)	$	(13,941	)	$	(49,987	)
Interest income (expense), net																	311			(558	)		—			(41,984	)		(42,231	)
Other income, net		760			—			234			—			994			483			—			200			—			683

(Loss) income before income taxes	$	(1,095,461	)	$	(3,388	)	$	444		$	(57,618	)	$	(1,156,023	)
Loss before income taxes																$	(4,421	)	$	(3,359	)	$	(27,830	)	$	(55,925	)	$	(91,535	)

Capital expenditures(1)	$	261,884		$	2,377		$	23,948		$	8,951		$	297,160		$	121,347		$	188		$	17,340		$	8,813		$	147,688

Depreciation, depletion and amortization	$	60,760		$	7,286		$	1,842		$	2,931		$	72,819		$	35,025		$	6,909		$	2,115		$	4,335		$	48,384

At December 31, 2009
Total assets	$	2,222,724		$	229,507		$	110,757		$	217,329		$	2,780,317

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. The subsidiary guarantors are wholly owned and have, jointly and severally, unconditionally guaranteed on an unsecured basis the Company’s 8.625% Senior Notes and Senior Floating Rate Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured

obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors. The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.

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

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., and its wholly owned subsidiary guarantors, prepared on the equity basis of accounting. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes. The non-guarantor subsidiaries are minor and, therefore, not presented separately. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.


	March 31, 2010												June 30, 2010
	Parent Company				Guarantor Subsidiaries		Eliminations			Consolidated			Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)												(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	155			$	2,416	$	—		$	2,571		$	169		$	1,914	$	—		$	2,083
Accounts receivable, net		691,545				236,411		(831,801	)		96,155			753,603			250,853		(901,047	)		103,409
Derivative contracts		—				141,569		—			141,569			—			63,737		—			63,737
Other current assets		—				49,922		—			49,922			—			56,897		—			56,897

Total current assets		691,700				430,318		(831,801	)		290,217			753,772			373,401		(901,047	)		226,126
Property, plant and equipment, net		—				2,596,609		—			2,596,609			—			2,783,773		—			2,783,773
Investment in subsidiaries		1,902,587				—		(1,902,587	)		—			2,019,681			—		(2,019,681	)		—
Other assets		47,106				37,733		—			84,839			55,528			63,236		—			118,764

Total assets	$	2,641,393			$	3,064,660	$	(2,734,388	)	$	2,971,665		$	2,828,981		$	3,220,410	$	(2,920,728	)	$	3,128,663

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	222,421			$	912,983	$	(831,801	)	$	303,603		$	211,248		$	1,005,692	$	(901,047	)	$	315,893
Other current liabilities		7,438				13,072		—			20,510			7,208			12,435		—			19,643

Total current liabilities		229,859				926,055		(831,801	)		324,113			218,456			1,018,127		(901,047	)		335,536
Long-term debt		2,589,344				21,066		—			2,610,410			2,730,660			18,763		—			2,749,423
Asset retirement obligation		—				111,601		—			111,601			—			115,475		—			115,475
Other liabilities		4,709				92,162		—			96,871			9,340			37,427		—			46,767

Total liabilities		2,823,912				1,150,884		(831,801	)		3,142,995			2,958,456			1,189,792		(901,047	)		3,247,201

(Deficit) equity		(182,519	)	��		1,913,776		(1,902,587	)		(171,330	)		(129,475	)		2,030,618		(2,019,681	)		(118,538	)

Total liabilities and equity	$	2,641,393			$	3,064,660	$	(2,734,388	)	$	2,971,665		$	2,828,981		$	3,220,410	$	(2,920,728	)	$	3,128,663


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated			Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)												(In thousands)
Three Months Ended March 31, 2010
Three Months Ended June 30, 2010
Total revenues	$	—		$	210,994		$	—		$	210,994		$	—		$	182,439		$	—		$	182,439
Expenses:
Direct operating expenses		—			87,521			—			87,521			—			82,604			—			82,604
General and administrative		77			31,597			—			31,674			86			33,779			—			33,865
Depreciation, depletion, amortization and impairment		—			64,581			—			64,581			—			66,139			—			66,139
Gain on derivative contracts		—			(61,952	)		—			(61,952	)		—			(119,621	)		—			(119,621	)

Total expenses		77			121,747			—			121,824			86			62,901			—			62,987

(Loss) income from operations		(77	)		89,247			—			89,170			(86	)		119,538			—			119,452
Equity earnings from subsidiaries		88,701			—			(88,701	)		—			117,094			—			(117,094	)		—
Interest expense, net		(61,376	)		(644	)		—			(62,020	)		(63,594	)		(567	)		—			(64,161	)
Other income, net		—			1,236			—			1,236
Other income (expense), net														73			(603	)		—			(530	)

Income before income tax expense		27,248			89,839			(88,701	)		28,386
Income tax expense		12			—			—			12
Income before income taxes														53,487			118,368			(117,094	)		54,761
Income tax (benefit) expense														(28	)		178			—			150

Net income		27,236			89,839			(88,701	)		28,374			53,515			118,190			(117,094	)		54,611
Less: net income attributable to noncontrolling interest		—			1,138			—			1,138			—			1,096			—			1,096

Net income attributable to SandRidge Energy, Inc.	$	27,236		$	88,701		$	(88,701	)	$	27,236		$	53,515		$	117,094		$	(117,094	)	$	53,515


Three Months Ended March 31, 2009
Three Months Ended June 30, 2009
Total revenues	$	48,683		$	112,388		$	(2,058	)	$	159,013		$	9,588		$	124,558		$	(47	)	$	134,099
Expenses:
Direct operating expenses		22,176			56,100			(2,058	)		76,218			5,561			87,564			(47	)		93,078
General and administrative		10,363			18,122			—			28,485			5,152			18,480			—			23,632
Depreciation, depletion, amortization and impairment		622,789			754,448			—			1,377,237			4,689			43,695			—			48,384
Gain on derivative contracts		(206,647	)		—			—			(206,647	)
(Gain) loss on derivative contracts														(30,704	)		49,696			—			18,992

Total expenses		448,681			828,670			(2,058	)		1,275,293			(15,302	)		199,435			(47	)		184,086

Loss from operations		(399,998	)		(716,282	)		—			(1,116,280	)
Income (loss) from operations														24,890			(74,877	)		—			(49,987	)
Equity earnings from subsidiaries		(716,361	)		—			716,361			—			(75,008	)		—			75,008			—
Interest expense, net		(39,769	)		(968	)		—			(40,737	)		(41,421	)		(810	)		—			(42,231	)
Other income, net		102			892			—			994			—			683			—			683

Loss before income tax benefit		(1,156,026	)		(716,358	)		716,361			(1,156,023	)
Loss before income taxes														(91,539	)		(75,004	)		75,008			(91,535	)
Income tax benefit		(1,169	)		—			—			(1,169	)		(365	)		—			—			(365	)

Net loss		(1,154,857	)		(716,358	)		716,361			(1,154,854	)		(91,174	)		(75,004	)		75,008			(91,170	)
Less: net income attributable to noncontrolling interest		—			3			—			3			—			4			—			4

Net loss attributable to SandRidge Energy, Inc.	$	(1,154,857	)	$	(716,361	)	$	716,361		$	(1,154,857	)	$	(91,174	)	$	(75,008	)	$	75,008		$	(91,174	)


	Parent Company			Guarantor Subsidiaries			Eliminations		Consolidated			Parent Company			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)											(In thousands)
Three Months Ended March 31, 2010
Six Months Ended June 30, 2010
Net cash (used in) provided by operating activities	$	(31,065	)	$	178,667		$	—	$	147,602		$	(160,436	)	$	418,895		$	—	$	258,459
Net cash used in investing activities		—			(179,879	)		—		(179,879	)		—			(416,199	)		—		(416,199	)
Net cash provided by (used in) financing activities		30,881			(3,894	)		—		26,987			160,266			(8,304	)		—		151,962

Net decrease in cash and cash equivalents		(184	)		(5,106	)		—		(5,290	)		(170	)		(5,608	)		—		(5,778	)
Cash and cash equivalents at beginning of year		339			7,522			—		7,861			339			7,522			—		7,861

Cash and cash equivalents at end of period	$	155		$	2,416		$	—	$	2,571		$	169		$	1,914		$	—	$	2,083


Three Months Ended March 31, 2009
Net cash (used in) provided by operating activities	$	(99,420	)	$	174,764		$	—	$	75,344
Six Months Ended June 30, 2009
Net cash provided by operating activities												$	106,883		$	37,264		$	—	$	144,147
Net cash used in investing activities		(178,614	)		(171,323	)		—		(349,937	)		(240,992	)		(29,306	)		—		(270,298	)
Net cash provided by (used in) financing activities		278,062			(4,029	)		—		274,033			134,253			(8,117	)		—		126,136

Net increase (decrease) in cash and cash equivalents		28			(588	)		—		(560	)		144			(159	)		—		(15	)
Cash and cash equivalents at beginning of year		18			618			—		636			18			618			—		636

Cash and cash equivalents at end of period	$	46		$	30		$	—	$	76		$	162		$	459		$	—	$	621

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

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as our audited consolidated financial statements and the accompanying notes included in the 2009 Form 10-K.

The financial information with respect to the ~~three-month~~three and six-month periods ended ~~March 31,~~June 30, 2010 and ~~March 31,~~June 30, 2009 that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, which consist 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.

We are an independent oil and natural gas company concentrating on exploration, development and production activities related to the exploitation of our significant holdings in west Texas. Our primary areas of focus are the West Texas Overthrust (“WTO”) and the Permian Basin. The WTO is a natural gas-prone geological region where we have operated since 1986. The WTO includes the Piñon gas field. Additionally, we focus on the exploration, development and production of our oil properties in the Permian Basin, including properties acquired in December 2009 from Forest Oil Corporation and one of its subsidiaries (collectively, “Forest”)~~, as~~ and properties owned by Arena, which we acquired in July 2010. Each such acquisition is described below. We also operate interests in the Mid-Continent, ~~the~~ Cotton Valley Trend in east Texas, ~~the~~ Gulf Coast and ~~the~~ Gulf of Mexico.

In December 2009, we purchased, for approximately $795.1 million, oil and natural gas properties located in the Permian Basin from Forest, consisting primarily of six operated areas in the Central Basin Platform and greater Permian Basin area of western Texas and eastern New Mexico. Approximately 98% of the production associated with these properties is operated and the properties cover over 90,000 net acres, of which nearly 80% is held by production. The acquisition of properties from Forest expanded our holdings in the Central Basin Platform of the Permian Basin and added significant Permian Basin oil production in the Midland and Delaware Basins in Texas as well as the Northwest Shelf in New Mexico.

We currently generate the majority of our consolidated revenues and cash flow from the production and sale of oil and natural gas. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find and economically develop and produce oil and natural gas reserves. Prices for oil and natural gas fluctuate widely. In order to reduce our exposure to these fluctuations, we enter into commodity derivative ~~commodity~~ contracts for a portion of our anticipated future oil and natural gas production. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital expenditure programs.

We operate businesses that are complementary to our exploration, development and production activities. We own related gas gathering and treating facilities, a gas marketing business and an oil field services business. The extent to which each of these supplemental businesses contributes to our consolidated results of operations is largely determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for our own account are eliminated in consolidation and, therefore, do not contribute to our consolidated results of operations.

Arena Acquisition. On July 16, 2010, the stockholders of each of SandRidge and Arena approved the acquisition by SandRidge, of all of the outstanding common stock of Arena, and the transaction was completed. In ~~April 2010,~~connection with the acquisition, we ~~entered into a~~issued 4.7771 shares of our common stock and paid $4.50 in cash to Arena

stockholders for each outstanding share of unrestricted Arena common stock. In addition, outstanding options to purchase Arena common stock that were deemed exercised pursuant to the merger agreement were converted into shares of our common stock pursuant to a formula in the merger agreement, and outstanding shares of Arena restricted common stock were converted into restricted shares of our common stock pursuant to a formula in the merger agreement. The total purchase price is estimated to be approximately $1.4 billion.

In conjunction with ~~Arena whereby we will acquire Arena and,~~stockholder approval of the issuance of SandRidge common stock in connection ~~therewith, issue 4.7771~~with the acquisition of Arena, our stockholders also approved an amendment to our certificate of incorporation to increase the number of authorized shares of common stock ~~and pay $2.50 in cash for each share~~from 400.0 million shares to 800.0 million shares.

Sale of ~~Arena common stock outstanding. Based upon the closing price of our stock on April 1,~~Oklahoma Deep Rights. On July 22, 2010, ~~the consideration~~

to be received by Arena shareholders is valued at $40.00 per share. Completion of the transaction is contingent upon approval by stockholders of both companies as well as other customary closing conditions. On April 30, 2010, the companies were notified that early termination of the waiting period mandated under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 had been granted effective immediately. The meetings of our and Arena’s stockholders to approve the transaction have been set for June 8, 2010 and the record date for such meetings is May 5, 2010. SandRidge will be the surviving parent company after completion of the merger. Arena iswe signed an agreement with an oil and gas ~~exploration, development~~company to sell certain deep acreage rights in the Cana Shale play in western Oklahoma for approximately $139.0 million in cash. We will retain the shallow rights associated with this acreage. The sale is expected to close in the third quarter of 2010 and ~~production company~~is subject to customary closing adjustments.

In January 2010, the FASB issued Accounting Standards Update 2010-03 (“ASU 2010-03”) to align the oil and natural gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule,Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and was effective for the year ended December 31, 2009.Modernization of the Oil and Gas Reporting Requirements was designed to modernize and update the oil and gas disclosure requirements to align with current ~~operations~~practices and changes in ~~Texas, Oklahoma, Kansas~~technology. We implemented ASU 2010-03 prospectively as a change in accounting principle inseparable from a change in accounting estimate at December 31, 2009.

In December 2009, the FASB issued Accounting Standards Update 2009-17, “Consolidations — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU 2009-17”), which codified FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R)”. ASU 2009-17 represents a revision to former FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” (“FIN 46(R)”), and ~~New Mexico.~~changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting or similar rights should be consolidated. ASU 2009-17 also requires enhanced disclosures about a reporting entity’s involvement with variable interest entities. We implemented ASU 2009-17 on January 1, 2010 with no impact on our financial position or results of operations.

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements~~Senior Credit Facility Amendment.~~” ~~In April~~(“ASU 2010-06”). ASU 2010-06 requires additional disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in ASC Topic 820, Fair Value Measurements and Disclosures. We implemented the new disclosures and clarifications of existing disclosure requirements under ASU 2010-06 effective with the first quarter of 2010, ~~we extended the maturity~~except for certain disclosure requirements regarding activity in Level 3 fair value measurements which are effective for fiscal years beginning after December 15, 2010. The implementation of ASU 2010-06 had no impact on our ~~senior credit facility. The amendment and restatement~~financial position or results of ~~the $1.75 billion senior credit facility extends the maturity date to April 15, 2014 from November 21, 2011 and affirms the borrowing base at $850.0 million.~~operations.

We operate in three business segments: exploration and production, drilling and oil field services and midstream gas services. The All Other column in the tables below includes items not related to our reportable segments such as our CO₂ gathering and sales operations and corporate operations. SandRidge Energy, Inc., the parent company, contributed its oil and natural gas related assets and liabilities to one of its wholly owned subsidiaries, effective as of May 1, 2009. As a result, the financial information of SandRidge Energy, Inc. is now included in the All Other column in the ~~table below.~~tables below, which is consistent with management’s evaluation of the business segments. This information was previously included in the exploration and production segment. ~~This presentation is consistent with how management evaluates the business segments.~~ All periods presented below reflect this change in presentation.

Management evaluates the performance of our business segments based on operating income (loss), which is defined as segment operating revenues less operating expenses. Results of 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 for the ~~three-month~~three and six-month periods ended ~~March 31,~~June 30, 2010 and 2009 (in thousands).


	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total			Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Three Months Ended March 31, 2010
Three Months Ended June 30, 2010
Revenues	$	170,184		$	86,074		$	82,537		$	10,453		$	349,248		$	150,571		$	55,975		$	66,379		$	8,744		$	281,669
Inter-segment revenue		(65	)		(80,314	)		(55,011	)		(2,864	)		(138,254	)		(66	)		(52,063	)		(44,223	)		(2,878	)		(99,230	)

Total revenues	$	170,119		$	5,760		$	27,526		$	7,589		$	210,994		$	150,505		$	3,912		$	22,156		$	5,866		$	182,439

Operating income (loss)	$	110,023		$	(4,301	)	$	1,254		$	(17,806	)	$	89,170		$	136,465		$	(294	)	$	902		$	(17,621	)	$	119,452
Interest income (expense), net		79			(313	)		(138	)		(61,648	)		(62,020	)		121			(254	)		(161	)		(63,867	)		(64,161	)
Other income, net		768			—			—			468			1,236
Other income (expense), net																	13			—			56			(599	)		(530	)

Income (loss) before income taxes	$	110,870		$	(4,614	)	$	1,116		$	(78,986	)	$	28,386		$	136,599		$	(548	)	$	797		$	(82,087	)	$	54,761

Three Months Ended March 31, 2009
Three Months Ended June 30, 2009
Revenues	$	121,933		$	93,814		$	94,367		$	5,896		$	316,010		$	103,727		$	55,975		$	71,838		$	6,511		$	238,051
Inter-segment revenue		(66	)		(87,503	)		(68,953	)		(475	)		(156,997	)		(64	)		(50,877	)		(52,742	)		(269	)		(103,952	)

Total revenues	$	121,867		$	6,311		$	25,414		$	5,421		$	159,013		$	103,663		$	5,098		$	19,096		$	6,242		$	134,099

Operating (loss) income(1)	$	(1,095,862	)	$	(2,755	)	$	210		$	(17,873	)	$	(1,116,280	)
Interest expense, net		(359	)		(633	)		—			(39,745	)		(40,737	)
Operating loss																$	(5,215	)	$	(2,801	)	$	(28,030	)	$	(13,941	)	$	(49,987	)
Interest income (expense), net																	311			(558	)		—			(41,984	)	��	(42,231	)
Other income, net		760			—			234			—			994			483			—			200			—			683

(Loss) income before income taxes	$	(1,095,461	)	$	(3,388	)	$	444		$	(57,618	)	$	(1,156,023	)
Loss before income taxes																$	(4,421	)	$	(3,359	)	$	(27,830	)	$	(55,925	)	$	(91,535	)

The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our oil and natural gas production, the quantity of oil and natural gas we produce and changes in the fair value of commodity derivative contracts we use to reduce the volatility of the prices we receive for our oil and natural gas production. Quarterly comparisons of production and price data are presented in the tables below. Changes in our results for these periods reflect, in part, the acquisition of oil and natural gas properties from Forest in December 2009, which impacted ~~our~~ production volumes, revenues and operating income for our exploration and production segment.


	Three Months Ended March 31,				Change					Three Months Ended June 30,				Change
	2010		2009		Amount			Percent		2010		2009		Amount		Percent
Production data:
Oil (MBbls)(1)		1,211		718		493		68.7	%
Oil (MBbl)(1)											1,344		722	622		86.1	%
Natural gas (MMcf)		19,057		24,432		(5,375	)	(22.0	)%		19,316		22,255	(2,939	)	(13.2	)%
Combined equivalent volumes (MMcfe)		26,320		28,739		(2,419	)	(8.4	)%		27,383		26,587	796		3.0	%
Average daily combined equivalent volumes (MMcfe/d)		292.4		319.3		(26.9	)	(8.4	)%		301		292	9		3.1	%

Average prices — as reported(2):
Oil (per Bbl)(1)	$	66.50	$	38.44	$	28.06		73.0	%	$	62.56	$	51.79	10.77		20.8	%
Natural gas (per Mcf)	$	4.67	$	3.83	$	0.84		21.9	%	$	3.41	$	2.95	0.46		15.6	%
Combined equivalent (per Mcfe)	$	6.44	$	4.22	$	2.22		52.6	%	$	5.48	$	3.88	1.60		41.2	%

Average prices — including impact of derivative contract settlements:
Oil (per Bbl)(1)	$	69.09	$	43.65	$	25.44		58.3	%	$	65.86	$	56.01	9.85		17.6	%
Natural gas (per Mcf)	$	6.75	$	7.71	$	(0.96	)	(12.5	)%	$	6.06	$	7.07	(1.01	)	(14.3	)%
Combined equivalent (per Mcfe)	$	8.06	$	7.64	$	0.42		5.5	%	$	7.51	$	7.44	0.07		0.9	%

Exploration and Production Segment — Three months ended ~~March 31,~~June 30, 2010 compared to the three months ended ~~March 31,~~June 30, 2009

Exploration and production segment revenues increased ~~$48.2~~$46.8 million, or ~~39.6%~~45.2%, to ~~$170.1~~$150.5 million in the three months ended ~~March 31,~~June 30, 2010 from ~~$121.9~~$103.7 million in the three months ended ~~March 31,~~June 30, 2009, as a result of a ~~52.6%~~41.2% increase in the combined average price we received for our oil and natural gas production. ~~This~~Also contributing to the increase was the 86.1% increase in ~~prices received was~~oil production, partially offset by the ~~8.4%~~13.2% decrease in ~~combined~~

natural gas production volumes. In the three-month period ended ~~March 31,~~June 30, 2010, oil production increased by ~~493~~622 MBbls to ~~1,211~~1,344 MBbls and natural gas production decreased by ~~5.4~~2.9 Bcf to ~~19.1~~19.3 Bcf from the comparable period in 2009. The increase in oil production was due to the addition of Permian Basin properties acquired from Forest and a focus on increased oil drilling in ~~the first quarter of~~ 2010. The decrease in natural gas production was ~~due to~~a result of the ~~effects~~decline in the number of ~~fewer~~ rigs drilling for natural gas ~~beginning in~~during 2009 and 2010 due to ~~the decline in~~depressed natural gas prices. ~~Drilling activity declined from a high of 47 rigs working in 2008 to a low of 4 rigs working in 2009.~~

The average price received for our oil production increased ~~73.0%~~20.8%, or ~~$28.06~~$10.77 per barrel, to ~~$66.50~~$62.56 per barrel during the three months ended ~~March 31,~~June 30, 2010 from ~~$38.44~~$51.79 per barrel during the same period in 2009. The average price we received for our natural gas production for the three-month period ended ~~March 31,~~June 30, 2010 increased ~~21.9%~~15.6%, or ~~$0.84~~$0.46 per Mcf, to ~~$4.67~~$3.41 per Mcf from ~~$3.83~~$2.95 per Mcf in the comparable period in 2009. Including the impact of derivative contract settlements, the effective price received for oil for the three-month period ended ~~March 31,~~June 30, 2010 was ~~$69.09~~$65.86 per Bbl compared to ~~$43.65~~$56.01 per Bbl during the same period in 2009. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended ~~March 31,~~June 30, 2010

was ~~$6.75~~$6.06 per Mcf compared to ~~$7.71~~$7.07 per Mcf during the same period in 2009. During 2009 and continuing into 2010, we entered into derivative contracts to mitigate the impact of commodity price fluctuations on our production through 2012. Due to the long-term nature of our investment in the development of our properties, we enter into oil and natural gas swaps and natural gas basis swaps for a portion of our production in order to stabilize future cash inflows for planning purposes. Our derivative contracts are not designated as hedges and, as a result, gains or losses on commodity derivative contracts are recorded as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Realized gains or losses from the settlement of derivative contracts with contractual maturities outside of the reporting period are not considered in the calculation of “effective prices.”

During the three-month period ended ~~March 31,~~June 30, 2010, the exploration and production segment reported a ~~$62.0~~$119.6 million net gain on our commodity derivative positions ($~~42.6~~117.9 million realized gain and ~~$19.4~~$1.7 million unrealized gain) compared to a ~~$206.6~~$19.0 million net ~~gain~~loss on our commodity derivative positions ($~~98.3~~94.7 million realized gain and ~~$108.3~~$113.7 million unrealized ~~gain)~~loss) in the same period in 2009. The realized gain of ~~$42.6~~$117.9 million for the three months ended ~~March 31,~~June 30, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. ~~The differential between~~Realized gains totaling $62.4 million resulting from settlements of commodity derivative contracts with original contractual maturities after June 30, 2010 were included in the ~~natural gas price at~~realized gain for the ~~time of settlement and the contract price was lower during the three-month period~~three months ended ~~March 31, 2010 than during the same period in 2009, resulting in a decrease to the amount of gains realized.~~June 30, 2010. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on our commodity ~~derivative~~ contracts recorded during the three months ended ~~March 31,~~June 30, 2010 was attributable to a decrease in average ~~natural gas~~oil prices and increases in the price differentials on our basis swaps at June 30, 2010 compared to the average oil prices and price differentials at March 31, 2010. This amount was partially offset by increases in the average natural gas price at June 30, 2010 compared to the average natural gas price at March 31, 2010. The unrealized loss for the three-month period ended June 30, 2009 was attributable to increased average oil and natural gas prices at June 30, 2009.

For the three months ended June 30, 2010, we had operating income of $136.5 million in our exploration and production segment compared to an operating loss of $5.2 million for the same period in 2009. The $47.0 million increase in oil and natural gas revenues and $119.6 million gain on commodity derivative contracts were partially offset by a $20.0 million increase in depreciation and depletion, a $14.4 million increase in production expenses and a $4.8 million increase in production taxes. See discussion of production expense, production taxes and depreciation and depletion under “Consolidated Results of Operations.”

Exploration and Production Segment — Six months ended June 30, 2010 compared to the six months ended June 30, 2009

Exploration and production segment revenues increased $95.1 million, or 42.2%, to $320.6 million in the six months ended June 30, 2010 from $225.5 million in the six months ended June 30, 2009, as a result of a 46.9% increase in the combined average price we received for our oil and natural gas production. Also contributing to the increase was the 77.4% increase in oil production, partially offset by the 17.8% decrease in natural gas production volumes. In the six-month period ended June 30, 2010, oil production increased by 1,115 MBbls to 2,555 MBbls and natural gas production decreased by 8.3 Bcf to 38.4 Bcf from the comparable

period in 2009. The increase in oil production was due to the addition of Permian Basin properties acquired from Forest and a focus on increased oil drilling in 2010. The decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2009 and 2010 due to depressed natural gas prices.

The average price received for our oil production increased 42.8%, or $19.30 per barrel, to $64.43 per barrel during the six months ended June 30, 2010 from $45.13 per barrel during the same period in 2009. The average price we received for our natural gas production for the six-month period ended June 30, 2010 increased 18.5%, or $0.63 per Mcf, to $4.04 per Mcf from $3.41 per Mcf in the comparable period in 2009. Including the impact of derivative contract settlements, the effective price received for oil for the six-month period ended June 30, 2010 was $67.39 per Bbl compared to $49.85 per Bbl during the same period in 2009. Including the impact of derivative contract settlements, the effective price received for natural gas for the six-month period ended June 30, 2010 was $6.40 per Mcf compared to $7.40 per Mcf during the same period in 2009.

During the six-month period ended June 30, 2010, the exploration and production segment reported a $181.6 million net gain on our commodity derivative positions ($160.6 million realized gain and $21.0 million unrealized gain) compared to a $187.7 million net gain on our commodity derivative positions ($193.2 million realized gain and $5.5 million unrealized loss) in the same period in 2009. The realized gain of $160.6 million for the six months ended June 30, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $62.4 million resulting from settlements of commodity derivative contracts with original contractual maturities after June 30, 2010 were included in the realized gain for the six months ended June 30, 2010. The unrealized gain on commodity contracts recorded during the six months ended June 30, 2010 was attributable to a decrease in average oil prices and increases in the price differentials on our basis swaps at June 30, 2010 compared to the average oil prices and price differentials at December 31, 2009 or the contract price for contracts entered into during 2010. This amount was partially offset by ~~decreases~~increases in the average price ~~differentials on our basis swaps~~of natural gas at ~~March 31,~~June 30, 2010 compared to the average price ~~differentials~~of natural gas at December 31, 2009, or as stated in the contract for contracts entered into during 2010. ~~The decrease in the unrealized gains was attributable to fewer natural gas fixed price contracts being open at March 31, 2010 compared to March 31, 2009.~~

For the ~~three~~six months ended ~~March 31,~~June 30, 2010, we had operating income of ~~$110.0~~$246.5 million in our exploration and production segment compared to an operating loss of ~~$1,095.9~~$1,101.1 million for the same period in 2009. The ~~$48.3~~$95.3 million increase in oil and natural gas revenues ~~$7.8~~and the absence of a full cost ceiling limitation during the first six months of 2010 were partially offset by the $6.1 million decrease in gains on commodity derivative contracts, a $19.0 million increase in production expenses, a $8.2 million increase in production taxes and a $12.2 million increase in depreciation and depletion of our oil and natural gas ~~properties and~~properties. See discussion of the ~~absence of a~~2009 period full cost ceiling limitation, ~~at March 31, 2010 were partially offset by a $144.7 million decrease in gains on commodity derivative contracts~~production expense, production taxes and ~~a $4.5 million increase in production expenses. The decrease in~~ depreciation and depletion under “Consolidated Results of our oil and natural gas properties was due to a decrease in combined production volumes as well as a decrease in the depreciation and depletion rate per Mcfe. The full cost ceiling impairment for the three-month period ended March 31, 2009 was the result of the decline of the future value of our reserves due to depressed oil and natural gas prices at March 31, 2009. The increase in production expenses was primarily due to the additional expenses resulting from properties acquired from Forest in December 2009.Operations.”

The financial results of our drilling and oil field services segment depend primarily on the demand for and price we can charge for our services. In addition to providing drilling services, our oil field services business also conducts operations that complement our ~~drilling services~~exploration and production segment such as providing pulling units, trucking, rental tools, location and road construction and roustabout services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third party working interests in wells we operate, are included in drilling and services revenues and expenses while drilling and oil field service revenues earned and expenses incurred in performing services for our own account are eliminated in consolidation.

Until April 15, 2009, we indirectly owned, through Lariat and its partner ~~Clayton Williams Energy, Inc. (“CWEI”),~~CWEI, an additional 11 operational rigs through an investment in ~~Larclay L.P. (“Larclay”).~~Larclay. Although our ownership in Larclay afforded us access to Larclay’s operational rigs, we did not control Larclay and, therefore, did not consolidate the results of its operations with ours. Only the activities ofor our wholly owned drilling and oil field

services subsidiaries are included in the financial results of our drilling and oil field services segment. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay pursuant to the terms of an the Larclay

Assignment ~~and Assumption Agreement (the “Larclay Assignment”)~~ entered into between Lariat and CWEI. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective as of April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay.

As of ~~March 31,~~June 30, 2010, we owned 30 drilling rigs, through Lariat, of which 34 were idle and 4 were non-operational. The table below presents a summary of the rigs owned by Lariat:


	March 31,		June 30,
	2010	2009	2010	2009
Rigs working for SandRidge	21	7	20	6
Rigs working for third parties	2	—	2	—
Idle rigs(1)	3	23	4	23

Total operational	26	30	26	29
Non-operational rigs(2)	4	1	4	2

Total rigs owned(3)	30	31	30	31

Drilling and Oil Field Services Segment — Three months ended ~~March 31,~~June 30, 2010 compared to the three months ended ~~March 31,~~June 30, 2009

Drilling and oil field services segment revenues decreased to ~~$5.8~~$3.9 million in the three-month period ended ~~March 31,~~June 30, 2010 from ~~$6.3~~$5.1 million in the three-month period ended ~~March 31, 2009. Drilling~~June 30, 2009 and drilling and oil field services segment expenses ~~increased approximately $1.0~~decreased $3.7 million to ~~$10.1 million.~~$4.2 million during the same period. The ~~increase~~decrease in expense resulted in ana reduced operating loss of ~~$4.3~~$0.3 million in the three-month period ended ~~March 31,~~June 30, 2010 compared to an operating loss of $2.8 million for the same period in 2009. The decline in revenues and expenses was primarily attributable to a decrease in services performed for third parties.

Drilling and Oil Field Services Segment — Six months ended June 30, 2010 compared to the six months ended June 30, 2009

Drilling and oil field services segment revenues decreased to $9.7 million in the six-month period ended June 30, 2010 from $11.4 million in the six-month period ended June 30, 2009. Drilling and oil field services segment expenses decreased $2.7 million to $14.3 million for the six-month period ended June 30, 2010. The decrease in expenses resulted in a reduced operating loss of $4.6 million for the six-month period ended June 30, 2010 compared to an operating loss of $5.6 million in the same period in 2009. The ~~increase~~decline in ~~drilling~~revenues and ~~services~~ expenses was primarily ~~due~~attributable to ~~an increase~~a decrease in ~~upfront operating costs associated with preparing idle rigs~~sales to and services performed for operation. During the first quarter of 2010, we placed 7 rigs into operation, bringing the total number of rigs working to 23. The average cost associated with preparing each of these rigs for operation was approximately $0.1 million.third parties during 2010.

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

In June 2009, we completed the sale of our gathering and compression assets located in the Piñon Field of the WTO. Net proceeds from the sale were approximately $197.5 million, which resulted in a loss on the sale of $26.1 million. In conjunction with the sale, we entered into a gas gathering agreement and an operations and

maintenance agreement. Under the gas gathering agreement, we have dedicated our Piñon Field acreage for priority gathering services for a period of 20 years and we will pay a fee for such services that was negotiated at arms’ length. Pursuant to the operations and maintenance agreement, we will operate and maintain the gathering system assets sold for a period of 20 years unless we or the buyer of the assets ~~chooses~~choose to terminate the agreement.

GRLP is a limited partnership that operates the Grey Ranch Plant located in Pecos County, Texas. We purchased our 50% equity investment in GRLP during 2003. On October 1, 2009, we executed amendments to certain agreements related to the ownership and operation of GRLP. As a result of these amendments, we became the primary beneficiary of GRLP. ~~Due to this change,~~Accordingly, we began consolidating the activity of GRLP in our midstream gas services segment prospectively beginning on the effective date of the amendments.

Midstream Gas Services Segment — Three months ended ~~March 31,~~June 30, 2010 compared to the three months ended ~~March 31,~~June 30, 2009

Midstream gas services segment revenues for the three months ended ~~March 31,~~June 30, 2010 were ~~$27.5~~$22.2 million compared to ~~$25.4~~$19.1 million in the same period in ~~2009 and operating~~2009. Operating income ~~increased to $1.3~~was $0.9 million for the three months ended ~~March 31,~~June 30, 2010 ~~from $0.2~~compared to an operating loss of $28.0 million for the comparable period in 2009. The increase in midstream gas services segment revenues ~~and operating income~~ was primarily due to the consolidation of GRLP activity into the midstream gas services segment for the three-month period ended ~~March 31,~~June 30, 2010. For the three-month period ended ~~March 31,~~June 30, 2009, our share of GRLP activity was reported as income from equity investments. The operating loss for the three-month period ended June 30, 2009 was primarily due to a $26.1 million loss on the sale of our gathering and compression assets discussed above.

Midstream Gas Services Segment — Six months ended June 30, 2010 compared to the six months ended June 30, 2009

Midstream gas services segment revenues for the six months ended June 30, 2010 were $49.7 million compared to $44.5 million in the same period in 2009. Operating income was $2.2 million for the six months ended June 30, 2010 compared to an operating loss of $27.8 million for the comparable period in 2009. The increase in midstream gas services segment revenues was due to the consolidation of GRLP activity into the midstream gas services segment for the six-month period ended June 30, 2010. The increase in operating income was primarily due to the inclusion of a $26.1 million loss on the sale of our gathering and compression assets in the six months ended June 30, 2009. Additionally, the operating income from GRLP was included in the midstream gas services segment for the six months ended June 30, 2010. Prior to October 1, 2009 when we began consolidating GRLP, our share of GRLP activity was reported as income from equity investments.

Three months ended ~~March 31,~~June 30, 2010 compared to the three months ended ~~March 31,~~June 30, 2009

Revenues.Total revenues increased ~~32.7%~~36.0% to ~~$211.0~~$182.4 million for the three months ended ~~March 31,~~June 30, 2010 from ~~$159.0~~$134.1 million in the same period in 2009. This increase was primarily due to a ~~$48.3~~$47.0 million increase in oil and natural gas sales.


	Three Months Ended March 31,									Three Months Ended June 30,
	2010		2009		$ Change			% Change		2010		2009		$ Change			% Change
	(In thousands)									(In thousands)
Revenues:
Oil and natural gas	$	169,585	$	121,241	$	48,344		39.9	%	$	149,995	$	103,039	$	46,956		45.6	%
Drilling and services		5,760		6,311		(551	)	(8.7	)%		3,901		5,097		(1,196	)	(23.5	)%
Midstream and marketing		27,988		25,956		2,032		7.8	%		22,598		19,642		2,956		15.0	%
Other		7,661		5,505		2,156		39.2	%		5,945		6,321		(376	)	(5.9	)%

Total revenues	$	210,994	$	159,013	$	51,981		32.7	%	$	182,439	$	134,099	$	48,340		36.0	%

Total oil and natural gas revenues increased ~~$48.3~~$47.0 million to ~~$169.6~~$150.0 million for the three months ended ~~March 31,~~June 30, 2010 compared to ~~$121.2~~$103.0 million for the same period in 2009, primarily as a result of an increase in the prices received on our production of oil and natural gas and increased oil production, offset slightly by decreases in natural gas production. The combined average price received, excluding the impact of derivative contracts, for our oil and natural gas production increased ~~52.6%~~41.2% in the 2010 period to ~~$6.44~~$5.48 per Mcfe compared to ~~$4.22~~$3.88 per Mcfe in 2009. ~~Oil~~The increase in oil production ~~increased 68.7% to 1,211 MBbls in 2010 from 718 MBbls in 2009,~~was primarily due to ~~production from oil~~the properties acquired from Forest and a focus on increased oil drilling in ~~December 2009, while natural gas production decreased 22.0% to 19.1 Bcf in 2010 compared to 24.4 Bcf in 2009.~~2010.

Drilling and services revenues decreased ~~8.7%~~23.5% to ~~$5.8~~$3.9 million for the three months ended ~~March 31,~~June 30, 2010 compared to ~~$6.3~~$5.1 million for the same period in 2009. The decrease iswas due to an increase in oil field services work performed for our own account, ~~resulting in decreases~~and a corresponding decline in oil field services performed for third parties.

Midstream and marketing revenues increased ~~$2.0~~$3.0 million, or ~~7.8%~~15.0%, with revenues of ~~$28.0~~$22.6 million in the three-month period ended ~~March 31,~~June 30, 2010 compared to ~~$26.0~~$19.6 million in the three-month period ended ~~March 31,~~June 30, 2009. The increase in midstream ~~gas services~~and marketing revenues was attributable to the inclusion of GRLP activity for the three-month period ended ~~March 31,~~June 30, 2010. Prior to October 2009, GRLP was not consolidated.

~~Other revenue increased to $7.7 million for the three months ended March 31, 2010 from $5.5 million for the same period in 2009. The increase was primarily due to higher CO~~₂ ~~volumes sold to third parties during the three-month period ended March 31, 2010 compared to the same period in 2009.~~

Operating Costs and Expenses. Total operating costs and expenses decreased to ~~$121.8~~$63.0 million for the three months ended ~~March 31,~~June 30, 2010 compared to ~~$1,275.3~~$184.1 million for the same period in 2009. The decrease was primarily due to the ~~absence~~gains on derivative contracts and a decrease in loss on sale of ~~a full cost ceiling impairment in the three months ended March 31, 2010 and decreases in depreciation and depletion~~assets during the three-month period ended ~~March 31,~~June 30, 2010 compared to the same period in 2009. These decreases were partially offset by increases in production expenses, production taxes, depreciation and depletion on oil and natural gas properties and general and administrative ~~expenses and decreases in gains on derivative contracts.~~expenses.


	Three Months Ended March 31,											Three Months Ended June 30,
	2010			2009			$ Change			% Change		2010			2009		$ Change			% Change
	(In thousands)											(In thousands)
Operating costs and expenses:
Production	$	50,272		$	45,734		$	4,538		9.9	%	$	56,009		$	41,591	$	14,418		34.7	%
Production taxes		4,838			1,491			3,347		224.5	%		5,404			593		4,811		811.3	%
Drilling and services		7,209			4,925			2,284		46.4	%		1,024			5,791		(4,767	)	(82.3	)%
Midstream and marketing		25,506			23,888			1,618		6.8	%		19,779			18,933		846		4.5	%
Depreciation and depletion — oil and natural gas		52,278			60,093			(7,815	)	(13.0	)%		54,319			34,350		19,969		58.1	%
Depreciation, depletion and amortization — other		12,303			12,726			(423	)	(3.3	)%		11,820			14,034		(2,214	)	(15.8	)%
Impairment		—			1,304,418			(1,304,418	)	(100.0	)%
General and administrative		31,674			28,485			3,189		11.2	%		33,865			23,632		10,233		43.3	%
Gain on derivative contracts		(61,952	)		(206,647	)		144,695		(70.0	)%
(Gain) loss on sale of assets		(304	)		180			(484	)	(268.9	)%
(Gain) loss on derivative contracts													(119,621	)		18,992		(138,613	)	(729.8	)%
Loss on sale of assets													388			26,170		(25,782	)	(98.5	)%

Total operating costs and expenses	$	121,824		$	1,275,293		$	(1,153,469	)	(90.4	)%	$	62,987		$	184,086	$	(121,099	)	(65.8	)%

Production expenses include the costs associated with our exploration and production activities, including, but not limited to, lease operating expenses and treating costs. Production expenses increased ~~$4.5~~$14.4 million primarily due to the addition of operating expenses associated with properties acquired from Forest. The additional expenses incurred on acquired Forest properties were ~~partially~~slightly offset by lower production expenses as a result of the decrease in natural gas production. ~~Natural gas production decreased by 5.4 Bcf to 19.1 Bcf from the comparable period in 2009.~~ Production taxes increased ~~$3.3~~$4.8 million, or ~~224.5%~~811.3%, to ~~$4.8~~$5.4 million primarily due to a decrease in ~~2010~~the amount of high-cost gas severance tax refunds received in the three-month period ended June 30, 2010 compared to ~~those~~the same period in 2009 and the ~~increased prices received~~additional taxes for ~~production during the three months ended March 31, 2010.~~properties acquired from Forest.

Drilling and services expenses, which include operating expenses attributable to the drilling and oil field services segment and our CO₂ services companies, ~~increased $2.3~~decreased $4.8 million or ~~46.4%~~82.3% for the three months ended ~~March 31,~~June 30, 2010 compared to the same period in 2009 primarily due to ~~costs associated with performing maintenance on idle rigs to prepare~~an increase in the amount of work performed for ~~operation and increases in CO~~₂ ~~sales to third parties~~our own account during the ~~three month~~three-month period ended ~~March 31,~~June 30, 2010 compared to the same period in 2009.

~~Midstream and marketing expenses increased $1.6 million, or 6.8%, to $25.5 million due to expenses related to GRLP, which we began consolidating in October 2009.~~

Depreciation and depletion for our oil and natural gas properties ~~decreased~~increased to ~~$52.3~~$54.3 million for the three-month period ended ~~March 31,~~June 30, 2010 from ~~$60.1~~$34.4 million in the same period in 2009. The ~~decrease~~increase was primarily due to ~~a decline~~an increase in our depreciation and depletion per Mcfe to ~~$1.99~~$1.98 in the ~~first~~second quarter of 2010 from ~~$2.09~~$1.29 in the comparable period in 2009 as a result of ~~the cumulative full cost ceiling impairment which reduced the carrying value of~~an increase to our ~~oil and natural gas properties.~~

~~At March 31, 2009, we recorded a non-cash impairment charge of $1,304.4 million as total capitalized costs of our~~depreciable oil and natural gas properties, ~~exceeded~~primarily due to the acquisition of properties from Forest.

Depreciation, depletion and amortization (“DD&A”) for our ~~full cost ceiling limitation. There~~other assets consists primarily of depreciation of our drilling rigs, midstream gathering and compression facilities and other equipment. The decrease in DD&A for our other assets was ~~no full cost ceiling impairment at March 31, 2010.~~attributable to the decrease in other assets as a result of the sale of gathering and compression assets in June 2009 and the change in asset lives of certain of our drilling, oil field services, midstream and other assets to align with industry average lives for similar assets. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from 3 to 39 years.

General and administrative expenses increased ~~$3.2~~$10.2 million, or ~~11.2%~~43.3% to ~~$31.7~~$33.8 million for the three months ended ~~March 31,~~June 30, 2010 from ~~$28.5~~$23.6 million for the comparable period in 2009 primarily due to $3.8 million of fees incurred related to our acquisition of Arena and increased compensation costs of $6.1 million resulting from an increase in non-cash stock compensation ~~expenses related to our non-qualified deferred compensation plan~~ and ~~an increase in acquisition expenses.~~the number of employees.

We recorded a net gain of ~~$62.0~~$119.6 million ($~~42.6~~117.9 million realized gain and ~~$19.4~~$1.7 million unrealized gain) on our commodity ~~derivatives~~derivative contracts for the three-month period ended ~~March 31,~~June 30, 2010 compared to a net ~~gain~~loss of ~~$206.6~~$19.0 million ($~~98.3~~94.7 million realized gain and ~~$108.3~~$113.7 million unrealized ~~gain)~~loss) in the same period of 2009. ~~The realized gain~~See further discussion of ~~$42.6~~gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”

Loss on sale of assets decreased $25.8 million, or 98.5%, to $0.4 million for the three months ended ~~March 31,~~June 30, 2010 ~~was~~from a $26.2 million loss for the comparable period in 2009, primarily due to a ~~decline in natural gas prices at~~$26.1 million loss recorded on the ~~time~~sale of ~~settlement compared to the contract price. The differential between the natural gas price at the time of settlement~~our gathering and ~~the contract price was lower~~compression assets during the ~~three-month period ended March 31, 2010 than during the same period in~~ 2009 resulting in a decrease to the amount of gains realized. The unrealized gain on our commodity derivative contracts recorded during the three months ended March 31, 2010 was attributable to a decrease in average natural gas prices at March 31, 2010 compared to the average natural gas prices at December 31, 2009 or the contract price for contracts entered into during 2010. This amount was partially offset by decreases in the price differentials on our basis swaps at March 31, 2010 compared to the price differentials at December 31, 2009 or as stated in the contract for contracts entered into during 2010. The decrease in the unrealized gains was attributable to fewer natural gas fixed price contracts being open at March 31, 2010 compared to March 31, 2009.period.

Other Income (Expense). Total other expense increased to ~~$60.8~~$64.7 million in the three-month period ended ~~March 31,~~June 30, 2010 from ~~$39.7~~$41.5 million in the three-month period ended ~~March 31,~~June 30, 2009. The increase is reflected in the table below.


	Three Months Ended March 31,											Three Months Ended June 30,
	2010			2009			$ Change			% Change		2010			2009			$ Change			% Change
	(In thousands)											(In thousands)
Other income (expense):
Interest income	$	69		$	11		$	58		527.3	%	$	98		$	188		$	(90	)	(47.9	)%
Interest expense		(62,089	)		(40,748	)		(21,341	)	52.4	%		(64,259	)		(42,419	)		(21,840	)	51.5	%
Income from equity investments		—			234			(234	)	(100.0	)%		—			200			(200	)	(100.0	)%
Other income (expense), net		1,236			760			476		62.6	%
Other (expense) income, net													(530	)		483			(1,013	)	(209.7	)%

Total other (expense) income		(60,784	)		(39,743	)		(21,041	)	52.9	%		(64,691	)		(41,548	)		(23,143	)	55.7	%

Income (loss) before income tax expense (benefit)		28,386			(1,156,023	)		1,184,409		(102.5	)%
Income (loss) before income taxes													54,761			(91,535	)		146,296		(159.8	)%
Income tax expense (benefit)		12			(1,169	)		1,181		(101.0	)%		150			(365	)		515		(141.1	)%

Net income (loss)	$	28,374		$	(1,154,854	)	$	1,183,228		(102.5	)%	$	54,611		$	(91,170	)	$	145,781		(159.9	)%

Interest expense increased to ~~$62.1~~$64.3 million for the three months ended ~~March 31,~~June 30, 2010 from ~~$40.7~~$42.4 million for the same period in 2009. This increase was primarily attributable to the higher average debt balances outstanding during the three months ended ~~March 31,~~June 30, 2010 compared to the same period in 2009 primarily due to the issuance of our 9.875% Senior Notes in May 2009 and our 8.75% Senior Notes in December 2009. Also contributing to the increase was a $6.5 million net loss on our interest rate swaps for the three-month period ending June 30, 2010 compared to a $2.6 million net gain for the same period in 2009.

We reported an income tax expense of ~~$0.01~~$0.1 million, net of income tax expense attributable to noncontrolling interest, for the three-month period ended ~~March 31,~~June 30, 2010, compared to an income tax benefit of ~~$1.2~~$0.4 million for the same period in 2009. The current period income tax expense represents an effective income tax rate for SandRidge of ~~0.04%~~0.1% compared to an effective income tax rate of 0.4% in the same period in 2009. We continue to have a low effective tax rate due to a full valuation allowance against our net deferred tax asset.

Six months ended June 30, 2010 compared to the six months ended June 30, 2009

Revenues.Total revenues increased 34.2% to $393.4 million for the six months ended June 30, 2010 from $293.1 million in the same period in 2009. This increase was primarily due to a $95.3 million increase in oil and natural gas sales.

Total oil and natural gas revenues increased $95.3 million to $319.6 million for the six months ended June 30, 2010 compared to $224.3 million for the same period in 2009, primarily as a result of an increase in the prices received on our production of oil and natural gas and increased oil production, offset slightly by decreases in natural gas production. The combined average price received, excluding the impact of derivative contracts, for our oil and natural gas production increased 46.9% in the 2010 period to $5.95 per Mcfe compared to $4.05 per Mcfe in 2009. The increase in oil production was primarily due to the addition of properties acquired from Forest and a focus on increased oil drilling in 2010.

Drilling and services revenues decreased 15.3% to $9.7 million for the six months ended June 30, 2010 compared to $11.4 million for the same period in 2009. The decrease was due to a decrease in sales of supplies to third parties and an increase in oil field services work performed for our own account with a corresponding decline in oil field services performed for third parties.

Midstream and marketing revenues increased $5.0 million, or 10.9%, with revenues of $50.6 million in the six-month period ended June 30, 2010 compared to $45.6 million in the six-month period ended June 30, 2009. The increase in midstream gas services revenues was primarily attributable to the inclusion of GRLP activity for the six-month period ended June 30, 2010. Prior to October 2009, GRLP was not consolidated. Also contributing to the increase was an increase in the volume of natural gas marketed for third parties, partially offset by a decrease in the price for such natural gas.

Other revenues increased slightly to $13.6 million for the six months ended June 30, 2010 from $11.8 million for the same period in 2009. The increase was primarily due to higher CO₂ volumes sold to third parties during the six-month period ended June 30, 2010 compared to the same period in 2009.

Operating Costs and Expenses. Total operating costs and expenses decreased to $184.8 million for the six months ended June 30, 2010 compared to $1,459.4 million for the same period in 2009. The decrease was primarily due to the absence of a full cost ceiling impairment and a decrease in loss on sale of assets during the six-month period ended June 30, 2010 compared to the same period in 2009. These decreases were partially offset by increases in production expenses, production taxes, depreciation and depletion on oil and natural gas properties and general and administrative expenses.

Production expenses increased $19.0 million primarily due to the addition of operating expenses associated with properties acquired from Forest. The additional expenses incurred on acquired Forest properties were slightly offset by lower production expenses as a result of the decrease in natural gas production. Natural gas production decreased by 8.3 Bcf to 38.4 Bcf from the comparable period in 2009. Production taxes increased $8.2 million, or 391.5%, to $10.2 million due to a decrease in the amount of high-cost gas severance tax refunds received in the six-month period ended June 30, 2010 compared to the same period in 2009, the additional taxes for properties acquired from Forest and the increased prices received for production during the six months ended June 30, 2010.

Drilling and services expenses decreased $2.5 million, or 23.2%, for the six months ended June 30, 2010 compared to the same period in 2009 primarily due to a decrease in purchases of supplies and an increase in the amount of work performed for our own account, partially offset by costs associated with performing maintenance on idle rigs to prepare for operation during the six-month period ended June 30, 2010 compared to the same period in 2009.

Midstream and marketing expenses increased $2.5 million, or 5.8%, to $45.3 million due to the consolidation of GRLP activity during the six-month period ended June 30, 2010.

Depreciation and depletion for our oil and natural gas properties increased to $106.6 million for the six-month period ended June 30, 2010 from $94.4 million in the same period in 2009. The increase was primarily due to an increase in our depreciation and depletion per Mcfe to $1.98 in the first six months of 2010 from $1.71 in the comparable period in 2009 as a result of an increase to our depreciable oil and natural gas properties, primarily due to the acquisition of properties from Forest.

During the first six months of 2009, we reduced the carrying value of our oil and natural gas properties by $1,304.4 million due to a full cost ceiling limitation at March 31, 2009. There were no full cost ceiling impairments recorded during the first six months of 2010.

General and administrative expenses increased $13.4 million, or 25.8%, to $65.5 million for the six months ended June 30, 2010 from $52.1 million for the comparable period in 2009 primarily due to $4.8 million in fees incurred related to our acquisition of Arena and increased compensation costs of $7.0 million resulting from an increase in non-cash stock compensation and the number of employees.

We recorded a net gain of $181.6 million ($160.6 million realized gain and $21.0 million unrealized gain) on our commodity derivative contracts for the six-month period ended June 30, 2010 compared to a net gain of $187.7 million ($193.2 million realized gains and $5.5 million unrealized loss) in the same period of 2009. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”

Loss on sale of assets decreased $26.3 million, or 99.7%, to $0.1 million for the six months ended June 30, 2010 from a $26.4 million loss for the comparable period in 2009, primarily due to a $26.1 million loss recorded on the sale of our gathering and compression assets during the 2009 period.

Other Income (Expense). Total other expense increased to $125.5 million in the six-month period ended June 30, 2010 from $81.3 million in the six-month period ended June 30, 2009. The increase is reflected in the table below.

Interest expense increased to $126.3 million for the six months ended June 30, 2010 from $83.2 million for the same period in 2009. This increase was primarily attributable to the higher average debt balances outstanding during the six months ended June 30, 2010 compared to the same period in 2009 primarily due to the issuance of our 9.875% Senior Notes in May 2009 and our 8.75% Senior Notes in December 2009. Also contributing to the increase was a $12.4 million net loss on our interest rate swaps for the six-month period ended June 30, 2010 compared to a $1.4 million net gain for the same period in 2009.

We reported an income tax expense of $0.1 million, net of income tax expense attributable to noncontrolling interest, for the six-month period ended June 30, 2010, compared to an income tax benefit of $1.5 million for the same period in 2009. The current period income tax expense represents an effective income tax rate for SandRidge of 0.1% compared to an effective income tax rate of 0.1% in the same period in 2009. We continue to have a low effective tax rate due to a full valuation allowance against our net deferred tax asset.

Our primary sources of liquidity and capital resources are cash flow generated from operations, borrowings under our senior credit facility, the issuance of equity and debt securities and, to a lesser extent, the sale of assets. Our primary uses of capital are expenditures related to our oil and natural gas properties and other fixed assets, the acquisition of oil and natural gas properties, the repayment of amounts outstanding on our senior credit

facility, the payment of dividends on our outstanding convertible perpetual preferred stock and interest payments on our outstanding debt. We maintain access to funds that may be needed to meet capital funding requirements through our senior credit facility.

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 ~~March 31,~~June 30, 2010, we had a working capital deficit of ~~$33.9~~$109.4 million compared to a surplus of $30.4 million at December 31, 2009. Current assets ~~increased $34.3~~decreased $29.8 million at ~~March 31,~~June 30, 2010, compared to current assets at December 31, 2009, primarily due to a ~~$35.6~~$42.3 million ~~increase~~decrease in our current derivative contract assets resulting from the ~~decrease in oil and natural gas market prices compared to the contract prices.~~settlement of commodity derivative contracts, including settlement of commodity derivative contracts with original contractual maturities after June 30, 2010, during 2010. Current liabilities increased ~~$98.6~~$110.0 million primarily as a result of a ~~$99.7~~$112.0 million increase in accounts payable and accrued expenses due to increased drilling activity and increased accrued interest on our fixed rate senior notes. Interest on our fixed rate senior notes is paid semi-annually.

Our cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2010 and 2009 were as follows:


	Three Months Ended March 31,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands)						(In thousands)
Cash flows provided by operating activities	$	147,602		$	75,344		$	258,459		$	144,147
Cash flows used in investing activities		(179,879	)		(349,937	)		(416,199	)		(270,298	)
Cash flows provided by financing activities		26,987			274,033			151,962			126,136

Net decrease in cash and cash equivalents	$	(5,290	)	$	(560	)	$	(5,778	)	$	(15	)

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

Net cash provided by operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2010 and 2009 was ~~$147.6~~$258.5 million and ~~$75.3~~$144.1 million, respectively. The increase in cash provided by operating activities in 2010 compared to 2009 was primarily due to a ~~52.6%~~46.9% increase in the combined average prices we received for our oil and natural gas ~~production.~~production and increased oil production, resulting from the properties acquired from Forest and a focus on increased oil drilling in 2010.

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration, development, production and acquisition of oil and natural gas reserves. These capital expenditures are necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and natural gas industry.

Cash flows used in investing activities ~~decreased~~increased to ~~$179.9~~$416.2 million in the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2010 from ~~$349.9~~$270.3 million in the comparable 2009 period primarily due to ~~reduced~~the receipt of proceeds from the sale of assets in the 2009 period that significantly offset capital expenditures during ~~the first quarter of 2010 and the receipt of $5.1 million in refunds of restricted deposits.~~that period.

Capital Expenditures. Our capital expenditures, on an accrual basis, by segment for the ~~three-month~~six-month periods ended ~~March~~June 30, 2010 and 2009 are summarized below:


	Three Months Ended March 31,				Six Months Ended June 30,
	2010		2009		2010		2009
	(In thousands)				(In thousands)
Capital Expenditures:
Exploration and production	$	192,077	$	261,884	$	411,050	$	383,231
Drilling and oil field services		9,417		2,377		17,612		2,201
Midstream gas services		20,422		23,948		36,759		41,288
Other		6,665		8,951		12,124		17,764

Total	$	228,581	$	297,160	$	477,545	$	444,484

Our financing activities provided ~~$27.0~~$152.0 million in cash for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2010 compared to ~~$274.0~~$126.1 million in the comparable period in 2009. ~~Proceeds from borrowings decreased to $273.3 million for~~Cash provided by financing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2010 ~~due to decreased~~was primarily comprised of $179.0 million of net borrowings, representing borrowings under our senior credit facility ~~during~~reduced by payments on our debt, offset slightly by the ~~period. We repaid approximately $232.0 million leaving net borrowings during the period~~payment of ~~approximately $41.3 million. During the three-month period ended March 31, 2009, we received net proceeds of approximately $243.3 million~~dividends on ~~the issuance of~~ our 8.5% convertible perpetual preferred ~~stock.~~stock and fees related to the amendment and restatement of the senior credit facility. Cash provided by financing activities during the six months ended June 30, 2009 was generated primarily by the private placement of 8.5% convertible perpetual preferred stock and the registered underwritten offering of common stock that provided combined proceeds of approximately $351.0 million, the majority of which were used to pay down amounts outstanding under the senior credit facility.

Senior Credit Facility.The amount we may borrow under our senior credit facility is limited to a borrowing base, which is currently $850.0 million, and is subject to periodic redeterminations. The borrowing base is available to be drawn on subject to limitations based on its terms and certain financial covenants. The borrowing base is determined based upon proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves. Because the value of our proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and our success in developing reserves, may affect the borrowing base.

In April 2010, we ~~extended the maturity of~~amended and restated our ~~senior credit facility. The amendment and restatement of the~~ $1.75 billion senior credit facility, ~~extends~~extending the maturity date to April 15, 2014 from November 21, 2011 and ~~affirms~~affirming the borrowing base at $850.0 million. The senior credit facility received commitments from 27 participating lender institutions, three of which ~~three are~~were new to the bank group. The largest commitment held by any individual lender is 5.9%. ~~The~~Under the terms of the amended and restated ~~senior credit~~ facility, ~~contains substantially~~ the ~~same covenants as the previous amendment. The~~required ratio of total funded debt to EBITDAX ~~changes~~will change from the current limit of 4.5:1.0 to 4.25:1.0 effective June 30, 2011 and then to 4.0:1.0 by June 30, 2012. The ratio of EBITDAX to interest expense plus current maturities of long-term debt covenant ~~has been~~was eliminated and our ability to make investments ~~has been increased.~~was increased from the previous terms. The remaining covenants were substantially unchanged from the previous agreement. We remain in compliance with all debt covenants and the next redetermination of the borrowing base is scheduled to occur in the fourth quarter of 2010.

Long-term obligations under the senior credit facility and other long-term debt consist of the following at ~~March 31,~~June 30, 2010 (in thousands):


Senior credit facility	$	45,214	$	186,000
Other notes payable		31,433		28,373
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		650,000		650,000
9.875% Senior Notes due 2016, net of $14,074 discount		351,426
9.875% Senior Notes due 2016, net of $13,658 discount				351,842
8.0% Senior Notes due 2018		750,000		750,000
8.75% Senior Notes due 2020, net of $7,296 discount		442,704
8.75% Senior Notes due 2020, net of $7,182 discount				442,818

Total debt	$	2,620,777	$	2,759,033

The ~~indentures governing the~~ senior credit facility and the indentures governing the senior notes included in the table above contain financial covenants and include limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers.

Maturities of Long-Term Debt. Aggregate maturities of long-term debt, ~~reflecting the April 2010 amendment and restatement of our senior credit facility and~~ excluding discounts, ~~during~~for the next five fiscal years are as follows (in thousands):


2010	$	8,110	$	5,050
2011		7,294		7,294
2012		1,051		1,051
2013		1,120		1,120
2014		396,405		537,191
Thereafter		2,228,167		2,228,167

Total debt	$	2,642,147	$	2,779,873

For more information about the senior credit facility, the senior notes and our other long-term debt obligations, see Note 10 to the condensed consolidated financial statements included in this ~~report.~~Quarterly Report.

For 2010, we have budgeted ~~$800.0~~$875.0 million for capital expenditures, including planned expenditures related to properties owned by Arena and excluding other acquisitions. The majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels or if we are unable to obtain capital on attractive terms. We may increase or decrease planned capital expenditures depending on oil and natural gas prices, asset sales and the availability of capital through the issuance of additional equity or long-term ~~debt or equity.~~debt.

Our revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depend on numerous factors beyond our control such as economic conditions, regulatory developments and competition from other energy sources. The energy markets and oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future. Our derivative arrangements serve to mitigate a portion of the effect of this price volatility on our cash flows, and while derivative contracts for the majority of expected ~~2010,~~ 2011 and 2012 oil production are in place, there are no fixed price swap derivative contracts in place for our natural gas production beyond 2010. In addition, we have and will continue to need to incur capital expenditures in 2010 in order to achieve production targets contained in certain gathering and treating arrangements. We are dependent on the availability of borrowings under our senior credit facility, along with cash flows from operating activities, to fund those capital expenditures. Based on anticipated oil and natural gas prices,

~~and~~ availability under our senior credit facility and anticipated proceeds from

the sales of assets, we expect to be able to fund our planned capital expenditures for 2010. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact our ability to comply with the financial covenants under our senior credit facility, which in turn would limit further borrowings to fund capital expenditures. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our derivative contracts.

As of ~~March 31,~~June 30, 2010, our cash and cash equivalents were ~~$2.6~~$2.1 million and we had approximately ~~$2.6~~$2.8 billion in total debt outstanding with ~~$45.2~~$186.0 million outstanding under our senior credit facility. As of and for the ~~three-month period~~three and six-month periods ended ~~March 31,~~June 30, 2010, we were in compliance with all of the covenants under all of our senior notes and our senior credit facility. As of ~~May 5,~~August 4, 2010, our cash and cash equivalents were approximately ~~$5.7~~$2.7 million, the balance outstanding under our senior credit facility was ~~$137.0~~$402.5 million and we had $25.4 million outstanding in letters of credit.

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

Volatility in the capital markets may increase costs associated with issuing debt due to increased interest rates, and may affect our ability to access these markets. Currently, we do not believe our liquidity has been, or in the near future will be, materially affected by recent events in the global financial markets. Nevertheless, we continue to monitor events and circumstances surrounding each of the 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 in 2008 of Lehman Brothers Commodity Services, Inc. (“Lehman Brothers”), a lender responsible for 0.29% of the obligations under our senior credit facility. As a result of the April 2010 amendment and restatement of the senior credit facility, Lehman Brothers is no longer a part of our bank group. We cannot predict with any certainty the impact to us of any ~~further~~ disruptions in the credit markets.

Based upon the current level of operations and anticipated growth, we believe our cash flow from operations, current cash on hand and availability under our senior credit facility, together with anticipated proceeds from asset sales and potential access to the credit markets, will be sufficient to meet our capital expenditures budget, debt service requirements and working capital needs for the next 12twelve months. We have the ability to reduce our capital expenditures budget if cash flows are not available.

On July 16, 2010, the stockholders of each of SandRidge and Arena approved the acquisition by SandRidge of all of the outstanding common stock of Arena, and the transaction was completed. In connection with the acquisition, we issued 4.7771 shares of our common stock and paid $4.50 in cash to Arena stockholders for each outstanding share of unrestricted Arena common stock. In addition, outstanding options to purchase Arena common stock that were deemed exercised pursuant to the merger agreement were converted into shares of our common stock pursuant to a formula provided for in the merger agreement, and outstanding shares of Arena restricted common stock were converted into restricted shares of our common stock pursuant to a formula in the merger agreement. The total purchase price is estimated to be approximately $1.4 billion. The effect of the Arena acquisition was to increase our reserve base primarily through the issuance of equity rather than through borrowings, except as necessary to pay the cash portion of the purchase price. Additionally, the acquisition is expected to increase our stockholders’ equity by an estimated $1.6 billion resulting in a positive ratio of debt to capital. See Note 17 to the condensed consolidated financial statements included in this Quarterly Report for further discussion of the Arena acquisition.

On July 22, 2010, we signed an agreement to sell certain deep acreage rights for approximately $139.0 million in cash. We will retain the shallow rights associated with this acreage. The sale is expected to close in the third quarter of 2010 and is subject to customary closing conditions. The proceeds from this sale will be available to fund capital expenditures or pay down debt.

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

Commodity Price Risk. Our most significant market risk relates to the prices we receive for our oil and natural gas production. Due to the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements for the purpose of reducing the variability of oil and natural gas 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 prevailing current market conditions. We do not intend to enter into derivative contracts that would exceed our expected production volumes for the period covered by the derivative arrangement. Our current credit agreement limits our ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. Future credit agreements could require a minimum level of commodity price hedging.

The use of derivative contracts also involves the risk that the counterparties will be unable to meet their obligations under the contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. As of ~~March 31,~~June 30, 2010, we had 1920 approved derivative counterparties, 1819 of which are lenders under our senior credit facility. We currently have derivative contracts outstanding with 1112 of these ~~counterparties. We have no derivative contracts in 2010 and beyond with~~ counterparties, ~~other than those that~~all of which are lenders under our senior credit facility.

We use, and may continue to use, a variety of commodity-based derivative contracts, including fixed-price swaps and basis protection swaps. Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period. Our natural gas fixed price swap transactions are settled based upon New York Mercantile Exchange prices, and our natural gas basis protection swap transactions are settled based upon the index price of natural gas at the Waha hub, a ~~West~~west Texas gas marketing and delivery center, and the Houston Ship Channel. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts ~~occurs~~are settled in the production month.

We have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which reflects changes in oil and natural gas 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 the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.

On ~~March 31,~~June 30, 2010, our open oil and natural gas commodity derivative contracts consisted of the following:


Period and Type of Contract	Notional (in MBbl)	Weighted Avg. Fixed Price
January 2011 — March 2011
Price swap contracts	1,260	$	86.26
April 2011 — June 2011
Price swap contracts	1,274	$	86.26
July 2011 — September 2011
Price swap contracts	1,472	$	85.90
October 2011 — December 2011
Price swap contracts	1,472	$	85.90
January 2012 — March 2012
Price swap contracts	1,638	$	87.08
April 2012 — June 2012
Price swap contracts	1,729	$	86.98
July 2012 — September 2012
Price swap contracts	1,778	$	86.96
October 2012 — December 2012
Price swap contracts	1,840	$	86.91


Period and Type of Contract	Notional (MMcf)(1)	Weighted Avg. Fixed Price			Notional (MMcf)(1)	Weighted Avg. Fixed Price
April 2010 — June 2010
Price swap contracts	19,793	$	7.32
Basis swap contracts	20,475	$	(0.74	)
July 2010 — September 2010
Price swap contracts	20,010	$	7.55		13,268	$	7.54
Basis swap contracts	20,700	$	(0.74	)	20,700	$	(0.74	)
October 2010 — December 2010
Price swap contracts	20,010	$	7.97		13,268	$	7.81
Basis swap contracts	20,700	$	(0.74	)	20,700	$	(0.74	)
January 2011 — March 2011
Basis swap contracts	25,650	$	(0.47	)	25,650	$	(0.47	)
April 2011 — June 2011
Basis swap contracts	25,935	$	(0.47	)	25,935	$	(0.47	)
July 2011 — September 2011
Basis swap contracts	26,220	$	(0.47	)	26,220	$	(0.47	)
October 2011 — December 2011
Basis swap contracts	26,220	$	(0.47	)	26,220	$	(0.47	)
January 2012 — March 2012
Basis swap contracts	28,210	$	(0.55	)	28,210	$	(0.55	)
April 2012 — June 2012
Basis swap contracts	28,210	$	(0.55	)	28,210	$	(0.55	)
July 2012 — September 2012
Basis swap contracts	28,520	$	(0.55	)	28,520	$	(0.55	)
October 2012 — December 2012
Basis swap contracts	28,520	$	(0.55	)	28,520	$	(0.55	)
January 2013 — March 2013
Basis swap contracts	3,600	$	(0.46	)	3,600	$	(0.46	)
April 2013 — June 2013
Basis swap contracts	3,640	$	(0.46	)	3,640	$	(0.46	)
July 2013 — September 2013
Basis swap contracts	3,680	$	(0.46	)	3,680	$	(0.46	)
October 2013 — December 2013
Basis swap contracts	3,680	$	(0.46	)	3,680	$	(0.46	)

The following table summarizes the cash settlements and valuation gains and losses on our commodity derivative contracts for the ~~three-month~~three and six-month periods ended ~~March 31,~~June 30, 2010 and 2009 (in thousands):

Credit Risk. A portion of our liquidity is concentrated in derivative contracts that enable us to mitigate a portion of our exposure to oil and natural gas prices and interest rate volatility. We periodically review the credit quality of each counterparty to our derivative contracts and the level of financial exposure we have to each counterparty to limit our credit risk exposure with respect to these contracts. Additionally, we apply a credit default

risk rating factor for our counterparties in determining the fair value of our derivative contracts. The counterparties for all of our ~~hedging~~derivative transactions have an “investment grade” credit rating. The weighted average credit default swap rate for our counterparties was ~~0.4%~~1.1% and 0.3% at ~~March 31,~~June 30, 2010 and December 31, 2009, respectively.

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 currently consists of 27 financial institutions with commitments ranging from 0.57% to 5.9%.

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

In addition to commodity price derivative arrangements, we may enter into derivative transactions to fix the interest we pay on a portion of the money we borrow under our credit agreement. We have entered into two $350.0 million notional interest rate swap agreements to fix the variable ~~LIBOR~~ interest rate on the Senior Floating Rate Notes through April 1, 2013. The first interest rate swap agreement fixes the ~~LIBOR interest~~rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 1, 2011. The second interest rate swap agreement fixes the ~~LIBOR~~ rate on the Senior Floating Rate Notes at an annual rate of 6.69% for the period from April 1, 2011 to April 1, 2013. The two interest rate swaps effectively serve to fix the variable interest rate on our Senior Floating Rate Notes for the majority of the term of these notes. These swaps have not been designated as hedges.

Our interest rate swaps reduce our market risk on our Senior Floating Rate Notes. We use sensitivity analyses to determine the impact that market risk exposures could have on our variable interest rate borrowings if not for our interest rate swaps. Based on the $350.0 million outstanding balance of our Senior Floating Rate Notes at ~~March 31,~~June 30, 2010, a one percent change in the applicable rates, with all other variables held constant, would have resulted in a change in our interest expense of approximately $0.9 million and $1.8 million for the ~~three-month period~~three and six-month periods ended ~~March 31, 2010.~~June 30, 2010, respectively.

The following table summarizes the cash settlements and valuation gains and losses ~~of $3.8 million and $0.3 million were recorded in interest expense in the condensed consolidated statements of operations for the change in fair value of the~~on our interest rate swaps for the ~~three-month~~three and six-month periods ended ~~March 31,~~June 30, 2010 and 2009 respectively. Realized losses of $2.1 million and $1.0 million were included in interest expense in the condensed consolidated statements of operations for the three-month periods ended March 31, 2010 and 2009, respectively.(in thousands):

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this Quarterly Report. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of ~~March 31,~~June 30, 2010 to provide reasonable assurance that the information required to be disclosed by us in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

There was no change in our internal control over financial reporting during the quarter ended ~~March 31,~~June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

On ~~April 3,~~July 16, 2010, SandRidge and one of its subsidiaries ~~entered into an agreement to acquire~~completed the acquisition of all of the outstanding shares of common stock of Arena for a combination of ~~company~~Company common stock and cash. ~~Since~~As disclosed in SandRidge’s Quarterly Report on Form 10-Q for the period ended March 31, 2010, after the April 3, 2010 announcement of the transaction, nine putative class action lawsuits ~~have been~~challenging the transaction were filed in Oklahoma and in Nevada by Arena ~~shareholders, purportedly on behalf of persons similarly situated, challenging the transaction. The~~shareholders. All nine lawsuits ~~contain~~contained substantially ~~the same~~similar allegations — that Arena’s directors breached their fiduciary duties by negotiating and approving the transaction and by administering a sale process that failed to maximize shareholder value and that Arena, SandRidge and/or a subsidiary of SandRidge aided and abetted such alleged breaches of fiduciary duty. One lawsuit was filed in federal court and also alleged violations of federal securities laws in connection with allegedly issuing an incomplete and misleading proxy statement. The lawsuits ~~seek,~~sought, among other relief, an injunction preventing the consummation of the merger and, in certain cases, unspecified damages.

SandRidge believes all of the lawsuits are without merit and ~~intends~~that it has valid defenses to ~~defend itself vigorously against them.~~all claims. Nevertheless, in order to avoid the cost, disruption and uncertainty of litigation — and without admitting any liability or wrongdoing — on May 27, 2010, SandRidge and Arena reached an agreement in principle for the coordinated settlement of six of the putative stockholder class actions related to the merger, including five of the lawsuits filed in state courts in Nevada and Oklahoma and the lawsuit filed in federal court. In connection with this agreement, SandRidge and Arena agreed to provide certain additional disclosures about the merger and to amend certain provisions of the merger agreement with respect to payment of termination fees and non-solicitation of alternative takeover proposals. The additional disclosures about the merger were made in joint Current Reports on Form 8-K filed by SandRidge and Arena on May 28, 2010.

Prior to reaching the May 27 settlement of six actions, the same actions had proceeded on a coordinated basis for purposes of discovery before the District Court in Washoe County, Reno, Nevada (the “Nevada Court”). The settlement was preliminarily approved in a written order by the Nevada Court on June 14, 2010. Pursuant to this order, class members may opt out of the settlement class or serve written objections to the settlement on or before August 27, 2010. The Nevada Court will conduct a final approval hearing regarding the settlement on September 10, 2010. The titles of the lawsuits subject to the settlement, the courts in which they were filed, and the dates they were filed are as follows:

~~In addition,~~ The three remaining lawsuits arising from the acquisition of Arena were stayed by the District Court of Oklahoma County on May 10, 2010. On July 1, 2010, the Plaintiffs commenced appellate proceedings before the Oklahoma Supreme Court challenging the stay and filed an emergency motion seeking to expedite the appeal. On July 8, 2010, the Oklahoma Supreme Court denied the emergency motion and, as of the date of this Quarterly

Report, there has been no further action with respect to these proceedings. SandRidge believes these lawsuits are without merit and intends to defend itself vigorously against them. The titles of the stayed lawsuits, the courts in which they were filed, and the dates they were filed are as follows:

SandRidge is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, we are not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on our financial condition, operations or cash flows.

We describe certain of our business risk factors below. This description includes material changes to the description of the risk factors previously disclosed in Part I, Item 1A of the 2009 Form 10-K.

~~If the pending merger with Arena occurs,~~The integration of SandRidge and Arena will present significant challenges.

~~If the pending merger with Arena occurs, the~~The integration of the operations of ~~Arena~~SandRidge and ~~SandRidge~~Arena and the consolidation of ~~such~~Arena’s operations into those of SandRidge will require the dedication of management resources, which will

temporarily detract attention from the day-to-day business of the combined company. The difficulties of assimilation may be increased by the necessity of coordinating geographically separated organizations, integrating operations and systems and personnel with disparate business backgrounds and combining different corporate cultures. The process of combining the organizations may cause an interruption of, or a loss of momentum in, the activities of any or all of ~~the companies’ businesses,~~our business, which could have an adverse effect on ~~the~~our revenues and operating results, ~~of the combined company,~~ at least in the near term. The failure to successfully integrate SandRidge and Arena or to successfully manage the challenges presented by the integration process may result in ~~SandRidge and Arena not achieving~~our inability to achieve the anticipated potential benefits of the merger.

New derivatives legislation and regulation could adversely affect our ability to hedge risks associated with our business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act creates a new regulatory framework for oversight of derivatives transactions by the Commodity Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”). Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-Frank Act contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While SandRidge may qualify for one or more of such exceptions, the scope of these exceptions is uncertain and will be further defined through rulemaking proceedings at the CFTC and SEC in the coming months. Further, although we may qualify for exceptions, our derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the new legislation, which may increase our transaction costs or make it more difficult for us to enter into hedging transactions on favorable terms. Our inability to enter into hedging transactions on favorable terms, or at all, could increase our operating expenses and put us at increased exposure to risks of adverse changes in oil and natural gas prices, which, in turn, could adversely affect the predictability of cash flows from sales of oil and natural gas.

The Dodd-Frank Act also expands the CFTC’s power to impose position limits on specific categories of swaps (excluding swaps entered into forbona fide hedging purposes), and establishes a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets.

Additionally, in January 2010, the CFTC proposed rules to establish position limits on derivatives that reference major energy commodities, including oil and natural gas. The proposed all-months-combined position limits would be 10% of the first 25,000 contracts of open interest and 2.5% of open interest beyond 25,000 contracts. Although the current version of the CFTC’s proposal includes an exemption forbona fide hedges relating to inventory or anticipatory purchases or sales of the commodity, the CFTC is evaluating whether position limits should be applied consistently across all markets and participants.

As part of our restricted stock program, we make required tax payments on behalf of employees when their 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 ~~March 31,~~June 30, 2010, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:

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


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

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


PART I. FINANCIAL INFORMATION
ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statement of Changes in Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3540
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	4657
ITEM 4.	Controls and Procedures	4960
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	5061
ITEM 1A.	Risk Factors	5062
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5163
ITEM 6.	Exhibits	5163


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

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

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


	Gain on Derivative Contracts		Interest Expense			Total
Change in unrealized gains (losses) on derivative contracts held at March 31, 2010	$	19,359	$	(3,848	)	$	15,511


	March 31, 2010			December 31, 2009
Oil and natural gas properties:
Proved	$	6,160,856		$	5,913,408
Unproved		226,452			281,811

Total oil and natural gas properties		6,387,308			6,195,219
Less accumulated depreciation, depletion and impairment(1)		(4,272,882	)		(4,223,437	)

Net oil and natural gas properties capitalized costs		2,114,426			1,971,782

Land		13,937			13,937
Non oil and natural gas equipment(2)		616,567			594,132
Buildings and structures		83,800			78,584

Total		714,304			686,653
Less accumulated depreciation, depletion and amortization		(232,121	)		(224,792	)

Net capitalized costs		482,183			461,861

Total property, plant and equipment, net	$	2,596,609		$	2,433,643


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

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


Type of Contract	Location of (Gain) Loss Recognized in Income	Amount of (Gain) Loss Recognized in Income
		Three Months Ended June 30,						Six Months Ended June 30,
		2010			2009			2010			2009
Oil and natural gas swaps	(Gain) loss on derivative contracts	$	(119,621	)	$	18,992		$	(181,573	)	$	(187,655	)
Interest rate swaps	Interest expense		6,477			(2,641	)		12,412			(1,354	)

Total		$	(113,144	)	$	16,351		$	(169,161	)	$	(189,009	)


Type of Contract	Location of (Gain) Loss Recognized in Income	Amount of (Gain) Loss Recognized in Income
Type of Contract	Location of (Gain) Loss Recognized in Income	2010			2009
Interest rate swap	Interest expense	$	5,935		$	1,287
Oil and natural gas swaps	Gain on derivative contracts		(61,952	)		(206,647	)

Total		$	(56,017	)	$	(205,360	)


	2010			2009
Realized gain	$	(42,593	)	$	(98,389	)
Unrealized gain		(19,359	)		(108,258	)

Gain on derivative contracts	$	(61,952	)	$	(206,647	)


	July 16, 2010
Current assets	$	80,133
Oil and natural gas properties(1)		1,382,383
Other property, plant and equipment		9,948
Long-term deferred tax assets		31,561
Goodwill(2)		366,902

Total assets acquired		1,870,927

Current liabilities		29,188
Long-term deferred tax liability(2)		408,541
Other non-current liabilities		8,918

Total liabilities assumed		446,647

Net assets acquired	$	1,424,280


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1, 2010 — January 31, 2010	258,024	$	10.63	N/A	N/A
February 1, 2010 — February 28, 2010	1,326	$	7.94	N/A	N/A
March 1, 2010 — March 31, 2010	2,088	$	7.70	N/A	N/A


SandRidge Energy, Inc.

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

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