SandRidge Energy (SD) 10-Q 2011 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2011

OR

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

For the transition period from              to             

Commission File Number: 001-33784

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	20-8084793
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
123 Robert S. Kerr Avenue Oklahoma City, Oklahoma	73102
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:

(405) 429-5500

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

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

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

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

Large accelerated filer	þ	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on October 31, 2011, was 412,099,692.

SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended September 30, 2011

INDEX

PART I. FINANCIAL INFORMATION
ITEM 1.	Financial Statements	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statement of Changes in Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	50
ITEM 4.	Controls and Procedures	51
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	52
ITEM 1A.	Risk Factors	52
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
ITEM 6.	Exhibits	53

2

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning capital expenditures, the Company’s liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy and other statements concerning the Company’s operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on the Company’s current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances. However, whether actual results and developments will conform with the Company’s expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part II of this Quarterly Report and in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (the “2010 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 the 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. The Company undertakes no obligation to publicly update or revise any forward-looking statements.

3

PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

	September  30, 2011			December  31, 2010
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	325,437		$	5,863
Accounts receivable, net		174,396			146,118
Derivative contracts		96,457			5,028
Inventories		11,672			3,945
Other current assets		20,032			14,636
Total current assets		627,994			175,590
Oil and natural gas properties, using full cost method of accounting
Proved		8,697,142			8,159,924
Unproved		681,886			547,953
Less: accumulated depreciation, depletion and impairment		(4,707,089	)		(4,483,736	)
		4,671,939			4,224,141
Other property, plant and equipment, net		531,875			509,724
Restricted deposits		27,892			27,886
Derivative contracts		213,901			—
Goodwill		235,396			234,356
Other assets		109,716			59,751
Total assets	$	6,418,713		$	5,231,448
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	1,035		$	7,293
Accounts payable and accrued expenses		413,830			376,922
Billings and estimated contract loss in excess of costs incurred		42,269			31,474
Derivative contracts		9,020			103,409
Asset retirement obligation		25,360			25,360
Total current liabilities		491,514			544,458
Long-term debt		2,812,775			2,901,793
Derivative contracts		6,867			124,173
Asset retirement obligation		97,223			94,517
Other long-term obligations		24,430			19,024
Total liabilities		3,432,809			3,683,965
Commitments and contingencies (Note 15)
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at September 30, 2011 and December 31, 2010; aggregate liquidation preference of $265,000		3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at September 30, 2011 and December 31, 2010; aggregate liquidation preference of $200,000		2			2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at September 30, 2011 and December 31, 2010; aggregate liquidation preference of $300,000		3			3
Common stock, $0.001 par value, 800,000 shares authorized; 412,986 issued and 412,400 outstanding at September 30, 2011 and 406,830 issued and 406,360 outstanding at December 31, 2010		399			398
Additional paid-in capital		4,557,005			4,528,912
Treasury stock, at cost		(4,700	)		(3,547	)
Accumulated deficit		(2,548,497	)		(2,989,576	)
Total SandRidge Energy, Inc. stockholders’ equity		2,004,215			1,536,195
Noncontrolling interest		981,689			11,288
Total equity		2,985,904			1,547,483
Total liabilities and equity	$	6,418,713		$	5,231,448

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

4

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
				(Unaudited)
Revenues
Oil and natural gas	$	318,453		$	209,998		$	897,506		$	529,578
Drilling and services		25,547			5,252			75,118			14,913
Midstream and marketing		15,092			23,281			53,663			73,868
Other		4,661			6,702			15,088			20,308
Total revenues		363,753			245,233			1,041,375			638,667
Expenses
Production		86,580			66,086			242,371			172,367
Production taxes		10,368			8,904			33,610			19,146
Drilling and services		16,209			4,187			49,308			12,420
Midstream and marketing		14,624			20,779			52,780			66,064
Depreciation and depletion — oil and natural gas		86,725			91,237			236,798			197,834
Depreciation and amortization — other		13,551			12,441			39,918			36,564
General and administrative		36,272			61,878			108,364			127,419
(Gain) loss on derivative contracts		(596,736	)		67,195			(489,096	)		(114,378	)
(Gain) loss on sale of assets		(422	)		(44	)		(1,148	)		39
Total expenses		(332,829	)		332,663			272,905			517,475
Income (loss) from operations		696,582			(87,430	)		768,470			121,192
Other income (expense)
Interest income		51			69			94			236
Interest expense		(59,003	)		(63,641	)		(180,171	)		(189,989	)
Loss on extinguishment of debt		—			—			(38,232	)		—
Other (expense) income, net		(672	)		1,356			662			2,062
Total other expense		(59,624	)		(62,216	)		(217,647	)		(187,691	)
Income (loss) before income taxes		636,958			(149,646	)		550,823			(66,499	)
Income tax expense (benefit)		954			(457,248	)		(6,013	)		(457,086	)
Net income		636,004			307,602			556,836			390,587
Less: net income attributable to noncontrolling interest		60,895			1,313			74,055			3,547
Net income attributable to SandRidge Energy, Inc.		575,109			306,289			482,781			387,040
Preferred stock dividends		13,881			8,632			41,702			25,894
Income available to SandRidge Energy, Inc. common stockholders	$	561,228		$	297,657		$	441,079		$	361,146
Earnings per share
Basic	$	1.41		$	0.82		$	1.11		$	1.41
Diluted	$	1.16		$	0.73		$	0.97		$	1.24
Weighted average number of common shares outstanding
Basic		399,270			361,687			398,656			257,028
Diluted		497,700			419,137			496,428			313,283

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

5

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands)

	SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock				Common Stock					Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Noncontrolling Interest			Total
	Shares		Amount		Shares			Amount
	(Unaudited)
Nine months ended September 30, 2011
Balance, December 31, 2010		7,650	$	8		406,360		$	398	$	4,528,912		$	(3,547	)	$	(2,989,576	)	$	11,288		$	1,547,483
Issuance of units by royalty trusts		—		—		—			—		—			—			—			917,528			917,528
Distributions to noncontrolling interest owners		—		—		—			—		—			—			—			(21,182	)		(21,182	)
Stock issuance expense		—		—		—			—		(231	)		—			—			—			(231	)
Purchase of treasury stock		—		—		—			—		—			(10,626	)		—			—			(10,626	)
Retirement of treasury stock		—		—		—			—		(10,626	)		10,626			—			—			—
Stock purchases — retirement plans, net of distributions		—		—		(116	)		—		2,563			(1,153	)		—			—			1,410
Stock-based compensation		—		—		—			—		36,336			—			—			—			36,336
Stock-based compensation excess tax benefit		—		—		—			—		52			—			—			—			52
Issuance of restricted stock awards, net of cancellations		—		—		6,156			1		(1	)		—			—			—			—
Net income		—		—		—			—		—			—			482,781			74,055			556,836
Convertible perpetual preferred stock dividends		—		—		—			—		—			—			(41,702	)		—			(41,702	)
Balance, September 30, 2011		7,650	$	8		412,400		$	399	$	4,557,005		$	(4,700	)	$	(2,548,497	)	$	981,689		$	2,985,904

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

6

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Nine Months Ended September 30,
	2011			2010
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	556,836		$	390,587
Adjustments to reconcile net income to net cash provided by operating activities
Provision for doubtful accounts		1,622			102
Inventory obsolescence		145			200
Depreciation, depletion and amortization		276,716			234,398
Debt issuance costs amortization		8,624			8,044
Discount amortization on long-term debt		1,766			1,595
Loss on extinguishment of debt		38,232			—
Deferred income taxes		(6,986	)		(456,437	)
Unrealized (gain) loss on derivative contracts		(527,166	)		135,364
(Gain) loss on sale of assets		(1,148	)		39
Investment loss (income)		653			(191	)
Stock-based compensation		28,458			24,174
Changes in operating assets and liabilities		(49,796	)		1,337
Net cash provided by operating activities		327,956			339,212
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment		(1,311,383	)		(694,187	)
Acquisition of assets, net of cash received of $0 and $39,518, respectively		(22,751	)		(138,428	)
Proceeds from sale of assets		624,767			113,422
Refunds of restricted deposits		—			5,095
Net cash used in investing activities		(709,367	)		(714,098	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		2,033,000			1,595,914
Repayments of borrowings		(2,130,042	)		(1,179,083	)
Premium on debt redemption		(30,338	)		—
Debt issuance costs		(19,652	)		(11,720	)
Proceeds from issuance of royalty trust units		917,528			—
Distributions to royalty trust unitholders		(18,431	)		—
Noncontrolling interest distributions		(2,751	)		(3,511	)
Noncontrolling interest contributions		—			306
Stock issuance expense		(231	)		(87	)
Stock-based compensation excess tax benefit		52			31
Purchase of treasury stock		(12,048	)		(5,335	)
Dividends paid — preferred		(46,243	)		(28,525	)
Derivative settlements		10,141			1,624
Net cash provided by financing activities		700,985			369,614
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		319,574			(5,272	)
CASH AND CASH EQUIVALENTS, beginning of year		5,863			7,861
CASH AND CASH EQUIVALENTS, end of period	$	325,437		$	2,589
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	22,010		$	101,406
Convertible perpetual preferred stock dividends payable	$	13,191		$	5,816
Adjustment to oil and natural gas properties for estimated contract loss	$	19,000		$	98,000
Common stock issued in connection with acquisition	$	—		$	1,246,334

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

7

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Business. SandRidge Energy, Inc. (including its subsidiaries, the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on development and production activities related to the exploitation of its significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. The Company’s primary areas of focus are the Permian Basin in West Texas and the Mississippian formation in the Mid-Continent. The Company owns and operates other interests in the West Texas Overthrust (“WTO”), Mid-Continent, Gulf Coast and Gulf of Mexico. The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and treating facilities, a gas marketing business, an oil field services business, including a drilling rig business, and tertiary oil recovery operations.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2010 have been derived from the audited financial statements contained in the Company’s 2010 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 2010 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, which consist only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2010 Form 10-K.

Reclassifications. Certain amounts in the prior periods presented have been reclassified to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported 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 depends on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. 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 fixed price swap contracts are in place for the majority of expected oil production for 2011 through 2013, fixed price swap contracts are in place for only a portion of expected oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. See Note 12 for the Company’s open oil and natural gas commodity derivative contracts.

The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements. The Company depends on the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”), along with cash flows from operating activities and the proceeds from planned asset sales or other asset monetizations, to fund those capital expenditures. Based on anticipated oil and natural gas prices, availability under the senior credit facility, potential access to the capital markets and anticipated proceeds from sales or other monetizations of assets, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2011 and for 2012. 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 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 11 for discussion of the financial covenants in the senior credit facility.

2. Recent Accounting Pronouncements

For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2010 Form 10-K.

Recently Adopted Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”). ASU 2010-06 requires additional disclosures and clarifies existing disclosure requirements about

8

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

fair value measurement as set forth in Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures. The new disclosure requirements regarding activity in Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010, were implemented by the Company in the first quarter of 2011. The implementation of ASU 2010-06 had no impact on the Company’s financial position or results of operations. See Note 4.

Recent Accounting Pronouncements Not Yet Adopted. In May 2011, the FASB issued Accounting Standards Update 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 clarifies the FASB’s intent about the application of existing fair value measurements as set forth in ASC Topic 820 and requires additional disclosure information regarding valuation processes and inputs used. The new disclosure requirements are effective for interim and annual reporting periods beginning after December 15, 2011. As the additional requirements under ASU 2011-04, which will be implemented January 1, 2012, pertain to fair value measurement disclosures, no effect on the Company’s financial position or results of operations is expected.

In September 2011, the FASB issued Accounting Standards Update 2011-08, “Testing Goodwill for Impairment” (“ASU 2011-08”). ASU 2011-08 allows an entity the option of performing a qualitative assessment to determine whether it is necessary to perform the current two-step annual impairment test. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit more-likely-than-not exceeds the carrying amount, the two-step impairment test is not required. ASU 2011-08 does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test goodwill annually for impairment or amend the requirement to test goodwill for impairment between annual tests if events or circumstances warrant. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. The Company is currently evaluating the impact of this guidance, which it will adopt on January 1, 2012.

3. Acquisitions and Divestitures

Arena Acquisition. On July 16, 2010, the Company acquired all of the outstanding common stock of Arena Resources, Inc. (“Arena”) for an aggregate purchase price of approximately $1.4 billion. In connection with the acquisition (the “Arena Acquisition”), the Company incurred approximately $0.6 million and $15.4 million in fees related to the acquisition during the nine-month periods ended September 30, 2011 and 2010, respectively, which have been included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations.

In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition. Upon receipt of final confirmatory information for certain accruals in the second quarter of 2011 and completion of the 2010 Arena federal income tax return, the Company increased current assets, the net deferred tax liability and the value assigned to goodwill and reduced current liabilities. The accompanying condensed consolidated balance sheet at December 31, 2010 included certain preliminary allocations of the purchase price for the Arena Acquisition. During the first six months of 2011, the Company updated certain estimates used in the purchase price allocation, primarily with respect to deferred taxes and other accruals, resulting in adjustments of $1.0 million to goodwill.

The following table summarizes the final valuation of assets acquired and liabilities assumed in connection with the Arena Acquisition (in thousands):

Current assets	$	83,563
Oil and natural gas properties(1)		1,587,630
Other property, plant and equipment		5,963
Deferred tax assets		48,997
Other long-term assets		16,181
Goodwill(2)		235,396
Total assets acquired		1,977,730
Current liabilities		38,964
Long-term deferred tax liability(2)		503,483
Other long-term liabilities		8,851
Total liabilities assumed		551,298
Net assets acquired	$	1,426,432

(1) Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $105.58 per barrel of oil and $8.56 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The prices utilized were based upon forward commodity strip prices, as of July 16, 2010, for the first four years and escalated for inflation at a rate of 2.5% annually beginning with the fifth year through the end of production, which was more than 50 years. Approximately 91.0% of the fair value allocated to oil and natural gas properties is attributed to oil reserves.

9

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

(2) The Company received carryover tax basis in Arena’s assets and liabilities because the merger was not a taxable transaction under the Internal Revenue Code (“IRC”). Based upon the final purchase price allocation, a step-up in basis related to the property acquired from Arena resulted in a net deferred tax liability of approximately $454.5 million, which in turn contributed to an excess of the consideration transferred to acquire Arena over the estimated fair value on the acquisition date of the net assets acquired, or goodwill. See Note 6 for further discussion of goodwill and Note 13 for further discussion of the net deferred tax liability.

The following unaudited pro forma results of operations are provided for the three and nine-month periods ended September 30, 2010 as though the Arena Acquisition had been completed as of the beginning of the respective period. The pro forma information is based on the Company’s consolidated results of operations for the three and nine-month periods ended September 30, 2010, Arena’s historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma combined results of operations for the three and nine-month periods ended September 30, 2010 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 purchase price allocation. These 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. The pro forma results of operations do not include any cost savings or other synergies that resulted from the acquisition or any estimated costs that have been incurred by the Company to integrate Arena. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

	Three Months Ended September 30, 2010				Nine Months Ended September 30, 2010
	Actual		Pro Forma		Actual		Pro Forma
	(in thousands, except per share data)
Revenues	$	245,233	$	253,955	$	638,667	$	753,500
Income available to SandRidge Energy, Inc. common stockholders(1)	$	297,657	$	285,299	$	361,146	$	367,599
Earnings per common share
Basic	$	0.82	$	0.72	$	1.41	$	0.93
Diluted	$	0.73	$	0.65	$	1.24	$	0.87

(1) Pro forma columns reflect a $454.5 million reduction in tax expense related to the release of a portion of the Company’s valuation allowance on existing deferred tax assets.

Sale of Wolfberry Assets. In January 2011, the Company agreed to sell its Wolfberry assets in the Permian Basin for $151.6 million, net of fees and post-closing adjustments. This asset sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized. The sale was completed in July 2011.

Sale of New Mexico Assets. In April 2011, the Company agreed to sell certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for approximately $199.0 million, net of fees and post-closing adjustments. This asset sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized. The sale was completed in August 2011.

Sale of Working Interest in Mississippian Properties. In September 2011, the Company sold to Atinum MidCon I, LLC (“Atinum”) 13.2% of its working interest in approximately 860,000 acres the Company has leased in the Mississippian formation in the Mid-Continent. As consideration for the working interest, Atinum paid the Company approximately $270.7 million in cash (including approximately $4.9 million attributable to the Atinum drilling carry described herein and approximately $7.7 million not attributable to the Atinum drilling carry, but to be applied against the Company’s future capital expenditures on the properties) and committed to pay 13.2% of SandRidge’s share of drilling and completion costs for wells drilled within an area of mutual interest until an additional $250.0 million has been paid (“Atinum drilling carry”), which is expected to occur over a three-year period. The sale of the working interest was accounted for as an adjustment to the full cost pool with no gain or loss recognized. The amounts received attributable to the Atinum drilling carry will reduce the Company’s capital expenditures.

Sale of East Texas Properties.In September 2011, the Company agreed to sell its East Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $231.0 million, subject to post closing adjustments. The Company expects the transaction to close in the fourth quarter of 2011.

10

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

4. Fair Value Measurements

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

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

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

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels as described in ASC Topic 820. The determination of the fair values, stated below, considers 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. The Company has assets and liabilities it has classified as Level 1 and Level 3, as described below. The Company did not have any assets or liabilities classified as Level 2 at September 30, 2011 or December 31, 2010.

Level 1 Fair Value Measurements

Restricted deposits. The fair value of restricted deposits invested in mutual funds or municipal bonds is based on quoted market prices. For restricted deposits held in savings accounts, carrying value is deemed to approximate fair value.

Other 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.

Level 3 Fair Value Measurements

Derivative Contracts. The fair values of the Company’s oil, natural gas and diesel fixed price swaps, natural gas basis swaps, natural gas collars and interest rate swap are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or other market participants, which include discount factors that the Company must estimate in its calculation. Additionally, the Company applies a 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):

September 30, 2011

	Fair Value Measurements						Netting(1)			Assets / Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,892	$	—	$	—	$	—		$	27,892
Commodity derivative contracts		—		—		312,093		(1,735	)		310,358
Other assets		5,714		—		—		—			5,714
	$	33,606	$	—	$	312,093	$	(1,735	)	$	343,964
Liabilities
Commodity derivative contracts	$	—	$	—	$	4,302	$	(1,735	)	$	2,567
Interest rate swaps		—		—		13,320		—			13,320
	$	—	$	—	$	17,622	$	(1,735	)	$	15,887

11

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

December 31, 2010

	Fair Value Measurements						Netting(1)			Assets / Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,886	$	—	$	—	$	—		$	27,886
Commodity derivative contracts		—		—		10,576		(5,548	)		5,028
Other assets		4,826		—		—		—			4,826
	$	32,712	$	—	$	10,576	$	(5,548	)	$	37,740
Liabilities
Commodity derivative contracts	$	—	$	—	$	216,436	$	(5,548	)	$	210,888
Interest rate swaps		—		—		16,694		—			16,694
	$	—	$	—	$	233,130	$	(5,548	)	$	227,582

(1) Represents the impact of netting assets and liabilities with counterparties with which the right of offset exists.

The tables below 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 and nine-month periods ended September 30, 2011 and 2010 (in thousands):

		$(000,000)			$(000,000)			$(000,000)			$(000,000)			$(000,000)			$(000,000)
	Three Months Ended September 30,
	2011									2010
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, June 30	$	(293,633	)	$	(15,285	)	$	(308,918	)	$	67,178		$	(16,548	)	$	50,630
Total realized and unrealized gains (losses)		596,736			(555	)		596,181			(67,195	)		(5,136	)		(72,331	)
Purchases		(3,126	)		—			(3,126	)		24,929			—			24,929
Settlements		7,814			2,520			10,334			(77,693	)		1,883			(75,810	)
Balance of Level 3, September 30	$	307,791		$	(13,320	)	$	294,471		$	(52,781	)	$	(19,801	)	$	(72,582	)

		$(000,000)			$(000,000)			$(000,000)			$(000,000)			$(000,000)			$(000,000)
	Nine Months Ended September 30,
	2011									2010
	Commodity Derivative Contracts			Interest Rate Swaps			Total			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, December 31	$	(205,860	)	$	(16,694	)	$	(222,554	)	$	46,153		$	(8,299	)	$	37,854
Total realized and unrealized (losses) gains		489,096			(3,631	)		485,465			114,378			(17,548	)		96,830
Purchases		(10,141	)		—			(10,141	)		24,929			—			24,929
Settlements		34,696			7,005			41,701			(238,241	)		6,046			(232,195	)
Balance of Level 3, September 30	$	307,791		$	(13,320	)	$	294,471		$	(52,781	)	$	(19,801	)	$	(72,582	)

During the three and nine-month periods ended September 30, 2011 and 2010, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

See Note 12 for further discussion of the Company’s derivative contracts.

Fair Value of Debt

The Company measures the fair value of its long-term debt based on quoted market prices which consider the effect of the Company’s credit risk. The estimated fair values and the carrying values of the Company’s senior notes at September 30, 2011 and December 31, 2010 were as follows (in thousands):

	September 30, 2011				December 31, 2010
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	338,846	$	350,000	$	334,751	$	350,000
8.625% Senior Notes due 2015		—		—		663,181		650,000
9.875% Senior Notes due 2016(1)		385,603		354,093		394,527		352,707
8.0% Senior Notes due 2018		727,500		750,000		762,849		750,000
8.75% Senior Notes due 2020(2)		447,750		443,437		472,968		443,057
7.5% Senior Notes due 2021		837,000		900,000		—		—

(1) Carrying value is net of $11,407 and $12,793 discount at September 30, 2011 and December 31, 2010, respectively.

(2) Carrying value is net of $6,563 and $6,943 discount at September 30, 2011 and December 31, 2010, respectively.

12

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The carrying 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 11 for discussion of the Company’s long-term debt, including the purchase and redemption of all outstanding 8.625% Senior Notes due 2015 and the issuance of the 7.5% Senior Notes due 2021, both of which occurred during 2011.

5. Property, Plant and Equipment

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

	September 30, 2011			December 31, 2010
Oil and natural gas properties
Proved	$	8,697,142		$	8,159,924
Unproved		681,886			547,953
Total oil and natural gas properties		9,379,028			8,707,877
Less: accumulated depreciation, depletion and impairment		(4,707,089	)		(4,483,736	)
Net oil and natural gas properties capitalized costs		4,671,939			4,224,141
Land		14,249			14,418
Non oil and natural gas equipment(1)		684,281			666,233
Buildings and structures		120,531			89,813
Total		819,061			770,464
Less: accumulated depreciation, depletion and amortization		(287,186	)		(260,740	)
Net capitalized costs		531,875			509,724
Total property, plant and equipment, net	$	5,203,814		$	4,733,865

(1) Includes capitalized interest of approximately $5.8 million and $4.7 million at September 30, 2011 and December 31, 2010, respectively.

There were no full cost ceiling impairments during the three or nine-month periods ended September 30, 2011 or 2010. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both September 30, 2011 and December 31, 2010 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the table above.

6. Goodwill

At September 30, 2011, the Company had $235.4 million of goodwill as a result of the excess consideration over the fair value of net assets acquired in the Arena Acquisition. Purchase price adjustments recorded in the first six months of 2011 resulted in a $1.0 million increase to goodwill. Goodwill recorded in the Arena Acquisition is primarily attributable to operational and cost synergies expected to be realized from the acquisition by using the Company’s current presence in the Permian Basin, its Fort Stockton, Texas service base and its existing rig ownership to efficiently increase its drilling and oil production from Arena assets acquired in the Central Basin Platform, as these assets have a proven production history. See Note 3 for additional discussion of the Arena Acquisition. Goodwill recognized is not deductible for tax purposes.

The Company performs its annual goodwill impairment test as of each July 1st and between annual evaluations if events occur or circumstances exist that would more likely than not reduce the fair value of the reporting unit below its carrying amount. Such circumstances could include, but are not limited to (1) a significant or sustained decrease in oil and natural gas prices, (2) a significant adverse change in the economic or business climate, (3) an adverse action or assessment by a regulator and (4) the likelihood that a reporting unit or a significant portion of a reporting unit will be sold or otherwise disposed. When evaluating whether goodwill is impaired, the Company compares the fair value of the reporting unit to which the goodwill is assigned to the reporting unit’s carrying amount, including goodwill. The fair value of the reporting unit is estimated using the income, or discounted cash flows, approach. If the carrying amount of the reporting unit exceeds its fair value, then the amount of the impairment loss must be measured. The impairment loss would be calculated by comparing the implied fair value of reporting unit goodwill to the carrying amount of goodwill. In calculating the implied fair value of reporting unit goodwill, the fair value of the reporting unit is allocated to all of the other assets and liabilities of that unit based on their fair values. The excess of the fair value of a reporting unit over the amount assigned to its other assets and liabilities is the implied fair value of goodwill. An impairment loss would be recognized when the carrying amount of goodwill exceeds its implied fair value.

The Company assigned the goodwill related to the Arena Acquisition to its exploration and production segment, which is the reporting unit for impairment testing purposes. Under the discounted cash flow approach, the reporting unit’s anticipated future cash flows, primarily based on projected oil and natural gas revenues, operating expenses and capital expenditures, were discounted using a weighted average cost of capital rate to estimate the fair value for the reporting unit. The Company’s first annual

13

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

evaluation of goodwill was completed during the third quarter of 2011 and resulted in no impairment loss. The Company monitors potential impairment indicators throughout the year. As of September 30, 2011, no such indicators were noted.

7. Other Assets

Other assets consist of the following (in thousands):

	September 30, 2011		December 31, 2010
Debt issuance costs, net of amortization	$	53,797	$	50,637
Lease broker advances		26,169		—
Development advance		12,598		—
Production tax credit receivable		7,665		1,436
Investments		5,714		4,826
Other		3,773		2,852
Total other assets	$	109,716	$	59,751

8. Variable Interest Entities

In accordance with the guidance in ASC Topic 810, Consolidation, including the guidance in Accounting Standards Update 2009-17, “Consolidations—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“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 the Company owns a variable interest in a VIE, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements.

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.

SandRidge Mississippian Trust I. On April 12, 2011, SandRidge Mississippian Trust I (the “Mississippian Trust”) completed its initial public offering of 17,250,000 common units representing beneficial interests in the Mississippian Trust. Net proceeds to the Mississippian Trust, after certain offering expenses, were approximately $336.9 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust in exchange for the net proceeds of the Mississippian Trust’s initial public offering and 10,750,000 units (3,750,000 common units and 7,000,000 subordinated units) representing approximately 38.4% of the beneficial interest in the Mississippian Trust. The royalty interests conveyed to the Mississippian Trust are in certain oil and natural gas properties leased by the Company in the Mississippian formation in five counties in Northern Oklahoma. The conveyance of the royalty interests to the Mississippian Trust was recorded in April 2011 at the historical cost to the Company, or $309.0 million, which was determined by allocating the historical net book value of the Company’s full cost pool based on the fair value of the conveyed royalty interests relative to the fair value of the Company’s full cost pool. The Mississippian Trust will dissolve and begin to liquidate on December 31, 2030 and will soon thereafter wind up its affairs and terminate. At the time the Mississippian Trust terminates, 50% of the conveyed royalty interests will automatically revert to the Company.

The Mississippian Trust makes quarterly cash distributions to its unitholders based on its calculated distributable income. In order to provide support for cash distributions on the Mississippian Trust’s common units, the Company agreed to subordinate a portion of the Mississippian Trust units it owns (the “Mississippian Trust subordinated units”), which constitute 25% of the total outstanding Mississippian Trust units. The Mississippian Trust subordinated units are entitled to receive pro rata distributions from the Mississippian Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the Mississippian Trust subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company. In addition, pursuant to the trust agreement, SandRidge has a loan commitment to the Mississippian Trust, whereby SandRidge will loan funds to the Mississippian Trust on an unsecured basis, with terms substantially the same as would be obtained in an arm’s length transaction between SandRidge and an unaffiliated party, if at any time the Mississippian Trust’s cash is not sufficient to pay ordinary course administrative expenses as they become due.

14

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to the royalty interest granted to the Mississippian Trust, by December 31, 2014. In the event of delays, the Company will have until December 31, 2015 to fulfill its drilling obligation. At the end of the fourth full calendar quarter following satisfaction of the Company’s drilling obligation (the “Mississippian Trust subordination period”), the Company’s Mississippian Trust subordinated units will automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions will terminate. Incentive distributions are equal to 50% of the amount by which the cash available for distribution on all of the Mississippian Trust units for any quarter exceeds 20% of the target distribution for such quarter. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust a lien in the Company’s interests in the properties where the development wells will be drilled in order to secure the estimated amount of the drilling costs for the wells. As the Company fulfills its drilling obligation, wells that have been drilled and perforated for completion are released from the lien and the total amount that may be recovered by the Mississippian Trust is proportionately reduced. As of September 30, 2011, the maximum amount recoverable by the Mississippian Trust under the lien has been reduced to approximately $109.6 million. Additionally, the Company and the Mississippian Trust entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Mississippian Trust, and a derivatives agreement, pursuant to which the Company provides to the Mississippian Trust the economic effects of certain of the Company’s derivative contracts. The tables below present open oil and natural gas commodity derivative contracts at September 30, 2011, the economic effects of which will be provided to the Mississippian Trust under the derivatives agreement. See Note 12 for further discussion of the derivatives agreement between the Company and the Mississippian Trust and a complete listing of the Company’s open commodity derivative contracts at September 30, 2011, including the derivative contracts the economic effects of which have been conveyed to the Mississippian Trust.

Oil Price Swaps

Contract Period	Notional (MBbl)		Weighted Avg. Fixed Price
October 2011 — December 2011		120	$	103.60
January 2012 — December 2012		454	$	104.15
January 2013 — December 2013		488	$	102.07
January 2014 — December 2014		541	$	100.94
January 2015 — December 2015		468	$	101.07

Natural Gas Price Swaps

Contract Period	Notional (MMcf)(1)		Weighted Avg. Fixed Price
October 2011 — December 2011		1,013	$	4.61
January 2012 — June 2012		2,190	$	4.90

Natural Gas Collars

Contract Period	Notional (MMcf)(1)		Collar Range
July 2012 — December 2012		402	$	4.00 - 6.20
January 2013 — December 2013		858	$	4.00 - 7.15
January 2014 — December 2014		937	$	4.00 - 7.78
January 2015 — December 2015		1,010	$	4.00 - 8.55

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

        The Mississippian Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Mississippian Trust. The Company’s ownership in the Mississippian Trust and loan commitment constitute variable interests. The Company has determined it is the primary beneficiary of the Mississippian Trust as it has (a) the power to direct the activities that most significantly impact the economic performance of the Mississippian Trust through (i) its participation in the creation and structure of the Mississippian Trust, (ii) the manner in which it fulfills its drilling obligation to the Mississippian Trust, and (iii) the manner in which it operates the oil and natural gas properties that are subject to the conveyed royalty interests, and (b) through the end of the Mississippian Trust subordination period, the obligation to absorb losses and right to receive residual returns, through its ownership of the Mississippian Trust subordinated units, that could potentially be significant to the Mississippian Trust. As a result, the Company began consolidating the activities of the Mississippian Trust into its results of operations in April 2011. In consolidation, the common units of the Mississippian Trust owned by third parties are reflected as noncontrolling interest. As discussed above, the Company’s Mississippian Trust subordinated units will automatically convert to Mississippian Trust common units at the end of the Mississippian Trust subordination period.

The Mississippian Trust’s assets can be used to settle its own obligations and not other obligations of the Company. The Mississippian Trust’s creditors have no contractual recourse to the general credit of the Company. Although the Mississippian Trust is

15

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

included in the Company’s consolidated financial statements, the Company’s legal interest in the Mississippian Trust’s assets is limited to its ownership of the Mississippian Trust units. At September 30, 2011, $365.1 million of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets was attributable to the Mississippian Trust. The Mississippian Trust’s assets and liabilities included in the accompanying unaudited condensed consolidated balance sheet at September 30, 2011 consisted of the following (in thousands):

Cash and cash equivalents	$	1,148
Accounts receivable, net		6,950
Total current assets		8,098
Investment in royalty interests(1)		308,964
Less: accumulated depreciation, depletion and impairment		(10,666	)
		298,298
Total assets	$	306,396
Accounts payable and accrued expenses	$	272
Total liabilities	$	272

(1) Included in oil and natural gas properties on the condensed consolidated balance sheet.

SandRidge Permian Trust. On August 16, 2011, SandRidge Permian Trust (the “Permian Trust”), a newly formed Delaware statutory trust, completed its initial public offering of 34,500,000 common units representing beneficial interests in the Permian Trust. Net proceeds to the Permian Trust, after certain offering expenses, were approximately $580.6 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Permian Trust in exchange for the net proceeds of the Permian Trust’s initial public offering and 18,000,000 units (4,875,000 common units and 13,125,000 subordinated units) representing approximately 34.3% of the beneficial interest in the Permian Trust. The royalty interests conveyed to the Permian Trust are in certain oil and natural gas properties leased by the Company in the Central Basin Platform of the Permian Basin in Andrews County, Texas. The conveyance of the royalty interests to the Permian Trust was recorded in August 2011 at the historical cost to the Company, or $549.8 million, which was determined by allocating the historical net book value of the Company’s full cost pool based on the fair value of the conveyed royalty interests relative to the fair value of the Company’s full cost pool. The Permian Trust will dissolve and begin to liquidate on March 31, 2031 and will soon thereafter wind up its affairs and terminate. At the time the Permian Trust terminates, 50% of the conveyed royalty interests will automatically revert to the Company.

The Permian Trust will make quarterly cash distributions to its unitholders based on its calculated distributable income. In order to provide support for cash distributions on the Permian Trust’s common units, the Company agreed to subordinate a portion of the Permian Trust units it owns (the “Permian Trust subordinated units”), which constitute 25% of the total outstanding Permian Trust units. The Permian Trust subordinated units are entitled to receive pro rata distributions from the Permian Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the Permian Trust subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company. In addition, pursuant to the trust agreement, SandRidge has a loan commitment to the Permian Trust, whereby SandRidge will loan funds to the Permian Trust on an unsecured basis, with terms substantially the same as would be obtained in an arm’s length transaction between SandRidge and an unaffiliated third party, if at any time the Permian Trust’s cash is not sufficient to pay ordinary course administrative expenses as they become due.

        The Company and one of its wholly owned subsidiaries entered into a development agreement with the Permian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to the royalty interest granted to the Permian Trust, by March 31, 2015. In the event of delays, the Company will have until March 31, 2016 to fulfill its drilling obligation. At the end of the fourth full calendar quarter following satisfaction of the Company’s drilling obligation (the “Permian Trust subordination period”), the Company’s Permian Trust subordinated units will automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions will terminate. Incentive distributions are equal to 50% of the amount by which the cash available for distribution on all of the Permian Trust units for any quarter exceeds 20% of the target distribution for such quarter. One of the Company’s wholly owned subsidiaries also granted to the Permian Trust a lien in the Company’s interests in the properties where the development wells will be drilled, in order to secure the estimated amount of the drilling costs for the wells. As the Company fulfills its drilling obligation, wells that have been drilled and perforated for completion are released from the lien and the total amount that may be recovered by the Permian Trust is proportionately reduced. As of September 30, 2011, the maximum amount recoverable by the Permian Trust under the lien has been reduced to approximately $250.0 million. The Company and the Permian Trust also entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Permian Trust, including hedge management services, and a derivatives agreement, pursuant to which the Company provides to the Permian Trust the economic effects of certain of the Company’s derivative contracts. Substantially concurrent with the execution of the derivatives agreement, the Company novated certain of the derivative contracts underlying the derivatives agreement to the Permian Trust. The tables below present the open contracts at September 30, 2011 underlying the derivatives agreement, including the contracts novated to the Permian Trust. The combined volume in the tables below reflect the total volume of the Permian Trust’s oil derivative contracts. See Note 12 for further discussion of the derivatives agreement between the Company and the Permian Trust and a complete listing of the Company’s open commodity derivative contracts at September 30, 2011, including the derivative contracts underlying the derivatives agreement.

16

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Oil Price Swaps Underlying the Derivatives Agreement

Contract Period	Notional (MBbl)		Weighted Avg. Fixed Price
October 2011 — December 2011		100	$	99.80
January 2012 — December 2012		687	$	102.20
January 2013 — December 2013		921	$	102.84
January 2014 — December 2014		1,100	$	101.75
January 2015 — March 2015		232	$	100.90

Oil Price Swaps Underlying the Derivatives Agreement and Novated to the Trust

Contract Period	Notional (in  MBbl)		Weighted Avg. Fixed  Price
October 2011 — December 2011		150	$	99.80
January 2012 — December 2012		466	$	102.20
January 2013 — December 2013		368	$	102.84
January 2014 — December 2014		311	$	101.75
January 2015 — March 2015		71	$	100.90

The Permian Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Permian Trust. The Company’s ownership in the Permian Trust and loan commitment constitute variable interests. The Company has determined it is the primary beneficiary of the Permian Trust as it has (a) the power to direct the activities that most significantly impact the economic performance of the Permian Trust through (i) its participation in the creation and structure of the Permian Trust, (ii) the manner in which it fulfills its drilling obligation to the Permian Trust, (iii) the manner in which it operates the oil and natural gas properties that are subject to the conveyed royalty interests, and (iv) its role as the Permian Trust’s hedge manager and (b) through the end of the Permian Trust subordination period, the obligation to absorb losses and right to receive residual returns, through its ownership of the Permian Trust subordinated units, that could potentially be significant to the Permian Trust. As a result, the Company began consolidating the activities of the Permian Trust into its results of operations in August 2011. In consolidation, the common units of the Permian Trust owned by third parties are reflected as noncontrolling interest. As discussed above, the Company’s Permian Trust subordinated units will automatically convert to Permian Trust common units at the end of the Permian Trust subordination period.

The Permian Trust’s assets can be used to settle its own obligations and not other obligations of the Company. The Permian Trust’s creditors have no contractual recourse to the general credit of the Company. Although the Permian Trust is included in the Company’s consolidated financial statements, the Company’s legal interest in the Permian Trust’s assets is limited to its ownership of the Permian Trust units. At September 30, 2011, $608.1 million of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets was attributable to the Permian Trust. The Permian Trust’s assets and liabilities included in the accompanying unaudited condensed consolidated balance sheet at September 30, 2011 consisted of the following (in thousands):

Cash and cash equivalents	$	1
Accounts receivable, net		9,865
Derivative contracts		9,996
Total current assets		19,862
Investment in royalty interests(1)		549,832
Less: accumulated depreciation, depletion and impairment		(2,348	)
		547,484
Derivative contracts		14,864
Total assets	$	582,210
Accounts payable and accrued expenses	$	421
Total liabilities	$	421

(1) Included in oil and natural gas properties on the condensed consolidated balance sheet.

Grey Ranch, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch Plant, 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% 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. Agreements related to the ownership and operation of GRLP provide for GRLP to pay management fees to the Company to operate the Plant and lease payments for 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.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

GRLP’s assets can be used to settle its own obligations and not other obligations of the Company. GRLP’s creditors have no recourse to the general credit of the Company. Although GRLP is included in the Company’s consolidated financial statements, the Company’s legal interest in GRLP’s assets is limited to its 50% ownership. At September 30, 2011 and December 31, 2010, $8.5 million and $11.3 million, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities included in the accompanying unaudited condensed consolidated balance sheets at September 30, 2011 and December 31, 2010 consisted of the following (in thousands):

	September 30, 2011		December 31, 2010
Cash and cash equivalents	$	963	$	4,601
Accounts receivable, net		93		181
Inventory		109		109
Other current assets		—		124
Total current assets		1,165		5,015
Other property, plant and equipment, net		15,272		16,079
Total assets	$	16,437	$	21,094
Accounts payable and accrued expenses	$	402	$	400
Total liabilities	$	402	$	400

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 of Genpar due to (i) its ability, as administrative manager, to direct the activities of Genpar that most significantly impact its economic 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 a gas gathering and operations and maintenance agreements with Piñon Gathering Company, LLC (“PGC”) through June 30, 2029. 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 ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company is not the primary beneficiary of PGC. Therefore, the results of PGC’s activities are not consolidated into the Company’s financial statements.

9. Century Plant Contract

The Company is constructing the Century Plant, a CO₂treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). Under 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 subsequently agreed-upon revisions, through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Company expects to complete the Century Plant in two phases. Upon completion of each phase of the Century Plant, Occidental will take ownership of the related assets and will operate the Century Plant for the purpose of separating and removing CO₂ from delivered natural gas. Phase I is in the commissioning process with completion and transfer of title to Occidental expected in early 2012, and Phase II is under construction and expected to be completed in 2012. Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO₂ from the Company’s delivered natural gas production volumes. Under this agreement, the Company will be required to deliver certain CO₂ volumes annually, and will have to compensate Occidental to the extent such requirements are not met. Based upon current natural gas production levels, the Company anticipates accruing amounts due to Occidental for not meeting such requirements beginning in 2012; however, at this time, the Company does not expect such amounts to have a material impact on its financial position or results of operations. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.

18

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 both phases of the contract is completed and assets have been transferred to Occidental. 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. The Company has recorded an addition of $124.0 million ($105.0 million in 2010 and $19.0 million in the first quarter of 2011) to its oil and natural gas properties for the estimated loss identified based on projections of the costs to be incurred in excess of contract amounts. Billings and estimated contract loss in excess of costs incurred of $42.3 million and $31.5 million at September 30, 2011 and December 31, 2010, respectively, are reported as current liabilities in the accompanying unaudited condensed consolidated balance sheets.

10. Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2010 to September 30, 2011 is as follows (in thousands):

Asset retirement obligation, December 31, 2010	$	119,877
Liability incurred upon acquiring and drilling wells		4,130
Sales of reserves in place		(6,855	)
Liability settled in current period		(1,608	)
Accretion of discount expense		7,039
Asset retirement obligation, September 30, 2011		122,583
Less: current portion		25,360
Asset retirement obligation, net of current	$	97,223

11. Long-Term Debt

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

	September 30, 2011		December 31, 2010
Senior credit facility	$	—	$	340,000
Other notes payable
Drilling rig fleet and related oil field services equipment		—		6,302
Mortgage		16,280		17,020
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		—		650,000
9.875% Senior Notes due 2016, net of $11,407 and $12,793 discount, respectively		354,093		352,707
8.0% Senior Notes due 2018		750,000		750,000
8.75% Senior Notes due 2020, net of $6,563 and $6,943 discount, respectively		443,437		443,057
7.5% Senior Notes due 2021		900,000		—
Total debt		2,813,810		2,909,086
Less: current maturities of long-term debt		1,035		7,293
Long-term debt	$	2,812,775	$	2,901,793

For the three-month periods ended September 30, 2011 and 2010, interest payments were approximately $61.5 million and $32.7 million, respectively. For the nine-month periods ended September 30, 2011 and 2010, interest payments were approximately $171.7 million and $124.9 million, respectively. Interest paid for the nine-month period ended September 30, 2011 included $25.7 million of accrued interest paid in connection with the purchase and redemption of the 8.625% Senior Notes due 2015. See discussion of purchase and redemption below.

Senior Credit Facility. The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. The senior credit facility matures on April 15, 2014, unless the Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) have not been refinanced by December 31, 2013, in which case the senior credit facility will mature on January 31, 2014.

        On February 23, 2011, the senior credit facility was amended to, among other things, (a) exclude from the calculation of Consolidated Net Income the net income (loss) of a Royalty Trust, except to the extent of cash distributions received by the Company, (b) establish that an investment in a Royalty Trust and dispositions to, and of interests in, Royalty Trusts are permitted, (c) clarify that a Royalty Trust is not a Subsidiary, (d) allow the Company to net against its calculation of Consolidated Funded Indebtedness cash balances exceeding $10.0 million in the event no loans are outstanding under the senior credit facility at that time, and (e) establish that, for any fiscal quarter ending prior to March 31, 2012, if the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0 then compliance with the Company’s Consolidated Leverage Ratio covenant is not required. Terms capitalized in the preceding sentence have the meaning given to them in the senior credit facility, as amended.

19

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

On April 20, 2011, the senior credit facility was further amended. The amendment permits the Company to pay cash dividends on its 7.0% convertible perpetual preferred stock and reaffirmed the borrowing base at $790.0 million.

As of September 30, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters, unless, for any quarter ending prior to March 31, 2012, the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0, calculated using the last four completed fiscal quarters, (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) and (iii) ratio of the Company’s secured indebtedness to EBITDA, which may not exceed 2.0:1.0 at each quarter end, calculated using the last four completed fiscal quarters. As of and during the three and nine-month periods ended September 30, 2011, the Company was in compliance with all of the financial covenants under the senior credit facility.

Additionally, 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.

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 considered by the lenders 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 highest 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 base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rate paid on amounts outstanding under the senior credit facility was 2.65% and 2.78% for the three-month periods ended September 30, 2011 and 2010, respectively, and 2.69% and 2.67% for the nine-month periods ended September 30, 2011 and 2010, respectively.

Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. On March 15, 2011, the borrowing base was reduced from $850.0 million to $790.0 million as a result of the issuance of the 7.5% Senior Notes due 2021, discussed below. The Company’s borrowing base is redetermined in April and October of each year. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, 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. At the October 2011 redetermination, the borrowing base remained unchanged at $790.0 million. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base. During the first nine months of 2011, additional costs of approximately $0.3 million were incurred. These costs have been deferred and are included in other assets in the accompanying unaudited condensed consolidated balance sheets.

At September 30, 2011, the Company had no amount outstanding under the senior credit facility and $25.8 million in outstanding letters of credit, which affect the availability under the senior credit facility on a dollar-for-dollar basis.

Other Notes Payable. The Company financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by such equipment. In March 2011, the Company paid the outstanding $4.3 million principal balance on these notes.

20

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 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.

Senior Floating Rate Notes Due 2014. The Company’s Senior Floating Rate Notes were issued in May 2008. The Senior Floating Rate Notes are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 20 for condensed financial information of the subsidiary guarantors.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625%. Interest is payable quarterly with the principal due on April 1, 2014. The average interest rate paid on the outstanding Senior Floating Rate Notes was 3.87% and 4.16% for the three-month periods ended September 30, 2011 and 2010, respectively, and 3.91% and 3.98% for the nine-month periods ended September 30, 2011 and 2010, respectively, without consideration of the interest rate swap discussed below. The Company may redeem, at specified redemption prices, some or all of the Senior Floating Rate Notes at any time.

As of September 30, 2011, the Company had a $350.0 million notional interest rate swap agreement to effectively fix the 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. This swap has not been designated as a hedge.

The $9.4 million of debt issuance costs associated with the Senior Floating Rate Notes is included in other assets in the accompanying unaudited condensed consolidated balance sheets and is being amortized over the term of the notes.

8.625% Senior Notes Due 2015. The Company’s 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”) were issued in May 2008. On March 1, 2011, the Company announced a cash tender offer to purchase any and all of the outstanding $650.0 million aggregate principal amount of its 8.625% Senior Notes for total consideration of $1,046.88 per $1,000 principal amount of such notes tendered by March 14, 2011. Holders tendering after March 14, 2011 were eligible to receive $1,016.88 per $1,000 principal amount of notes tendered. The Company purchased approximately 94.5%, or $614.2 million, of the aggregate principal amount of its 8.625% Senior Notes pursuant to the tender offer, which expired on March 28, 2011. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes for $1,043.13 per $1,000 principal amount outstanding, plus accrued interest. All holders whose notes were purchased or redeemed received accrued and unpaid interest from October 1, 2010. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $38.2 million, were recorded as a loss on extinguishment of debt and included in the accompanying unaudited condensed consolidated statements of operations for the nine-month period ended September 30, 2011.

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 is 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 guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable.

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 unaudited 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 guaranteed unconditionally on an unsecured basis, by certain of the Company’s wholly owned 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 unaudited 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 8.75% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally, guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 20 for condensed financial information of the subsidiary guarantors.

21

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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

7.5% Senior Notes Due 2021. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 (the “7.5% Senior Notes”) to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were approximately $880.7 million after deducting offering expenses, and were used to fund the tender offer for the 8.625% Senior Notes, including any accrued and unpaid interest, the redemption of the 8.625% Senior Notes that remained outstanding following the conclusion of the tender offer, including accrued and unpaid interest (each as described above) and to repay borrowings under the Company’s senior credit facility. The 7.5% Senior Notes bear interest at a fixed rate of 7.5% per annum, payable semi-annually, with the principal due on March 15, 2021. Prior to March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. On or after March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, prior to their maturity at other various specified redemption prices. The notes are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries.

In conjunction with the issuance of the 7.5% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to conduct a registered exchange offer for or register the resale of these notes before March 14, 2012. On October 17, 2011, the Company commenced a registered exchange offer for the 7.5% Senior Notes. The terms of the 7.5% Senior Notes to be issued in the exchange offer will be identical to the terms of the senior notes to be exchanged, except that the transfer restrictions, registration rights and provisions for additional interest relating to the exchanged notes will not apply to the 7.5% Senior Notes to be issued in the exchange offer.

Debt issuance costs of $19.3 million incurred in connection with the offering of the 7.5% Senior Notes are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized over the term of the notes.

Indentures. The indentures governing the Company’s senior notes contain 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 and nine-month periods ended September 30, 2011, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

12. Derivatives

None of the Company’s derivative contracts have been designated as hedges. The Company records all derivative contracts, which include commodity derivatives and an interest rate swap, at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts for the commodity derivative contracts and in interest expense for interest rate swaps in the consolidated statement of operations. Commodity derivative contracts are settled on a monthly basis. Settlements on interest rate swaps occur quarterly. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheet.

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company 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. Additionally, the Company uses derivative contracts to manage commodity price risk associated with diesel fuel used by its drilling rigs. 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 September 30, 2011, the Company’s commodity derivative contracts consisted of fixed price swaps, collars and basis swaps, which are described below:

Fixed price swaps:	The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Collars:	Collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
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.

22

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 an interest rate swap agreement 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 through April 1, 2013. See Note 11 for further discussion of the Company’s interest rate swap.

Trust Derivatives Agreements. In April 2011, the Company entered into a derivatives agreement with the Mississippian Trust, effective April 1, 2011. The agreement provides the Mississippian Trust with the economic effect of certain oil and natural gas derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015. Under this arrangement, the Company will pay the Mississippian Trust amounts it receives from its counterparties in accordance with the underlying contracts, and the Mississippian Trust will pay the Company any amounts that the Company is required to pay its counterparties under such contracts.

In August 2011, the Company entered into a derivatives agreement with the Permian Trust, effective August 1, 2011. The agreement provides the Permian Trust with the economic effect of certain oil derivative contacts previously entered into by the Company. The underlying commodity derivative contracts cover volumes of oil production through March 31, 2015. Under the derivatives agreement, the Company will pay the Permian Trust amounts it receives from its counterparty, and the Permian Trust will pay the Company any amounts that the Company is required to pay such counterparty. Under the derivatives agreement, as development wells are drilled for the benefit of the Permian Trust, the Company will have the right, under certain circumstances, to assign or novate to the Permian Trust additional derivative contracts. Substantially concurrent with the execution of the derivatives agreement, the Company novated certain of the derivatives contracts underlying the derivatives agreement to the Permian Trust. As a party to these contracts, the Permian Trust will receive payment directly from the counterparty, and be required to pay any amounts owed directly to the counterparty. To secure the Permian Trust’s obligations under these novated contracts, the Permian Trust has given the counterparty a lien on its royalty interests in certain oil and natural gas properties.

All contracts underlying the derivatives agreements with the Mississippian Trust and Permian Trust, including those novated to the Permian Trust, have been included in the Company’s consolidated derivative disclosures. See Note 8 for further discussion of the Mississippian Trust and Permian Trust.

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 at September 30, 2011 and December 31, 2010 on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract	Balance Sheet Classification	September  30, 2011			December  31, 2010
Derivative assets
Oil price swaps	Derivative contracts-current	$	92,144		$	—
Natural gas price swaps	Derivative contracts-current		4,261			8,500
Natural gas collars	Derivative contracts-current		52			—
Oil price swaps	Derivative contracts-noncurrent		215,484			—
Natural gas price swaps	Derivative contracts-noncurrent		—			3,518
Natural gas collars	Derivative contracts-noncurrent		152			—
Derivative liabilities
Oil price swaps	Derivative contracts-current		—			(63,123	)
Natural gas price swaps	Derivative contracts-current		—			(640	)
Natural gas basis swaps	Derivative contracts-current		—			(34,112	)
Interest rate swaps	Derivative contracts-current		(9,020	)		(9,007	)
Oil price swaps	Derivative contracts-noncurrent		—			(84,055	)
Natural gas price swaps	Derivative contracts-noncurrent		—			(802	)
Natural gas basis swaps	Derivative contracts-noncurrent		(4,291	)		(34,908	)
Natural gas collars	Derivative contracts-noncurrent		(11	)		(238	)
Interest rate swaps	Derivative contracts-noncurrent		(4,300	)		(7,687	)
Total derivative contracts, net		$	294,471		$	(222,554	)

23

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Refer to Note 4 for additional discussion of the fair value measurement of the Company’s derivative contracts.

The following table summarizes the effects of the Company’s derivative contracts on the accompanying condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2011 and 2010 (in thousands):

Type of Contract	Location of (Gain) Loss Recognized in Income	Amount of (Gain) Loss Recognized in Income
		Three Months Ended September 30,					Nine Months Ended September 30,
		2011			2010		2011			2010
Oil and natural gas derivatives	(Gain) loss on derivative contracts	$	(596,736	)	$	67,195	$	(489,096	)	$	(114,378	)
Interest rate swaps	Interest expense		555			5,136		3,631			17,548
Total		$	(596,181	)	$	72,331	$	(485,465	)	$	(96,830	)

The following tables summarize the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts and interest rate swaps for the three and nine-month periods ended September 30, 2011 and 2010 (in thousands):

		$(000,000)			$(000,000)			$(000,000)			$(000,000)
	Three Months Ended September 30,						Nine Months Ended September 30,
Oil and Natural Gas Derivatives	2011			2010			2011			2010
Realized loss (gain)(1)	$	7,814		$	(77,692	)	$	34,696		$	(238,240	)
Unrealized (gain) loss		(604,550	)		144,887			(523,792	)		123,862
(Gain) loss on commodity derivative contracts	$	(596,736	)	$	67,195		$	(489,096	)	$	(114,378	)

		$(000,000)			$(000,000)		$(000,000)			$(000,000)
	Three Months  Ended September 30,					Nine Months Ended September 30,
Interest Rate Swaps	2011			2010		2011			2010
Realized loss	$	2,520		$	1,883	$	7,005		$	6,046
Unrealized (gain) loss		(1,965	)		3,253		(3,374	)		11,502
Loss on interest rate swaps	$	555		$	5,136	$	3,631		$	17,548

(1) Includes $9.9 million net realized gains ($72.8 million realized gains and $62.9 million realized losses) and $48.1 million net realized gains ($111.0 million realized gains and $62.9 million realized losses) for the three and nine-month periods ended September 30, 2011, respectively, related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled (“out-of-period settlements”). Includes $48.2 million and $110.6 million of realized gains on out-of-period settlements for the three and nine-month periods ended September 30, 2010, respectively.

On September 30, 2011, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

Contract Period(1)(2)	Notional (MBbl)		Weighted Avg. Fixed Price
October 2011 — December 2011		2,550	$	88.15
January 2012 — March 2012		2,675	$	89.50
April 2012 — June 2012		2,766	$	89.36
July 2012 — September 2012		2,826	$	89.32
October 2012 — December 2012		2,888	$	89.24
January 2013 — March 2013		2,820	$	92.63
April 2013 — June 2013		2,852	$	92.63
July 2013 — September 2013		2,883	$	92.63
October 2013 — December 2013		2,883	$	92.63
January 2014 — March 2014		1,401	$	96.43
April 2014 — June 2014		1,417	$	96.43
July 2014 — September 2014		1,432	$	96.43
October 2014 — December 2014		1,432	$	96.43
January 2015 — March 2015		1,159	$	95.77
April 2015 — June 2015		865	$	93.95
July 2015 — September 2015		874	$	93.95
October 2015 — December 2015		874	$	93.95

24

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Natural Gas Price Swaps

Contract Period(1)	Notional (MMcf)(3)		Weighted Avg. Fixed Price
October 2011 — December 2011		1,840	$	4.61
January 2012 — March 2012		1,820	$	4.90
April 2012 — June 2012		1,820	$	4.90

Natural Gas Basis Swaps

Contract Period	Notional (MMcf)(3)		Weighted Avg. Fixed Price
January 2013 — March 2013		3,600	$	(0.46	)
April 2013 — June 2013		3,640	$	(0.46	)
July 2013 — September 2013		3,680	$	(0.46	)
October 2013 — December 2013		3,680	$	(0.46	)

Natural Gas Collars

Contract Period(1)	Notional (MMcf)(3)		Collar Range
July 2012 — September 2012		201	$	4.00 - 6.20
October 2012 — December 2012		201	$	4.00 - 6.20
January 2013 — March 2013		212	$	4.00 - 7.15
April 2013 — June 2013		214	$	4.00 - 7.15
July 2013 — September 2013		216	$	4.00 - 7.15
October 2013 — December 2013		216	$	4.00 - 7.15
January 2014 — March 2014		231	$	4.00 - 7.78
April 2014 — June 2014		234	$	4.00 - 7.78
July 2014 — September 2014		236	$	4.00 - 7.78
October 2014 — December 2014		236	$	4.00 - 7.78
January 2015 — March 2015		249	$	4.00 - 8.55
April 2015 — June 2015		251	$	4.00 - 8.55
July 2015 — September 2015		255	$	4.00 - 8.55
October 2015 — December 2015		255	$	4.00 - 8.55

Diesel Price Swaps

Contract Period	Notional (Thousands of Gallons)		Weighted Avg. Fixed Price
January 2012 — March 2012		1,512	$	2.86
April 2012 — June 2012		1,512	$	2.83
July 2012 — September 2012		1,512	$	2.83
October 2012 — December 2012		1,512	$	2.81

(1) Includes derivative contracts, the economic effects of which have been conveyed to the Mississippian Trust and Permian Trust pursuant to the derivatives agreements with each of the Mississippian Trust and Permian Trust, respectively. See Note 8 for a listing of such contracts.

(2) Includes derivative contracts novated to the Permian Trust. See Note 8 for a listing of such contracts.

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

13. Income Taxes

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 for income taxes on a current year-to-date basis. The provision (benefit) for income taxes consisted of the following components for the three and nine-month periods ended September 30, 2011 and 2010 (in thousands).

	Three Months  Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
Current
Federal	$	739	$	(844	)	$	623		$	(844	)
State		215		33			350			195
		954		(811	)		973			(649	)
Deferred
Federal		—		(442,923	)		(6,447	)		(442,923	)
State		—		(13,514	)		(539	)		(13,514	)
		—		(456,437	)		(6,986	)		(456,437	)
Total provision (benefit)		954		(457,248	)		(6,013	)		(457,086	)
Less: income tax provision attributable to noncontrolling interest		103		15			104			104
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	851	$	(457,263	)	$	(6,117	)	$	(457,190	)

25

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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 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 tax assets will not be realized based on 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. In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company adjusted the previously recorded net deferred tax liability associated with the Arena Acquisition by recording an additional net deferred tax liability of $7.0 million. The adjustment resulted in the Company releasing a corresponding portion of its previously recorded valuation allowance resulting in a deferred tax benefit. This release of valuation allowance is in addition to the $447.5 million released in 2010. The 2010 and 2011 partial releases of the valuation allowance were based on management’s assessment that it is more likely than not that the Company will realize a benefit from more of its existing deferred tax assets as the Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. The Company continued to have a full valuation allowance against its net deferred tax asset at September 30, 2011.

The current income tax provision of $0.95 million and $0.97 million for the three and nine-month periods ended September 30, 2011 is primarily a result of the Company filing the final income tax returns for Arena and its subsidiaries.

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 certain of the Company’s tax attributes, including $298.4 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. The Company experienced a subsequent ownership change within the meaning of IRC Section 382 on July 16, 2010 as a result of the Arena Acquisition. The Company expects a more restrictive limitation on certain of its tax attributes as a result of the July 16, 2010 ownership change than with the December 31, 2008 ownership change. The more restrictive limitation would apply not only to the $298.4 million of federal net operating loss carryforwards and certain other tax attributes existing at December 31, 2008 but also to the net operating losses of approximately $512.9 million and certain other attributes generated during the period from January 1, 2009 through July 16, 2010. The subsequent limitation could result in a material amount of the loss carryforwards existing at July 16, 2010 expiring unused. Arena also experienced an ownership change on July 16, 2010 as a result of its acquisition by the Company. This ownership change is expected to result in a limitation on Arena’s net operating loss carryforwards and certain other carryforwards available to the Company on an annual basis. None of the limitations discussed above resulted in a current federal tax liability at September 30, 2011 or December 31, 2010.

As of September 30, 2011, the Company had a liability of approximately $1.54 million for unrecognized tax benefits. If recognized, approximately $1.0 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate. The liability for unrecognized tax benefits as of December 31, 2010 was $1.45 million.

Consistent with the Company’s policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included $0.02 million and $0.09 million of accrued gross interest with respect to unrecognized tax benefits in its accompanying unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2011, respectively. The Company did not recognize any interest and penalties related to unrecognized tax benefits during the three and nine-month periods ended September 30, 2010.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2008 to present remain open for federal examination. Additionally, various tax years remain open beginning with tax year 2003 due to federal net operating loss carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years. Currently, several examinations are in progress. The Company does not anticipate that any federal or state audits will have a significant impact on the Company’s results of operations or financial position. In addition, the Company does not expect resolution of any uncertain tax positions that would result in a significant increase or decrease to the amount of unrecognized tax benefits during the next twelve months.

26

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Income tax payments, net of refunds, were $1.79 million and $2.73 million for the three and nine-month periods ended September 30, 2011. For the three-month period ended September 30, 2010, income tax payments, net of refunds, were $1.9 million. For the nine-month period ended September 30, 2010, income tax refunds, net of payments, were $1.6 million.

14. Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock and outstanding convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share for the three and nine-month periods ended September 30, 2011 and 2010 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Weighted average basic common shares outstanding		399,270		361,687		398,656		257,028
Effect of dilutive securities
Restricted stock		8,297		5,954		7,639		4,759
Convertible preferred stock outstanding		90,133		51,496		90,133		51,496
Weighted average diluted common and potential common shares outstanding		497,700		419,137		496,428		313,283

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock, 6.0% convertible perpetual preferred stock and 7.0% convertible perpetual preferred stock for the three and nine-month periods ended September 30, 2011 and its outstanding 8.5% convertible perpetual preferred stock and 6.0% convertible perpetual preferred stock for the three and nine-month periods ended September 30, 2010. See Note 16 for discussion of the Company’s convertible preferred stock. Under the if-converted 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. For the three and nine-month periods ended September 30, 2011, the Company determined the if-converted method was more dilutive and did not include the 6.0%, 8.5% or 7.0% preferred stock dividends in the determination of income available to common stockholders. For the three and nine-month periods ended September 30, 2010, the Company determined the if-converted method was more dilutive and did not include the 6.0% and 8.5% preferred stock dividends in the determination of income available to common stockholders.

15. Commitments and Contingencies

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

On or about June 27, 2008 and November 6, 2008, there were fires at the Company’s Grey Ranch Plant and a nearby compressor station. The Company, as owner of the plant and compressor station, recovered approximately $24.5 million from its insurance carriers for damages caused by the fires. At the time of the plant fire, the plant was operated by Southern Union Gas Services, Ltd. (“Southern Union Gas”). On June 4, 2010, November 10, 2010, and March 15, 2011, the Company’s insurance carriers filed lawsuits against Southern Union Gas and its parent, Southern Union Company (together with Southern Union Gas, “Southern Union”) seeking recovery for amounts paid under the Company’s insurance policies. Southern Union, in turn, has tendered indemnity requests to GRLP, of which the Company is a 50% owner. GRLP has not accepted or acknowledged any responsibility to indemnify Southern Union. To the extent the Company, as a 50% owner of GRLP, is required to fund any indemnification of Southern Union, it will pursue coverage for such liability under its general liability insurance policy. An estimate of reasonably possible losses associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with the construction by Aspen of a natural gas pipeline in West Texas. On October 14, 2011, the complaint was amended to add Odessa Fuels, LLC, Odessa Fuels Marketing, LLC and Odessa Field Services and Compression as plaintiffs. The plaintiffs seek damages for breach of contract and for the construction cost of the pipeline, which they claim approach $100.0 million. The Company intends to defend this lawsuit vigorously and believes the plaintiff’s claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP (collectively, the “plaintiffs”) filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83^rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County,

27

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including carbon dioxide, or “CO₂”) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO₂ produced from the plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Commissioner of the General Land Office of the State of Texas (“GLO”) is named as an additional defendant in the lawsuit as some of the affected oil and gas leases described in the plaintiffs’ allegations cover mineral classified lands in which the GLO is entitled to one-half of the royalties attributable to such leases. The GLO has filed a cross-claim against the SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands. The Company intends to defend this lawsuit vigorously. This case is in the early stages and, accordingly, an estimate of reasonably possible losses, if any, associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.

SandRidge acquired certain oil and natural gas leases in Loving County, Texas, from mineral owners in April 2010, which it subsequently sold to Energen Resources Corporation (“Energen”) in December 2010 for an allocated value of approximately $4.0 million. Subsequent to the acquisition by SandRidge of the leases and prior to their disposition to Energen, the mineral owners executed oil and natural gas leases conveying the same mineral estates to Cimarex Energy Co. (“Cimarex”). SandRidge has requested a declaratory judgment resolving all disputes between it and Cimarex regarding the validity of the leases insofar as they purport to cover the same mineral interests. In connection with that action, Cimarex has filed a third-party petition naming Energen as a third-party defendant, and is asserting quiet title and trespass to try title claims against Energen. Energen has tendered to SandRidge a demand for indemnity, and SandRidge has assumed Energen’s defense and any potential loss suffered by it. An estimate of reasonably possible losses, if any, associated with the demand for indemnity cannot be made at this time. Accordingly, the Company has not established any reserves relating to the demand.

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. (collectively, “Plaintiffs”) filed a lawsuit against SandRidge Energy, Inc., SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain directors and senior executive officers of SandRidge Energy, Inc. (collectively, “Defendants”) in the U.S. District Court for the District of Connecticut. Plaintiffs allege that Defendants made false and misleading statements to U.S. Drilling Capital Management LLC and Plaintiffs prior to the entry into a participation agreement among Patriot Exploration LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by Plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, Plaintiffs have invested approximately $15.0 million under the participation agreement. Plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes Plaintiffs’ claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.

16. Equity

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

	September  30, 2011		December  31, 2010
Shares authorized		50,000		50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock		2,650		2,650
6.0% Convertible perpetual preferred stock		2,000		2,000
7.0% Convertible perpetual preferred stock		3,000		3,000

The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 7,650,000 shares were designated as convertible perpetual preferred stock at September 30, 2011 and December 31, 2010. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions and none of these 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 $100.00 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. All dividend payments to date have been paid in cash. Approximately $5.6 million in dividends ($2.8 million paid and $2.8 million unpaid) and $16.9 million in dividends ($14.1 million paid and $2.8 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the calculation of income available to common stockholders and the Company’s

28

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

basic earnings per share calculation for the three and nine-month periods ended September 30, 2011, respectively, as presented in the accompanying unaudited condensed consolidated statements of operations. Approximately $5.6 million in dividends ($2.8 million paid and $2.8 million unpaid) and $16.9 million in dividends ($14.1 million paid and $2.8 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the calculation of income available to common stockholders and the Company’s basic earnings per share calculation for the three and nine-month periods ended September 30, 2010, respectively, as presented in the accompanying unaudited 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 convert automatically 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 $100.00 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. All dividend payments to date have been paid in cash. Approximately $3.0 million ($0.5 million paid and $2.5 million unpaid) and $9.0 million in dividends ($6.5 million paid and $2.5 million unpaid) on the 6.0% convertible perpetual preferred stock have been included in the calculation of income available to common stockholders and the Company’s basic earnings per share calculation for the three and nine-month periods ended September 30, 2011, respectively, as presented in the accompanying unaudited condensed consolidated statements of operations. Approximately $3.0 million (all unpaid) and $9.0 million in dividends ($6.0 million paid and $3.0 unpaid) on the 6.0% convertible perpetual preferred stock have been included in the calculation of income available to common stockholders and the Company’s basic earnings per share calculation for the three and nine-month periods ended September 30, 2010, respectively, as presented in the accompanying unaudited condensed consolidated statements of operations. The 6.0% convertible perpetual preferred stock is not redeemable by the Company at any time. Each share is initially convertible into approximately 9.2115 shares of the Company’s common stock, at the holder’s option 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.

7.0% Convertible perpetual preferred stock. The Company’s 7.0% convertible perpetual preferred stock was issued in November 2010. Each share of the 7.0% convertible preferred stock has a liquidation preference of $100.00 per share and became convertible at the holder’s option on February 15, 2011, initially into approximately 12.8791 shares of the Company’s common stock based on an initial conversion price of $7.76 per share. The annual dividend on each share of the 7.0% convertible preferred stock is $7.00 payable semi-annually, in cash, common stock or a combination thereof, at the Company’s election beginning on May 15, 2011. All dividend payments to date have been paid in cash. Approximately $5.3 million (all unpaid) and $15.8 million in dividends ($7.9 million paid and $7.9 million unpaid) on the 7.0% convertible perpetual preferred stock have been included in the calculation of income available to common stockholders and the Company’s basic earnings per share calculation for the three and nine-month periods ended September 30, 2011, respectively, as presented in the accompanying unaudited condensed consolidated statements of operations. The 7.0% convertible perpetual preferred stock is not redeemable by the Company at any time. After November 20, 2015, the Company may cause all outstanding shares of the 7.0% convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.

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

	September  30, 2011		December  31, 2010
Shares authorized		800,000		800,000
Shares outstanding at end of period		412,400		406,360
Shares held in treasury		586		470

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 1.1 million shares with a total value of $10.6 million and approximately 670,000 shares with a total value of $5.3 million during the nine-month periods ended September 30, 2011 and 2010, respectively. These shares were accounted for as treasury stock when withheld, and subsequently retired.

Any shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan are accounted for as treasury shares. These shares are 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, subject to certain conditions. All awards issued during and after 2006 have four-year vesting periods. Shares of restricted common stock are subject to restriction on transfer. Unvested restricted stock awards are included in the Company’s outstanding shares of common stock.

29

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the three and nine-month periods ended September 30, 2011, the Company recognized stock-based compensation expense of $9.4 million and $26.5 million, net of $2.0 million and $5.7 million capitalized, respectively, related to restricted common stock awards. For the three and nine-month periods ended September 30, 2010, the Company recognized stock-based compensation expense of $10.0 million and $24.2 million, net of $1.5 million and $4.1 million capitalized, respectively, related to restricted common stock awards.

Noncontrolling Interest. Noncontrolling interests in the Company’s subsidiaries, including four variable interest entities of which the Company is the primary beneficiary (see Note 8), represent third-party ownership interests in the consolidated entity and are included as a component of equity in the consolidated balance sheet and consolidated statement of changes in equity.

17. Related Party Transactions

The Company enters into transactions in the ordinary course of business with certain related parties. These transactions primarily consist of purchases related 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 September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Sales to and reimbursements from related parties	$	5,742	$	4,157	$	17,477	$	10,980

	September  30, 2011		December  31, 2010
Accounts receivable due from related parties	$	1,931	$	1,702

Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer owns a minority interest in a limited liability company that owns and operates the Oklahoma City Thunder, a National Basketball Association (“NBA”) team playing in Oklahoma City, where the Company is headquartered. The Company is party to a sponsorship agreement, through the 2013 season, whereby it 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 pays an annual license fee of $0.2 million through 2013. Amounts related to these agreements are not included in the tables above. At September 30, 2011, the Company had no amounts due under these agreements. At December 31, 2010, the amount due under these agreements was $0.8 million. The Company expects to be relieved of any obligation to pay these amounts if there is a NBA labor shortage or strike.

18. Subsequent Events

Events occurring after September 30, 2011 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this Quarterly Report have been included.

7.5% Senior Notes Registered Exchange Offer. On October 17, 2011, the Company commenced a registered exchange offer for the 7.5% Senior Notes. See further discussion in Note 11.

19. Business Segment Information

The Company has three business segments: exploration and production, drilling and oil field services and midstream gas services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of oil and natural gas properties. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells. The midstream gas services segment is engaged in the purchasing, gathering, 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.

30

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

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

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended September 30, 2011
Revenues	$	321,456		$	108,595		$	44,111		$	2,420		$	476,582
Inter-segment revenue		(67	)		(83,048	)		(29,457	)		(257	)		(112,829	)
Total revenues	$	321,389		$	25,547		$	14,654		$	2,163		$	363,753
Operating income (loss)(1)	$	717,327		$	2,507		$	(2,016	)	$	(21,236	)	$	696,582
Interest income (expense), net		163			7			(144	)		(58,978	)		(58,952	)
Other income (expense), net		11			—			—			(683	)		(672	)
Income (loss) before income taxes	$	717,501		$	2,514		$	(2,160	)	$	(80,897	)	$	636,958
Capital expenditures(2)	$	441,825		$	5,898		$	6,757		$	13,808		$	468,288
Depreciation, depletion and amortization	$	87,236		$	8,250		$	1,202		$	3,588		$	100,276
Three Months Ended September 30, 2010
Revenues	$	210,484		$	60,370		$	65,470		$	8,965		$	345,289
Inter-segment revenue		(63	)		(55,096	)		(42,545	)		(2,352	)		(100,056	)
Total revenues	$	210,421		$	5,274		$	22,925		$	6,613		$	245,233
Operating (loss) income	$	(65,642	)	$	(1,826	)	$	1,196		$	(21,158	)	$	(87,430	)
Interest income (expense), net		137			(201	)		(175	)		(63,333	)		(63,572	)
Other income, net		459			—			388			509			1,356
(Loss) income before income taxes	$	(65,046	)	$	(2,027	)	$	1,409		$	(83,982	)	$	(149,646	)
Capital expenditures(2)	$	295,007		$	8,897		$	10,143		$	4,002		$	318,049
Depreciation, depletion and amortization	$	91,931		$	7,081		$	1,131		$	3,535		$	103,678
Nine Months Ended September 30, 2011
Revenues	$	906,461		$	272,587		$	148,367		$	8,525		$	1,335,940
Inter-segment revenue		(200	)		(197,469	)		(95,968	)		(928	)		(294,565	)
Total revenues	$	906,261		$	75,118		$	52,399		$	7,597		$	1,041,375
Operating income (loss)(1)	$	834,317		$	6,496		$	(7,115	)	$	(65,228	)	$	768,470
Interest income (expense), net		283			(94	)		(456	)		(179,810	)		(180,077	)
Loss on extinguishment of debt		—			—			—			(38,232	)		(38,232	)
Other income (expense), net		1,690			—			(485	)		(543	)		662
Income (loss) before income taxes	$	836,290		$	6,402		$	(8,056	)	$	(283,813	)	$	550,823
Capital expenditures(2)	$	1,259,491		$	20,692		$	15,392		$	37,818		$	1,333,393
Depreciation, depletion and amortization	$	238,442		$	23,977		$	3,589		$	10,708		$	276,716
At September 30, 2011
Total assets	$	5,426,848		$	229,269		$	155,719		$	606,877		$	6,418,713
Nine Months Ended September 30, 2010
Revenues	$	531,239		$	202,419		$	214,386		$	28,162		$	976,206
Inter-segment revenue		(194	)		(187,473	)		(141,778	)		(8,094	)		(337,539	)
Total revenues	$	531,045		$	14,946		$	72,608		$	20,068		$	638,667
Operating income (loss)	$	180,846		$	(6,421	)	$	3,352		$	(56,585	)	$	121,192
Interest income (expense), net		337			(768	)		(474	)		(188,848	)		(189,753	)
Other income, net		1,240			—			444			378			2,062
Income (loss) before income taxes	$	182,423		$	(7,189	)	$	3,322		$	(245,055	)	$	(66,499	)
Capital expenditures(2)	$	706,056		$	26,509		$	46,902		$	16,126		$	795,593
Depreciation, depletion and amortization	$	199,965		$	21,244		$	2,933		$	10,256		$	234,398
At December 31, 2010
Total assets	$	4,612,295		$	224,784		$	151,598		$	242,771		$	5,231,448

31

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

(1) Exploration and production segment operating income includes net gains of $596.7 million and $489.1 million on commodity derivative contracts for the three and nine-month periods ended September 30, 2011, respectively.

(2) On an accrual basis.

20. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. The subsidiary guarantors are wholly owned and have jointly and severally guaranteed unconditionally on an unsecured basis the Company’s Senior Floating Rate Notes and 8.75% Senior Notes as of September 30, 2011. Prior to their purchase and redemption, the 8.625% Senior Notes were also jointly and severally guaranteed unconditionally on an unsecured basis by the wholly owned subsidiary guarantors. 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’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes. The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiaries, prepared on the equity basis of accounting. The non-guarantor subsidiaries, including four variable interest entities, are included in the non-guarantors column in the tables below. 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.

Condensed Consolidating Balance Sheets

	September 30, 2011
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	322,922	$	331	$	2,184	$	—		$	325,437
Accounts receivable, net		1,176,509		299,025		560,328		(1,861,466	)		174,396
Derivative contracts		—		86,462		35,665		(25,670	)		96,457
Other current assets		—		19,725		11,979		—			31,704
Total current assets		1,499,431		405,543		610,156		(1,887,136	)		627,994
Property, plant and equipment, net		—		4,264,373		939,441		—			5,203,814
Investment in subsidiaries		3,924,216		124,511		—		(4,048,727	)		—
Derivative contracts		—		199,037		82,404		(67,540	)		213,901
Goodwill		—		235,396		—		—			235,396
Other assets		53,798		83,810		—		—			137,608
Total assets	$	5,477,445	$	5,312,670	$	1,632,001	$	(6,003,403	)	$	6,418,713
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	660,841	$	1,103,850	$	510,605	$	(1,861,466	)	$	413,830
Derivative contracts		9,020		25,670		—		(25,670	)		9,020
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		42,269		1,035		—			43,304
Total current liabilities		669,861		1,197,149		511,640		(1,887,136	)		491,514
Long-term debt		2,797,530		—		15,245		—			2,812,775
Derivative contracts		4,300		70,107		—		(67,540	)		6,867
Asset retirement obligation		—		97,045		178		—			97,223
Other long-term obligations		1,539		22,891		—		—			24,430
Total liabilities		3,473,230		1,387,192		527,063		(1,954,676	)		3,432,809
Equity
SandRidge Energy, Inc. stockholders’ equity		2,004,215		2,943,789		1,104,938		(4,048,727	)		2,004,215
Noncontrolling interest		—		981,689		—		—			981,689
Total equity		2,004,215		3,925,478		1,104,938		(4,048,727	)		2,985,904
Total liabilities and equity	$	5,477,445	$	5,312,670	$	1,632,001	$	(6,003,403	)	$	6,418,713

32

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	December 31, 2010
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,441	$	564	$	3,858	$	—		$	5,863
Accounts receivable, net		1,224,500		141,530		408,015		(1,627,927	)		146,118
Derivative contracts		—		5,028		—		—			5,028
Other current assets		—		13,890		4,691		—			18,581
Total current assets		1,225,941		161,012		416,564		(1,627,927	)		175,590
Property, plant and equipment, net		—		4,635,747		98,118		—			4,733,865
Investment in subsidiaries		3,230,067		69,995		—		(3,300,062	)		—
Goodwill		—		234,356		—		—			234,356
Other assets		50,637		37,000		—		—			87,637
Total assets	$	4,506,645	$	5,138,110	$	514,682	$	(4,927,989	)	$	5,231,448
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	66,539	$	1,510,827	$	427,483	$	(1,627,927	)	$	376,922
Derivative contracts		9,007		94,402		—		—			103,409
Asset retirement obligation		—		25,360		—		—			25,360
Other current liabilities		—		37,776		991		—			38,767
Total current liabilities		75,546		1,668,365		428,474		(1,627,927	)		544,458
Long-term debt		2,885,764		—		16,029		—			2,901,793
Derivative contracts		7,687		116,486		—		—			124,173
Asset retirement obligation		—		94,350		167		—			94,517
Other long-term obligations		1,454		17,570		—		—			19,024
Total liabilities		2,970,451		1,896,771		444,670		(1,627,927	)		3,683,965
Equity		1,536,194		3,241,339		70,012		(3,300,062	)		1,547,483
Total liabilities and equity	$	4,506,645	$	5,138,110	$	514,682	$	(4,927,989	)	$	5,231,448

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended September 30, 2011
Total revenues	$	—		$	320,816		$	87,056		$	(44,119	)	$	363,753
Expenses
Direct operating expenses		—			120,367			50,848			(43,856	)		127,359
General and administrative		84			35,153			1,298			(263	)		36,272
Depreciation, depletion, amortization and impairment		—			89,832			10,444			—			100,276
Gain on derivative contracts		—			(527,744	)		(68,992	)		—			(596,736	)
Total expenses		84			(282,392	)		(6,402	)		(44,119	)		(332,829	)
(Loss) income from operations		(84	)		603,208			93,458			—			696,582
Equity earnings from subsidiaries		634,712			93,045			—			(727,757	)		—
Interest (expense) income, net		(58,721	)		26			(257	)		—			(58,952	)
Other expense, net		—			(672	)		—			—			(672	)
Income before income taxes		575,907			695,607			93,201			(727,757	)		636,958
Income tax expense		798			—			156			—			954
Net income		575,109			695,607			93,045			(727,757	)		636,004
Less: net income attributable to noncontrolling interest		—			60,895			—			—			60,895
Net income attributable to SandRidge Energy, Inc.	$	575,109		$	634,712		$	93,045		$	(727,757	)	$	575,109
Three Months Ended September 30, 2010
Total revenues	$	—		$	235,447		$	27,318		$	(17,532	)	$	245,233
Expenses
Direct operating expenses		—			96,136			21,124			(17,348	)		99,912
General and administrative		71			61,376			615			(184	)		61,878
Depreciation, depletion, amortization and impairment		—			101,956			1,722			—			103,678
Loss on derivative contracts		—			67,195			—			—			67,195
Total expenses		71			326,663			23,461			(17,532	)		332,663
(Loss) income from operations		(71	)		(91,216	)		3,857			—			(87,430	)
Equity earnings from subsidiaries		(87,857	)		3,555			—			84,302			—
Interest expense, net		(63,061	)		(239	)		(272	)		—			(63,572	)
Other income, net		—			1,356			—			—			1,356
(Loss) income before income taxes		(150,989	)		(86,544	)		3,585			84,302			(149,646	)
Income tax (benefit) expense		(457,278	)		—			30			—			(457,248	)
Net income (loss)		306,289			(86,544	)		3,555			84,302			307,602
Less: net income attributable to noncontrolling interest		—			1,313			—			—			1,313
Net income (loss) attributable to SandRidge Energy, Inc.	$	306,289		$	(87,857	)	$	3,555		$	84,302		$	306,289

33

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2011
Total revenues	$	—		$	971,595		$	157,826		$	(88,046	)	$	1,041,375
Expenses
Direct operating expenses		—			361,984			102,320			(87,383	)		376,921
General and administrative		273			105,495			3,259			(663	)		108,364
Depreciation, depletion, amortization and impairment		—			258,485			18,231			—			276,716
Gain on derivative contracts		—			(410,503	)		(78,593	)		—			(489,096	)
Total expenses		273			315,461			45,217			(88,046	)		272,905
(Loss) income from operations		(273	)		656,134			112,609			—			768,470
Equity earnings from subsidiaries		694,149			111,917			—			(806,066	)		—
Interest expense, net		(179,036	)		(267	)		(774	)		—			(180,077	)
Loss on extinguishment of debt		(38,232	)		—			—			—			(38,232	)
Other income, net		—			420			242			—			662
Income before income taxes		476,608			768,204			112,077			(806,066	)		550,823
Income tax (benefit) expense		(6,173	)		—			160			—			(6,013	)
Net income		482,781			768,204			111,917			(806,066	)		556,836
Less: net income attributable to noncontrolling interest		—			74,055			—			—			74,055
Net income attributable to SandRidge Energy, Inc.	$	482,781		$	694,149		$	111,917		$	(806,066	)	$	482,781
Nine Months Ended September 30, 2010
Total revenues	$	—		$	609,135		$	117,950		$	(88,418	)	$	638,667
Expenses
Direct operating expenses		—			258,991			98,868			(87,823	)		270,036
General and administrative		234			125,207			2,573			(595	)		127,419
Depreciation, depletion, amortization and impairment		—			229,325			5,073			—			234,398
Gain on derivative contracts		—			(114,378	)		—			—			(114,378	)
Total expenses		234			499,145			106,514			(88,418	)		517,475
(Loss) income from operations		(234	)		109,990			11,436			—			121,192
Equity earnings from subsidiaries		117,937			10,467			—			(128,404	)		—
Interest expense, net		(188,031	)		(905	)		(817	)		—			(189,753	)
Other income, net		74			1,932			56			—			2,062
(Loss) income before income taxes		(70,254	)		121,484			10,675			(128,404	)		(66,499	)
Income tax (benefit) expense		(457,294	)		—			208			—			(457,086	)
Net income		387,040			121,484			10,467			(128,404	)		390,587
Less: net income attributable to noncontrolling interest		—			3,547			—			—			3,547
Net income attributable to SandRidge Energy, Inc.	$	387,040		$	117,937		$	10,467		$	(128,404	)	$	387,040

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2011
Net cash provided by (used in) operating activities	$	519,941		$	(227,240	)	$	33,747		$	1,508		$	327,956
Net cash provided by (used in) investing activities		—			230,114			(953,717	)		14,236			(709,367	)
Net cash (used in) provided by financing activities		(198,460	)		(3,107	)		918,296			(15,744	)		700,985
Net increase (decrease) in cash and cash equivalents		321,481			(233	)		(1,674	)		—			319,574
Cash and cash equivalents at beginning of year		1,441			564			3,858			—			5,863
Cash and cash equivalents at end of period	$	322,922		$	331		$	2,184		$	—		$	325,437

34

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

	Parent			Guarantors			Non-Guarantors			Eliminations		Consolidated
	(In thousands)
Nine Months Ended September 30, 2010
Net cash (used in) provided by operating activities	$	(241,580	)	$	574,767		$	6,025		$	—	$	339,212
Net cash used in investing activities		(138,428	)		(569,592	)		(6,078	)		—		(714,098	)
Net cash provided by (used in) financing activities		380,864			(7,349	)		(3,901	)		—		369,614
Net increase (decrease) in cash and cash equivalents		856			(2,174	)		(3,954	)		—		(5,272	)
Cash and cash equivalents at beginning of year		339			2,841			4,681			—		7,861
Cash and cash equivalents at end of period	$	1,195		$	667		$	727		$	—	$	2,589

35

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

Introduction

The following discussion and analysis is intended to help the reader understand the Company’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as the Company’s audited consolidated financial statements and the accompanying notes included in the 2010 Form 10-K. The Company’s discussion and analysis includes the following subjects:

• Overview of the Company

• Recent Developments

• Recent Accounting Pronouncements

• Results by Segment

• Consolidated Results of Operations

• Liquidity and Capital Resources

The financial information with respect to the three and nine-month periods ended September 30, 2011 and September 30, 2010, 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.

Overview of the Company

SandRidge is an independent oil and natural gas company concentrating on development and production activities related to the exploitation of the Company’s significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. The Company’s primary areas of focus are the Permian Basin in West Texas and the Mississippian formation in the Mid-Continent. The Company also owns and operates other interests in the Mid-Continent, WTO, Gulf Coast and Gulf of Mexico. During 2010 and 2011, the Company has continued the expansion of its oil property base through the Arena Acquisition in July 2010, which added significantly to the Company’s holdings in the Permian Basin, and through the growth and development of its property base in the Mid-Continent area of Oklahoma and Kansas. The Company consolidates the activities of the Mississippian Trust and the Permian Trust, two publicly traded royalty trusts described below and in Note 8 to the Company’s unaudited condensed consolidated financial statements.

The Company operates businesses that are complementary to its development and production activities. The Company owns 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 the Company’s consolidated results of operations largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for the Company’s own account are eliminated in consolidation and, therefore, do not directly contribute to the Company’s consolidated results of operations.

The Company currently generates the majority of its consolidated revenues and cash flow from the production and sale of oil and natural gas. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on the Company’s 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 the Company’s exposure to these fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production. Reducing the Company’s exposure to price volatility helps ensure that it has adequate funds available for its capital expenditure programs.

SandRidge Mississippian Trust I. On April 12, 2011, the Mississippian Trust completed its initial public offering of 17,250,000 common units representing a 61.6% beneficial interest in the Mississippian Trust. Net proceeds to the Mississippian Trust, after certain offering expenses, were approximately $336.9 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust in exchange for the net proceeds of the Mississippian Trust’s initial public offering and 10,750,000 units representing approximately 38.4% of the beneficial interest in the Mississippian Trust. The Company used the net proceeds it received from the Mississippian Trust’s offering to repay borrowings under the Company’s senior credit facility and for general corporate purposes.

SandRidge Permian Trust.On August 16, 2011, the Permian Trust completed its initial public offering of 34,500,000 common units representing a 65.7% beneficial interest in the Permian Trust. Net proceeds to the Permian Trust, after certain offering expenses, were approximately $580.6 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Permian Trust

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in exchange for the net proceeds of the Permian Trust’s initial public offering and 18,000,000 units representing approximately 34.3% of the beneficial interest in the Permian Trust. The Company used the net proceeds it received from the Permian Trust’s initial public offering to repay borrowings under the Company’s senior credit facility and plans to use remaining proceeds for general corporate purposes.

Recent Developments

Sale of Working Interest in Mississippian Properties. In September 2011, the Company sold to Atinum 13.2% of its working interest in approximately 860,000 acres the Company has leased in the Mississippian formation in the Mid-Continent. As consideration for the working interest, Atinum paid the Company approximately $270.7 million in cash (including approximately $4.9 million attributable to the Atinum drilling carry and approximately $7.7 million not attributable to the Atinum drilling carry, but to be applied against the Company’s future capital expenditures on the properties) and committed to pay 13.2% of SandRidge’s share of drilling and completion costs for wells drilled within an area of mutual interest until an additional $250.0 million has been paid, which is expected to occur over a three-year period. The Company plans to use the proceeds to fund a portion of its drilling program and for general corporate purposes.

Sale of East Texas Properties.In September 2011, the Company agreed to sell its East Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $231.0 million, subject to post closing adjustments. The Company expects the transaction to close in the fourth quarter of 2011 and intends to use the cash proceeds to fund a portion of its drilling program and for general corporate purposes.

7.5% Senior Notes Registered Exchange Offer. In conjunction with the issuance of the Company’s 7.5% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to conduct a registered exchange offer for or register the resale of these notes before March 14, 2012. On October 17, 2011, the Company commenced a registered exchange offer for the 7.5% Senior Notes. See further discussion in Note 11 to the Company’s unaudited condensed consolidated financial statements included in this Quarterly Report.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Note 2 to the Company’s condensed consolidated financial statements included in Item 1 of this Quarterly Report.

Results by Segment

The Company operates 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 the Company’s reportable segments, including its CO₂ gathering and sales operations and corporate operations. Management evaluates the performance of the Company’s business segments based on operating income (loss), which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Results of these measurements provide important information to the Company about the activity and profitability of the Company’s lines of business. Set forth in the tables below is financial information regarding the Company’s business segments for the three and nine-month periods ended September 30, 2011 and 2010 (in thousands).

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended September 30, 2011
Revenues	$	321,456		$	108,595		$	44,111		$	2,420		$	476,582
Inter-segment revenue		(67	)		(83,048	)		(29,457	)		(257	)		(112,829	)
Total revenues	$	321,389		$	25,547		$	14,654		$	2,163		$	363,753
Operating income (loss)(1)	$	717,327		$	2,507		$	(2,016	)	$	(21,236	)	$	696,582
Interest income (expense), net		163			7			(144	)		(58,978	)		(58,952	)
Other income (expense), net		11			—			—			(683	)		(672	)
Income (loss) before income taxes	$	717,501		$	2,514		$	(2,160	)	$	(80,897	)	$	636,958
Three Months Ended September 30, 2010
Revenues	$	210,484		$	60,370		$	65,470		$	8,965		$	345,289
Inter-segment revenue		(63	)		(55,096	)		(42,545	)		(2,352	)		(100,056	)
Total revenues	$	210,421		$	5,274		$	22,925		$	6,613		$	245,233
Operating (loss) income	$	(65,642	)	$	(1,826	)	$	1,196		$	(21,158	)	$	(87,430	)
Interest income (expense), net		137			(201	)		(175	)		(63,333	)		(63,572	)
Other income, net		459			—			388			509			1,356
(Loss) income before income taxes	$	(65,046	)	$	(2,027	)	$	1,409		$	(83,982	)	$	(149,646	)

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	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Nine Months Ended September 30, 2011
Revenues	$	906,461		$	272,587		$	148,367		$	8,525		$	1,335,940
Inter-segment revenue		(200	)		(197,469	)		(95,968	)		(928	)		(294,565	)
			��
Total revenues	$	906,261		$	75,118		$	52,399		$	7,597		$	1,041,375
Operating income (loss)(1)	$	834,317		$	6,496		$	(7,115	)	$	(65,228	)	$	768,470
Interest income (expense), net		283			(94	)		(456	)		(179,810	)		(180,077	)
Loss on extinguishment of debt		—			—			—			(38,232	)		(38,232	)
Other income (expense), net		1,690			—			(485	)		(543	)		662
Income (loss) before income taxes	$	836,290		$	6,402		$	(8,056	)	$	(283,813	)	$	550,823
Nine Months Ended September 30, 2010
Revenues	$	531,239		$	202,419		$	214,386		$	28,162		$	976,206
Inter-segment revenue		(194	)		(187,473	)		(141,778	)		(8,094	)		(337,539	)
Total revenues	$	531,045		$	14,946		$	72,608		$	20,068		$	638,667
Operating income (loss)	$	180,846		$	(6,421	)	$	3,352		$	(56,585	)	$	121,192
Interest income (expense), net		337			(768	)		(474	)		(188,848	)		(189,753	)
Other income, net		1,240			—			444			378			2,062
Income (loss) before income taxes	$	182,423		$	(7,189	)	$	3,322		$	(245,055	)	$	(66,499	)

(1) Exploration and production segment operating income includes net gains of $596.7 million and $489.1 million on commodity derivative contracts for the three and nine-month periods ended September 30, 2011, respectively.

Exploration and Production Segment

The primary factors affecting the financial results of the Company’s exploration and production segment are the prices the Company receives for its oil and natural gas production, the quantity of oil and natural gas it produces and changes in the fair value of commodity derivative contracts used to reduce the volatility of the prices received for its oil and natural gas production. Quarterly comparisons of production and price data are presented in the tables below. Changes in the Company’s results for these periods reflect, in part, the acquisition of oil properties in the Arena Acquisition in July 2010, which increased oil production volumes and revenues attributable to the Company’s exploration and production segment.

	Three Months Ended September 30,				Change
	2011		2010		Amount			Percent
Production data
Oil (MBbl)(1)		3,192		2,219		973			43.8	%
Natural gas (MMcf)		17,935		19,100		(1,165	)		(6.1	)%
Combined equivalent volumes (MBoe)		6,181		5,402		779			14.4	%
Average daily combined equivalent volumes (MBoe/d)		67		59		8			13.6	%
Average prices — as reported(2)
Oil (per Bbl)(1)	$	79.31	$	63.90	$	15.41			24.1	%
Natural gas (per Mcf)	$	3.64	$	3.57	$	0.07			2.0	%
Combined equivalent (per Boe)	$	51.52	$	38.87	$	12.65			32.5	%
Average prices — including impact of derivative contract settlements
Oil (per Bbl)(1)	$	76.94	$	64.74	$	12.20			18.8	%
Natural gas (per Mcf)	$	3.08	$	5.02	$	(1.94	)		(38.6	)%
Combined equivalent (per Boe)	$	48.66	$	44.33	$	4.33			9.8	%
	Nine Months Ended September 30,				Change
	2011		2010		Amount			Percent
Production data
Oil (MBbl)(1)		8,540		4,774		3,766			78.9	%
Natural gas (MMcf)		52,440		57,473		(5,033	)		(8.8	)%
Combined equivalent volumes (MBoe)		17,280		14,353		2,927			20.4	%
Average daily combined equivalent volumes (MBoe/d)		63		53		10			18.9	%
Average prices — as reported(2)
Oil (per Bbl)(1)	$	82.61	$	64.18	$	18.43			28.7	%
Natural gas (per Mcf)	$	3.66	$	3.88	$	(0.22	)		(5.7	)%
Combined equivalent (per Boe)	$	51.94	$	36.90	$	15.04			40.8	%
Average prices — including impact of derivative contract settlements
Oil (per Bbl)(1)	$	75.30	$	67.12	$	8.18			12.2	%
Natural gas (per Mcf)	$	3.41	$	6.30	$	(2.89	)		(45.9	)%
Combined equivalent (per Boe)	$	47.56	$	47.55	$	0.01			0.0	%

(1) Includes natural gas liquids.

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

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Exploration and Production Segment — Three months ended September 30, 2011 compared to the three months ended September 30, 2010

Exploration and production segment revenues increased $111.0 million, or 52.7%, to $321.4 million in the three months ended September 30, 2011 from $210.4 million in the three months ended September 30, 2010, as a result of a 43.8% increase in oil production and a 24.1% increase in the average price the Company received for its oil production. These increases were slightly offset by a 6.1% decrease in natural gas production. The increase in oil production was due to the continued development of Permian Basin properties acquired from Arena, and a focus on increased oil drilling in the Permian Basin and Mid-Continent throughout 2010 and 2011. Properties acquired and developed from Arena produced 1,122 MBbls of oil for the three-month period ended September 30, 2011, compared to 680 MBbls in the 2010 period. The decrease in natural gas production was a result of natural production declines in existing natural gas wells.

The average price received for the Company’s oil production increased 24.1%, or $15.41 per barrel, to $79.31 per barrel during the three months ended September 30, 2011 from $63.90 per barrel during the same period in 2010. The average price received for the Company’s natural gas production for the three-month period ended September 30, 2011 increased 2.0%, or $0.07 per Mcf, to $3.64 per Mcf from $3.57 per Mcf in the comparable period in 2010. Including the impact of derivative contract settlements, the effective price received for oil for the three-month period ended September 30, 2011 was $76.94 per Bbl compared to $64.74 per Bbl during the same period in 2010. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended September 30, 2011 was $3.08 per Mcf compared to $5.02 per Mcf during the same period in 2010. The Company’s derivative contracts are not designated as hedges and, as a result, realized and unrealized 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 September 30, 2011, the exploration and production segment reported a $596.7 million net gain on its commodity derivative positions ($7.8 million realized loss and $604.5 million unrealized gain) compared to a $67.2 million net loss on its commodity derivative positions ($77.7 million realized gain and $144.9 million unrealized loss) in the same period in 2010. Net realized gains totaling $9.9 million ($72.8 million realized gains and $62.9 million realized losses) on out-of-period settlements were included in the net realized loss for the three months ended September 30, 2011. Realized gains totaling $48.2 million on out-of-period settlements were included in the net realized gain for the three-month period ended September 30, 2010. Realized gains or losses on derivative contracts represent the difference in the settlement price compared to the contract price. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on the Company’s commodity derivative contracts recorded during the three months ended September 30, 2011 was primarily attributable to a decrease in average oil prices at September 30, 2011 compared to the average oil prices at June 30, 2011 or the contract price for contracts entered into during the third quarter of 2011. The unrealized loss on the Company’s commodity contracts recorded during the three months ended September 30, 2010 was primarily attributable to an increase in average oil prices at September 30, 2010 compared to the average oil prices at June 30, 2010.

For the three months ended September 30, 2011, the Company had operating income of $717.3 million in its exploration and production segment compared to an operating loss of $65.6 million for the same period in 2010. An increase of $108.5 million in oil and natural gas revenues was partially offset by an increase of $20.5 million in production expense during the three months ended September 30, 2011. Additionally, the Company recorded a $596.7 million net gain on commodity derivative contracts for the three months ended September 30, 2011 compared to a $67.2 million net loss for the same period in 2010. See further discussion of these changes under “Consolidated Results of Operations.”

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Exploration and Production Segment — Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

Exploration and production segment revenues increased $375.2 million, or 70.7%, to $906.3 million in the nine months ended September 30, 2011 from $531.0 million in the nine months ended September 30, 2010, as a result of a 78.9% increase in oil production and a 28.7% increase in the average price the Company received for its oil production. These increases were slightly offset by an 8.8% decrease in natural gas production and a 5.7% decrease in the average price received for natural gas production. The increase in oil production was due to the addition of Permian Basin properties acquired from Arena in July 2010, and the continued focus on increased oil drilling throughout 2010 and 2011. Properties acquired and developed from Arena produced 2,973 MBbls of oil for the nine-month period ended September 30, 2011 compared to 680 MBbls in the 2010 period after the acquisition. The decrease in natural gas production was a result of natural production declines in existing natural gas wells.

The average price received for the Company’s oil production increased 28.7%, or $18.43 per barrel, to $82.61 per barrel during the nine months ended September 30, 2011 from $64.18 per barrel during the same period in 2010. The average price received for the Company’s natural gas production for the nine-month period ended September 30, 2011 decreased 5.7%, or $0.22 per Mcf, to $3.66 per Mcf from $3.88 per Mcf in the comparable period in 2010. Including the impact of derivative contract settlements, the effective price received for oil for the nine-month period ended September 30, 2011 was $75.30 per Bbl compared to $67.12 per Bbl during the same period in 2010. Including the impact of derivative contract settlements, the effective price received for natural gas for the nine-month period ended September 30, 2011 was $3.41 per Mcf compared to $6.30 per Mcf during the same period in 2010.

During the nine-month period ended September 30, 2011, the exploration and production segment reported a $489.1 million net gain on its commodity derivative positions ($34.7 million realized loss and $523.8 million unrealized gain) compared to a $114.4 million net gain on its commodity derivative positions ($238.2 million realized gain and $123.8 million unrealized loss) in the same period in 2010. Net realized gains totaling $48.1 million ($111.0 million realized gains and $62.9 million realized losses) on out-of-period settlements were included in the net realized loss for the nine months ended September 30, 2011. Realized gains on out-of-period settlements totaling $110.6 million were included in the net realized gain for the nine months ended September 30, 2010. The unrealized gain on the Company’s commodity derivative contracts recorded during the nine months ended September 30, 2011 was primarily attributable to a decrease in average oil prices at September 30, 2011 compared to the average oil prices at December 31, 2010 or the contract price for contracts entered into during 2011. The unrealized loss on commodity contracts recorded during the nine months ended September 30, 2010 was attributable to an increase in average oil prices and decreases in the price differentials on the Company’s natural gas basis swaps at September 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.

For the nine months ended September 30, 2011, the Company had operating income of $834.3 million in its exploration and production segment compared to operating income of $180.8 million for the same period in 2010. Increases of $367.9 million in oil and natural gas revenues and $374.7 million in gain on derivative contracts were slightly offset by increases of $70.0 million in production expense, $14.5 million in production taxes and $39.0 million in depreciation and depletion on oil and natural gas properties during the nine months ended September 30, 2011. See further discussion of these changes under “Consolidated Results of Operations.”

Drilling and Oil Field Services Segment

The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. In addition to providing drilling services, the Company’s oil field services business also conducts operations that complement its 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 the Company operates, are included in drilling and services revenues and expenses while drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation.

As of September 30, 2011, the Company owned 31 drilling rigs. The table below presents a summary of the Company’s rigs as of September 30, 2011 and 2010:

	September 30,
	2011		2010
Rigs working for SandRidge		21		21
Rigs working for third parties		10		3
Idle rigs		—		4
Total operational		31		28
Non-operational rigs(1)		—		7
Total rigs owned		31		35

(1) Includes one rig being constructed, two rigs being converted and four rigs that were retired at September 30, 2010.

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Drilling and Oil Field Services Segment — Three months ended September 30, 2011 compared to the three months ended September 30, 2010

Drilling and oil field services segment revenues increased to $25.5 million in the three-month period ended September 30, 2011 from $5.3 million in the three-month period ended September 30, 2010 and drilling and oil field services segment expenses increased $15.9 million to $23.0 million during the same period. The increase in revenue resulted in operating income of $2.5 million in the three-month period ended September 30, 2011 compared to an operating loss of $1.8 million for the same period in 2010. The increase in revenues and expenses was primarily attributable to an increase in the number of rigs working for third parties and an increase in oil field services performed for third parties during the 2011 period. The increase in the number of rigs working for third parties was a result of increased demand for the Company’s rigs and additional rigs becoming available in West Texas as the Company decreased its drilling activity in the WTO beginning in 2010 and focused on the development of its oil properties in the Permian Basin and Mid-Continent areas.

Drilling and Oil Field Services Segment — Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

Drilling and oil field services segment revenues increased to $75.1 million in the nine-month period ended September 30, 2011 from $14.9 million in the nine-month period ended September 30, 2010 and drilling and oil field services segment expenses increased $47.3 million during the same period to $68.6 million. The increase in revenue resulted in operating income of $6.5 million in the nine-month period ended September 30, 2011 compared to an operating loss of $6.4 million for the same period in 2010. The increase in revenues and expenses was primarily attributable to an increase in the number of rigs working for third parties and an increase in oil field services performed for third parties during the 2011 period.

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead, and provide value-added services to customers. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees the Company charges to gather, compress and treat this natural gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of natural gas owned by such parties, net of any applicable margin and actual costs the Company charges to gather, compress and treat the natural gas. In general, natural gas purchased and sold by the Company’s midstream gas business is priced at a published daily or monthly index price. The primary factors affecting the results of the Company’s midstream gas services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas.

The Company owns and operates two gas treating plants in West Texas, which remove CO₂ from natural gas production and deliver residue gas to nearby pipelines. During 2011, the Company continued with the operational assessment phase of the Century Plant, in Pecos County, Texas, including diverting some of the Company’s natural gas from the Company’s two existing gas treating plants and processing it at the Century Plant during this time. As a result of this assessment, the Century Plant has been taken off line from time to time to resolve certain operational issues. The Company is currently in the process of diverting its high CO₂ natural gas production back through the Century Plant and commencing performance testing for Train I of the Century Plant. Upon successful completion of the performance testing, the use of the Company’s two gas treating plants in West Texas may be limited, the extent of which will depend on certain variables, including natural gas prices and the expected need for such plants to supplement treating capacity at the Century Plant going forward. During the second quarter of 2011, the Company evaluated its gas treating plants for impairment in connection with the operational phase of Train I of the Century Plant and concluded no impairment was necessary.

Midstream Gas Services Segment — Three months ended September 30, 2011 compared to the three months ended September 30, 2010

Midstream gas services segment revenues for the three months ended September 30, 2011 were $14.7 million compared to $22.9 million in the same period in 2010. The decrease in revenue along with the impact of fixed charges necessary to maintain and operate the treating plants resulted in an operating loss of $2.0 million for the three months ended September 30, 2011 compared to operating income of $1.2 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes the Company marketed and a decrease in natural gas volumes processed in the Company’s gas treating plants.

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Midstream Gas Services Segment — Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

Midstream gas services segment revenues for the nine months ended September 30, 2011 were $52.4 million compared to $72.6 million in the same period in 2010. The decrease in revenue along with the impact of fixed charges necessary to maintain and operate the treating plants resulted in an operating loss of $7.1 million for the nine months ended September 30, 2011 compared to operating income of $3.4 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes the Company marketed, a decrease in natural gas prices and a decrease in natural gas volumes processed in the Company’s gas treating plants.

Consolidated Results of Operations

Three months ended September 30, 2011 compared to the three months ended September 30, 2010

Revenues.Total revenues increased 48.3% for the three months ended September 30, 2011 from the same period in 2010 primarily due to the increase in oil and natural gas sales.

	Three Months Ended September 30,
	2011		2010		$ Change			% Change
	(In thousands)
Revenues
Oil and natural gas	$	318,453	$	209,998	$	108,455			51.6	%
Drilling and services		25,547		5,252		20,295			386.4	%
Midstream and marketing		15,092		23,281		(8,189	)		(35.2	)%
Other		4,661		6,702		(2,041	)		(30.5	)%
Total revenues	$	363,753	$	245,233	$	118,520			48.3	%

Total oil and natural gas revenues increased $108.5 million for the three months ended September 30, 2011 compared to the same period in 2010, primarily as a result of increases in the amount of oil produced and the average price received for oil production, offset slightly by a decrease in the amount of natural gas produced. The 973 MBbl increase in oil production was primarily due to the Company’s focus on increased oil drilling in the Permian Basin and Mid-Continent. The average price received for oil production, excluding the impact of derivative contracts, increased 24.1% in the 2011 period to $79.31 per Bbl compared to $63.90 per Bbl in 2010.

Drilling and services revenues increased $20.3 million for the three months ended September 30, 2011 compared to the same period in 2010 due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties.

Midstream and marketing revenues decreased $8.2 million, or 35.2%, in the three-month period ended September 30, 2011 compared to the three-month period ended September 30, 2010. The decrease was attributable to a decrease in third party volumes the Company marketed due to decreased natural gas production and a decrease in natural gas volumes processed at the Company’s gas treating plants in the three-month period ended September 30, 2011 compared to the same period in 2010.

Expenses. Total expenses were ($332.8) million for the three months ended September 30, 2011, compared to $332.7 million for the same period in 2010. Expenses in the three-month period ended September 30, 2011 included a $596.7 million gain on derivative contracts, compared to a $67.2 million loss on derivative contracts in the three-month period ended September 30, 2010.

	Three Months Ended September 30,
	2011			2010			$ Change			% Change
	(In thousands)
Expenses
Production	$	86,580		$	66,086		$	20,494			31.0	%
Production taxes		10,368			8,904			1,464			16.4	%
Drilling and services		16,209			4,187			12,022			287.1	%
Midstream and marketing		14,624			20,779			(6,155	)		(29.6	)%
Depreciation and depletion — oil and natural gas		86,725			91,237			(4,512	)		(4.9	)%
Depreciation and amortization — other		13,551			12,441			1,110			8.9	%
General and administrative		36,272			61,878			(25,606	)		(41.4	)%
(Gain) loss on derivative contracts		(596,736	)		67,195			(663,931	)		(988.1	)%
Gain on sale of assets		(422	)		(44	)		(378	)		859.1	%
Total expenses	$	(332,829	)	$	332,663		$	(665,492	)		(200.0	)%

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Production expenses include the costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expenses and treating costs. Production expenses increased $20.5 million primarily due to newly completed oil wells that began producing during late 2010 and the first nine months of 2011. Additionally, higher production costs were incurred on oil production compared to production costs on natural gas volumes as oil volumes continued to comprise a larger portion of the Company’s total production. Oil production increased 973 MBbls in the three-month period ended September 30, 2011 compared to the same period in 2010.

Drilling and services expenses, which include operating expenses attributable to the drilling and oil field services segment and the Company’s CO₂ services company, increased $12.0 million for the three months ended September 30, 2011 compared to the same period in 2010 primarily due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties during the three-month period ended September 30, 2011 compared to the same period in 2010.

Midstream and marketing expenses decreased $6.2 million, or 29.6%, to $14.6 million due to decreased natural gas volumes purchased from third parties as a result of decreased natural gas production during the three-month period ended September 30, 2011.

General and administrative expenses decreased $25.6 million, or 41.4%, to $36.3 million for the three months ended September 30, 2011 from $61.9 million for the comparable period in 2010. The decrease was primarily due to $10.7 million of fees incurred related to the Arena Acquisition and $16.0 million for the settlement of a dispute with certain working interest owners during the three-month period ended September 30, 2010.

The Company recorded a net gain of $596.7 million ($7.8 million realized loss and $604.5 million unrealized gain) on its commodity derivative contracts for the three-month period ended September 30, 2011 compared to a net loss of $67.2 million ($77.7 million realized gain and $144.9 million unrealized loss) in the same period of 2010. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”

Other Income (Expense). Total other expense decreased to $59.6 million in the three-month period ended September 30, 2011 from $62.2 million in the three-month period ended September 30, 2010. The decrease is reflected in the table below.

	Three Months Ended September 30,
	2011			2010			$ Change			% Change
	(In thousands)
Other income (expense)
Interest income	$	51		$	69		$	(18	)		(26.1	)%
Interest expense		(59,003	)		(63,641	)		4,638			(7.3	)%
Other (expense) income, net		(672	)		1,356			(2,028	)		(149.6	)%
Total other expense		(59,624	)		(62,216	)		2,592			(4.2	)%
Income (loss) before income taxes		636,958			(149,646	)		786,604			(525.6	)%
Income tax expense (benefit)		954			(457,248	)		458,202			(100.2	)%
Net income		636,004			307,602			328,402			106.8	%
Less: net income attributable to noncontrolling interest		60,895			1,313			59,582			4,537.9	%
Net income attributable to SandRidge Energy, Inc.	$	575,109		$	306,289		$	268,820			87.8	%

Income tax expense was $1.0 million in the three months ended September 30, 2011. The expense was primarily attributable to the Company filing the final income tax returns for Arena and its subsidiaries. The Company reported an income tax benefit of $457.3 million in the three months ended September 30, 2010. The benefit was primarily attributable to the release of a portion of the company’s valuation allowance against its net deferred tax asset. Net deferred tax liabilities recorded as a result of the Arena Acquisition in July 2010 reduced the Company’s existing net deferred tax asset position, allowing a corresponding reduction in the valuation allowance against the net deferred tax asset.

Net income attributable to noncontrolling interest increased to $60.9 million for the three months ended September 30, 2011 from $1.3 million for the same period in 2010 due to completion of the Mississippian Trust’s initial public offering in April 2011 and the Permian Trust’s initial public offering in August 2011. The portion of the Mississippian Trust’s and Permian Trust’s net income attributable to beneficial interests held by third parties is reflected as net income attributable to noncontrolling interest.

Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

Revenues.Total revenues increased 63.1% for the nine months ended September 30, 2011 from the same period in 2010 primarily due to the increase in oil and natural gas sales.

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	Nine Months Ended September 30,
	2011		2010		$ Change			% Change
	(In thousands)
Revenues
Oil and natural gas	$	897,506	$	529,578	$	367,928			69.5	%
Drilling and services		75,118		14,913		60,205			403.7	%
Midstream and marketing		53,663		73,868		(20,205	)		(27.4	)%
Other		15,088		20,308		(5,220	)		(25.7	)%
Total revenues	$	1,041,375	$	638,667	$	402,708			63.1	%

Total oil and natural gas revenues increased $367.9 million for the nine months ended September 30, 2011 compared to the same period in 2010, primarily as a result of an increase in the amount of oil produced and the average price received for oil production, offset slightly by a decrease in the amount of natural gas produced as well as decreased prices received for natural gas production. The 3,766 MBbl increase in oil production was primarily due to the properties acquired from Arena and the Company’s focus on increased oil drilling throughout 2010 and in 2011. The average price received for oil production, excluding the impact of derivative contracts, increased 28.7% in the 2011 period to $82.61 per Bbl compared to $64.18 per Bbl in 2010.

Drilling and services revenues increased $60.2 million for the nine months ended September 30, 2011 compared to the same period in 2010 due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties. During the nine-month period ended September 30, 2011, the Company had an average of ten rigs working for third parties compared to an average of two rigs working for third parties during the same period in 2010.

Midstream and marketing revenues decreased $20.2 million, or 27.4%, in the nine-month period ended September 30, 2011 compared to the nine-month period ended September 30, 2010. The decrease was attributable to a decrease in third party volumes the Company marketed due to decreased natural gas production, a decrease in natural gas prices and a decrease in natural gas volumes processed at the Company’s gas treating plants in the nine-month period ended September 30, 2011 compared to the same period in 2010.

Other revenues decreased $5.2 million for the nine months ended September 30, 2011 from the same period in 2010. The decrease was due to lower CO₂ volumes sold to third parties from the Company’s gas treating plants during the nine-month period ended September 30, 2011 compared to the same period in 2010 as a result of less natural gas treated at these plants.

Expenses. Total expenses decreased to $272.9 million for the nine months ended September 30, 2011 compared to $517.5 million for the same period in 2010. The decrease was primarily due to the increase in the gain on derivative contracts, partially offset by increases in production expense, production taxes, drilling and services expense, and depreciation and depletion on oil and natural gas properties.

	Nine Months Ended September 30,
	2011			2010			$ Change			% Change
	(In thousands)
Expenses
Production	$	242,371		$	172,367		$	70,004			40.6	%
Production taxes		33,610			19,146			14,464			75.5	%
Drilling and services		49,308			12,420			36,888			297.0	%
Midstream and marketing		52,780			66,064			(13,284	)		(20.1	)%
Depreciation and depletion — oil and natural gas		236,798			197,834			38,964			19.7	%
Depreciation and amortization — other		39,918			36,564			3,354			9.2	%
General and administrative		108,364			127,419			(19,055	)		(15.0	)%
Gain on derivative contracts		(489,096	)		(114,378	)		(374,718	)		327.6	%
(Gain) loss on sale of assets		(1,148	)		39			(1,187	)		(3,043.6	)%
Total expenses	$	272,905		$	517,475		$	(244,570	)		(47.3	)%

Production expenses increased $70.0 million primarily due to operating expenses associated with properties acquired from Arena and additional oil wells that began producing during late 2010 and the first nine months of 2011. Additionally, higher production costs were incurred on oil production compared to production costs on natural gas volumes. Oil production increased 3,766 MBbls in the nine-month period ended September 30, 2011 compared to the same period in 2010.

Production taxes increased $14.5 million, or 75.5%, due to increased oil production, including production from properties acquired from Arena and newly producing wells, in the nine-month period ended September 30, 2011 compared to the same period in 2010.

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Drilling and services expenses increased $36.9 million, or 297.0%, for the nine months ended September 30, 2011 compared to the same period in 2010 primarily due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties during the nine-month period ended September 30, 2011 compared to the same period in 2010.

Midstream and marketing expenses decreased $13.3 million, or 20.1%, to $52.8 million due to decreased natural gas volumes purchased from third parties as a result of decreased natural gas production during the nine-month period ended September 30, 2011.

Depreciation and depletion for the Company’s oil and natural gas properties increased $39.0 million for the nine-month period ended September 30, 2011 from the same period in 2010. The increase was primarily due to an increase of 20.4% in the Company’s combined production volume, partially offset by the decrease in the depreciation and depletion per Boe to $13.70 in the first nine months of 2011 from $13.78 per Boe in the comparable period in 2010.

General and administrative expenses decreased $19.1 million, or 15.0%, to $108.4 million for the nine months ended September 30, 2011 from $127.4 million for the comparable period in 2010. The decrease was primarily due to $15.4 million of fees incurred related to the Arena Acquisition and $16.0 million for the settlement of a dispute with certain working interest owners during the 2010 period. These decreases were partially offset by an increase in payroll expenses in the nine-month period ended September 30, 2011 due to an increase in the number of Company employees.

The Company recorded a net gain of $489.1 million ($34.7 million realized loss and $523.8 million unrealized gain) on its commodity derivative contracts for the nine-month period ended September 30, 2011 compared to a net gain of $114.4 million ($238.2 million realized gain and $123.8 million unrealized loss) in the same period of 2010. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”

Other Income (Expense). Total other expense increased to $217.6 million in the nine-month period ended September 30, 2011 from $187.7 million in the nine-month period ended September 30, 2010. The increase is reflected in the table below.

	Nine Months Ended September 30,
	2011			2010			$ Change			% Change
	(In thousands)
Other income (expense)
Interest income	$	94		$	236		$	(142	)		(60.2	)%
Interest expense		(180,171	)		(189,989	)		9,818			(5.2	)%
Loss on extinguishment of debt		(38,232	)		—			(38,232	)		(100.0	)%
Other income, net		662			2,062			(1,400	)		(67.9	)%
Total other expense		(217,647	)		(187,691	)		(29,956	)		16.0	%
Income (loss) before income taxes		550,823			(66,499	)		617,322			(928.3	)%
Income tax benefit		(6,013	)		(457,086	)		451,073			(98.7	)%
Net income		556,836			390,587			166,249			42.6	%
Less: net income attributable to noncontrolling interest		74,055			3,547			70,508			1,987.8	%
Net income attributable to SandRidge Energy, Inc.	$	482,781		$	387,040		$	95,741			24.7	%

In connection with the tender offer to purchase and the redemption of the 8.625% Senior Notes, the Company recognized a loss on extinguishment of debt of $38.2 million for the nine-month period ended September 30, 2011. The loss represents the premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes.

In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company recorded an additional net deferred tax liability of $7.0 million associated with the Arena Acquisition. Management determined that it is more likely than not that the Company will now realize a benefit from more of its existing deferred tax assets as the additional Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. As a result of recording an additional net deferred tax liability, the Company released a corresponding portion of its previously recorded valuation allowance resulting in a deferred tax benefit. In the third quarter of 2011, the Company filed the final income tax returns for Arena and its subsidiaries resulting in a current tax provision of $0.74 million. The $6.0 million net tax benefit for the nine-month period ended September 30, 2011 is primarily comprised of the benefit associated with the partial release of the Company’s previously recorded valuation allowance against its net deferred tax asset and the filing of the final income tax returns for Arena and its subsidiaries. The Company reported an income tax benefit of $457.1 million for the nine-month period ended September 30, 2010. The income tax benefit was primarily attributable to the release of a portion of the Company’s valuation allowance against its net deferred tax asset after the Company recorded net deferred tax liabilities related to the Arena Acquisition in July 2010.

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Net income attributable to noncontrolling interest increased to $74.1 million for the nine months ended September 30, 2011 compared to $3.5 million for the same period in 2010 due to completion of the Mississippian Trust’s initial public offering in April 2011 and the Permian Trust’s initial public offering in August 2011.

Liquidity and Capital Resources

The Company’s primary sources of liquidity and capital resources are cash flow generated from operations, borrowings under the Company’s senior credit facility, the issuance of equity and debt securities and proceeds from sales or other monetization of assets.

• In March 2011, the Company received net proceeds of $880.7 million upon the issuance of the 7.5% Senior Notes, which were used to redeem the 8.625% Senior Notes and repay borrowings under the Company’s senior credit facility.

• In April 2011, the Company received proceeds of $336.9 million as partial consideration for the conveyance of royalty interests in certain of the Company’s oil and natural gas properties to the Mississippian Trust. The Company used the net proceeds it received to repay borrowings under the Company’s senior credit facility and for general corporate purposes.

• In August 2011, the Company received proceeds of approximately $580.6 million as partial consideration for the conveyance of royalty interests in certain of the Company’s oil and natural gas properties in the Permian Basin in Andrews County, Texas to the Permian Trust. The Company used or plans to use the net proceeds it received to repay borrowings under the Company’s senior credit facility and for general corporate purposes.

• In September 2011, the Company received approximately $270.7 million upon the sale of a 13.2% working interest in acreage it has leased in the Mississippian formation in the Mid-Continent and agreed to sell certain of the Company’s East Texas natural gas properties for approximately $231.0 million. The Company intends to use the cash proceeds from these sales to fund a portion of its drilling program and for general corporate purposes.

The Company’s primary uses of capital are expenditures related to its oil and natural gas properties, including costs related to drilling and completion of wells, and other fixed assets, the acquisition of oil and natural gas properties, the repayment of amounts outstanding on its senior credit facility, the payment of dividends on its outstanding convertible perpetual preferred stock and interest payments on its outstanding debt. The Company maintains access to funds that may be needed to meet capital funding requirements through its senior credit facility.

Working Capital

The Company’s working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under its senior credit facility and changes in the fair value of its outstanding commodity derivative instruments. Absent any significant effects from its commodity derivative instruments, the Company typically has a working capital deficit or a relatively small amount of positive working capital because the Company’s capital spending generally has exceeded the Company’s cash flows from operations and it generally uses excess cash to pay down borrowings outstanding under its credit arrangements.

At September 30, 2011, the Company had a working capital surplus of $136.5 million compared to a deficit of $368.9 million at December 31, 2010. Current assets increased $452.4 million at September 30, 2011, compared to current assets at December 31, 2010, primarily due to a $319.6 million increase in cash and cash equivalents, as a result of proceeds received from the initial public offering of the Permian Trust and asset sales, and a $91.4 million increase in the asset positions of the Company’s current derivative contracts, resulting from a decrease in average oil prices at September 30, 2011 compared to applicable contract prices. Current liabilities decreased $52.9 million, primarily due to a $94.4 million decrease in the liability positions on the Company’s current derivative contracts, resulting primarily from a decrease in average oil prices at September 30, 2011 compared to applicable contract prices, offset by a $36.9 million increase in accounts payable and accrued expenses.

The Company expects to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2011 and 2012 based on cash flow from operating activities, availability under its senior credit facility, anticipated proceeds from sales or other monetizations of assets and potential access to the capital markets.

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Cash Flows

The Company’s cash flows for the nine months ended September 30, 2011 and 2010 were as follows:

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Cash flows provided by operating activities	$	327,956		$	339,212
Cash flows used in investing activities		(709,367	)		(714,098	)
Cash flows provided by financing activities		700,985			369,614
Net increase (decrease) in cash and cash equivalents	$	319,574		$	(5,272	)

Cash Flows from Operating Activities

The Company’s operating cash flow is mainly influenced by the prices the Company receives for its oil and natural gas production; the quantity of oil and natural gas it produces; settlements on derivative contracts; third-party demand for its drilling rigs and oil field services and the rates it is able to charge for these services; and the margins it obtains from its natural gas and CO₂ gathering and treating contracts.

Net cash provided by operating activities for the nine months ended September 30, 2011 and 2010 was $328.0 million and $339.2 million, respectively. Cash provided by operating activities decreased slightly for the nine-month period ended September 30, 2011 compared to the same period in 2010 due to a decrease in realized gains on the Company’s commodity derivative contracts, partially offset by an increase in oil and natural gas revenues as a result of increased oil production.

Cash Flows from Investing Activities

The Company dedicates and expects to continue to dedicate a substantial portion of its capital expenditure program toward the 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 slightly to $709.4 million in the nine-month period ended September 30, 2011 from $714.1 million in the comparable period of 2010 as the increase in capital expenditures during the nine-month period ended September 30, 2011 was offset by increased proceeds from the sale of assets during the period. Proceeds from the asset sales, as well as the sale of working interests to Atinum during the nine-month period ended September 30, 2011 totaled approximately $624.8 million.

Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the nine-month periods ended September 30, 2011 and 2010 are summarized below:

	Nine Months Ended September 30,
	2011		2010
	(In thousands)
Capital Expenditures
Exploration and production	$	1,259,491	$	706,056
Drilling and oil field services		20,692		26,509
Midstream gas services		15,392		46,902
Other		37,818		16,126
Total	$	1,333,393	$	795,593

Cash Flows from Financing Activities

The Company’s financing activities provided $701.0 million in cash for the nine-month period ended September 30, 2011 compared to $369.6 million in the comparable period in 2010. Cash provided by financing activities during the nine months ended September 30, 2011 was primarily comprised of $880.7 million of net proceeds from the issuance of the 7.5% Senior Notes, $336.9 million of net proceeds from the issuance of units by the Mississippian Trust and $580.6 million of net proceeds from the issuance of units by the Permian Trust. These amounts were offset by the purchase and redemption of $650.0 million aggregate principal amount of the 8.625% Senior Notes, the premium of $30.3 million paid in connection with the purchase and redemption of the 8.625% Senior Notes, $340.0 million of net repayments under the senior credit facility and $46.2 million of dividends paid on the Company’s convertible perpetual preferred stock.

Indebtedness

Senior Credit Facility.The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. The Company pays a 0.5% commitment fee on any available portion of the senior credit facility. Effective March 15, 2011, the borrowing base was reduced to $790.0 million due to the issuance of the Company’s 7.5%

47

Senior Notes. The borrowing base is determined based upon the discounted present value of future cash flows attributable to the Company’s proved reserves. 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. Outstanding letters of credit affect the availability under the senior credit facility on a dollar-for-dollar basis. The senior credit facility matures on April 15, 2014, unless the Company’s Senior Floating Rate Notes have not been refinanced by December 31, 2013, in which case the senior credit facility will mature on January 31, 2014.

On February 23, 2011, the Company’s senior credit facility was amended to, among other things, (a) exclude from the calculation of Consolidated Net Income the net income (or loss) of a Royalty Trust, except to the extent of cash distributions received by the Company, (b) establish that an investment in a Royalty Trust and dispositions to, and of interests in, Royalty Trusts are permitted, (c) clarify that a Royalty Trust is not a Subsidiary, (d) allow the Company to net against its calculation of Consolidated Funded Indebtedness cash balances exceeding $10.0 million in the event no loans are outstanding under the senior credit facility at that time, and (e) establish that, for any fiscal quarter ending prior to March 31, 2012, if the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0 then compliance with the Company’s Consolidated Leverage Ratio covenant is not required. Terms capitalized in the preceding sentence have the meaning given to them in the senior credit facility, as amended.

On April 20, 2011, the senior credit facility was further amended. The amendment permits the Company to pay cash dividends on its 7.0% convertible perpetual preferred stock. In October 2011, the borrowing base was reaffirmed at $790.0 million.

As of September 30, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters, unless, for any quarter ending prior to March 31, 2012, the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0, calculated using the last four completed fiscal quarters, (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) and (iii) ratio of the Company’s secured indebtedness to EBITDA, which may not exceed 2.0:1.0 at each quarter end, calculated using the last four completed fiscal quarters. The Company remains in compliance with all financial covenants under the senior credit facility.

Senior Notes.On March 1, 2011, the Company announced a cash tender offer to purchase any and all of the outstanding $650.0 million aggregate principal amount of its 8.625% Senior Notes. The Company purchased approximately 94.5%, or $614.2 million of these notes. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes.

In March 2011, the Company issued $900.0 million of its 7.5% Senior Notes. Net proceeds were used to fund the tender offer for and redemption of the 8.625% Senior Notes and to repay amounts outstanding under the Company’s senior credit facility. In conjunction with the issuance of the 7.5% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to conduct a registered exchange offer for or register the resale of these notes before March 14, 2012. On October 17, 2011, the Company commenced a registered exchange offer for the 7.5% Senior Notes. The terms of the 7.5% Senior Notes to be issued in the exchange offer will be identical to the terms of the senior notes to be exchanged, except that the transfer restrictions, registration rights and provisions for additional interest relating to the exchanged notes will not apply to the 7.5% Senior Notes to be issued in the exchange offer.

Long-term obligations under the senior credit facility and other long-term debt consist of the following at September 30, 2011 (in thousands):

Senior credit facility	$	—
Other notes payable		16,280
Senior Floating Rate Notes due 2014		350,000
9.875% Senior Notes due 2016, net of $11,407 discount		354,093
8.0% Senior Notes due 2018		750,000
8.75% Senior Notes due 2020, net of $6,563 discount		443,437
7.5% Senior Notes due 2021		900,000
Total debt	$	2,813,810

The indentures governing the senior notes referred to above contain limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers.

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Maturities of Long-Term Debt. Aggregate maturities of long-term debt, excluding discounts, for the next five fiscal years are as follows (in thousands):

2011	$	251
2012		1,051
2013		1,120
2014		351,191
2015		1,266
Thereafter		2,476,901
Total debt	$	2,831,780

For more information about the senior credit facility, the senior notes and the Company’s other long-term debt obligations, see Note 11 to the unaudited condensed consolidated financial statements included in this Quarterly Report.

Outlook

The Company’s 2011 and 2012 budget for capital expenditures, including expenditures related to its drilling programs for the Mississippian Trust and the Permian Trust, and excluding acquisitions, is $1.8 billion per year. The majority of the Company’s capital expenditures are discretionary and could be curtailed if the Company’s cash flows decline from expected levels or if the Company is unable to obtain capital on attractive terms. The Company may increase or decrease planned capital expenditures depending on oil and natural gas prices, the availability of capital through asset sales and the issuance of additional equity or long-term debt. The Company plans to fund its remaining 2011 and a portion of its 2012 budget for capital expenditures with proceeds received from the Permian Trust and sale of working interests to Atinum.

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. 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 its cash flows, and while fixed price swap contracts are in place for the majority of expected oil production for 2011 through 2013, fixed price swap contracts are in place for only a portion of expected oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. See Item 3 “Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding the Company’s derivative contracts.

The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements. The Company is dependent on the availability of borrowings under its senior credit facility, along with cash flows from operating activities and proceeds from planned asset sales and other asset monetizations, to fund those capital expenditures. Based on anticipated oil and natural gas prices, availability under the Company’s senior credit facility, anticipated proceeds from the sales or other monetizations of assets and potential access to the capital markets, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2011 and for 2012. 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 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. The Company has the ability to reduce its capital expenditures if cash flows are not available.

The Company may choose to refinance borrowings outstanding under its senior credit facility by issuing long-term debt or equity in the public or private markets, or both. In addition, the Company may from time to time seek to retire or purchase its outstanding securities through cash purchases and/or exchanges in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

As of September 30, 2011, the Company’s cash and cash equivalents were $325.4 million and the Company had approximately $2.8 billion in total debt outstanding with no amount outstanding under its senior credit facility. As of and for the three and nine-month periods ended September 30, 2011, the Company was in compliance with all of the covenants under all of its senior notes and its senior credit facility. As of October 31, 2011, the Company’s cash and cash equivalents were $226.7 million and the Company had no amount outstanding under its senior credit facility and $25.8 million outstanding in letters of credit.

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ITEM 3.Quantitative and Qualitative Disclosures About Market Risk

General

The discussion in this section provides information about the financial instruments the Company uses 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. The Company’s most significant market risk relates to the prices it receives for its oil and natural gas production. Due to the historical volatility of these commodities, the Company periodically has entered into, and expects in the future to enter into, derivative arrangements for the purpose of reducing the variability of oil and natural gas prices the Company receives for its production. From time to time, the Company enters into commodity pricing derivative contracts for a portion of its anticipated production volumes depending upon management’s view of opportunities under the then prevailing current market conditions. The Company’s senior credit facility limits its ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. The Company does not intend to enter into derivative contracts that would exceed its expected production volumes for the period covered by the derivative arrangement. Future credit facilities could require a minimum level of commodity price hedging.

The Company uses, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, collars and basis protection swaps. The Company’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period. The Company’s natural gas fixed price swap transactions are settled based upon New York Mercantile Exchange prices, and the Company’s natural gas basis protection swap transactions are settled based upon the index price of natural gas at the Waha hub, a West Texas gas marketing and delivery center, and the Houston Ship Channel. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. The Company’s natural gas collars are settled based upon the New York Mercantile Exchange prices on the penultimate commodity business day for the relevant contract. Natural gas collars only result in a cash settlement when the settlement price exceeds the fixed-price ceiling or falls below the fixed-price floor.

The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts on the balance sheet at fair value, which reflects changes in oil and natural gas prices. The Company establishes fair value of its derivative contracts by price quotations obtained from counterparties to the derivative contracts. Changes in fair values of the Company’s derivative contracts are recognized as unrealized gains and losses in current period earnings. As a result, the Company’s current period earnings may be significantly affected by changes in the fair value of its commodity derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.

See Note 12 to the Company’s unaudited condensed consolidated financial statements included in this Quarterly Report for a summary of open commodity derivative contracts.

The following table summarizes the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts for the three and nine-month periods ended September 30, 2011 and 2010 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Realized loss (gain)(1)	$	7,814		$	(77,692	)	$	34,696		$	(238,240	)
Unrealized (gain) loss		(604,550	)		144,887			(523,792	)		123,862
(Gain) loss on commodity derivative contracts	$	(596,736	)	$	67,195		$	(489,096	)	$	(114,378	)

(1) Includes $9.9 million and $48.1 million of realized gains for the three and nine-month periods ended September 30, 2011, respectively, related to out-of-period settlements. Includes $48.2 million and $110.6 million of realized gains for the three and nine-month periods ended September 30, 2010, respectively, related to out-of-period settlements.

Credit Risk. The use of derivative contracts involves the risk that the counterparties will be unable to meet their obligations under the contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. As of September 30, 2011, the Company had 21 approved derivative counterparties, 20 of which are lenders under its senior credit facility. The Company currently has derivative contracts outstanding with 14 of these counterparties. The Company periodically reviews the credit quality of each counterparty to its derivative contracts and the level of overall financial exposure the Company has to each counterparty to limit its credit risk exposure with respect to these contracts. Additionally, the Company applies a 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. The counterparties for all of the Company’s derivative transactions have an “investment grade” credit rating.

The Company’s ability to fund its capital expenditure budget is partially dependent upon the availability of funds under its senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in the senior credit facility, the Company’s bank group currently consists of 26 financial institutions with commitments ranging from 0.57% to 5.41%.

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Interest Rate Risk. The Company is subject 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 its 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, the Company may enter into derivative transactions to fix the interest the Company pays on a portion of the amount outstanding on its variable rate debt. At September 30, 2011, the Company had a $350.0 million notional interest rate swap agreement. The interest rate swap agreement effectively serves to fix the 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. This swap has not been designated as a hedge.

The Company’s interest rate swap reduces its market risk on its Senior Floating Rate Notes. The Company uses sensitivity analyses to determine the impact that market risk exposures could have on the Company’s variable interest rate borrowings if not for its interest rate swap. Based on the $350.0 million outstanding balance of the Company’s Senior Floating Rate Notes at September 30, 2011, a one percent change in the applicable rates, with all other variables held constant, would have resulted in a change in the Company’s interest expense of approximately $0.9 million and $2.6 million for the three and nine-month periods ended September 30, 2011, respectively.

The following table summarizes the cash settlements and valuation gains and losses on the Company’s interest rate swaps for the three and nine-month periods ended September 30, 2011 and 2010 (in thousands):

	Three Months  Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
Realized loss	$	2,520		$	1,883	$	7,005		$	6,046
Unrealized (gain) loss		(1,965	)		3,253		(3,374	)		11,502
Loss on interest rate swaps	$	555		$	5,136	$	3,631		$	17,548

ITEM 4.Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company performed an evaluation of the effectiveness of the design and operation of its 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, the Company’s Chief Executive Officer and the Company’s Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2011 to provide reasonable assurance that the information required to be disclosed by the Company in its 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 the Company’s internal control over financial reporting during the quarter ended September 30, 2011 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. Other Information

ITEM 1.Legal Proceedings

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with the construction by Aspen of a natural gas pipeline in West Texas. On October 14, 2011, the complaint was amended to add Odessa Fuels, LLC, Odessa Fuels Marketing, LLC and Odessa Field Services and Compression as plaintiffs. The plaintiffs seek damages for breach of contract and for the construction cost of the pipeline, which they claim approach $100.0 million. The Company intends to defend this lawsuit vigorously and believes the plaintiff’s claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP (collectively, the “plaintiffs”), filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”), in the 83^rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including carbon dioxide, or “CO₂“) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO₂ produced from plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Commissioner of the General Land Office of the State of Texas (“GLO”) is named as an additional defendant in the lawsuit as some of the affected oil and natural gas leases described in plaintiffs’ allegations cover mineral classified lands in which the GLO is entitled to one-half of the royalties attributable to such leases. The GLO has filed a cross-claim against the SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands. The Company intends to defend this lawsuit vigorously. This case is in the early stages and accordingly, an estimate of reasonably possible losses, if any, associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. (collectively, “Plaintiffs”) filed a lawsuit against SandRidge Energy, Inc., SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain directors and senior executive officers of SandRidge Energy, Inc. (collectively, “Defendants”) in the U.S. District Court for the District of Connecticut. Plaintiffs allege that Defendants made false and misleading statements to U.S. Drilling Capital Management LLC and Plaintiffs prior to the entry into a participation agreement among Patriot Exploration LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by Plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, Plaintiffs have invested approximately $15.0 million under the participation agreement. Plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes Plaintiffs’ claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.

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

ITEM 1A. Risk Factors

We describe one of the Company’s business risk factors below. This description includes a material change to the risk factors previously disclosed in Part I, Item 1A of the 2010 Form 10-K.

Production of oil, natural gas and natural gas liquids could be materially and adversely affected by severe or unseasonable weather.

Production of oil, natural gas and natural gas liquids could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

• evacuation of personnel and curtailment of operations;

• weather-related damage to drilling rigs or other facilities, resulting in suspension of operations;

• inability to deliver materials to worksites; and

• weather-related damage to pipelines and other transportation facilities.

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

As part of the Company’s restricted stock program, the Company makes required tax payments on behalf of employees when their 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. The shares withheld are initially recorded as treasury shares, then immediately retired. During the quarter ended September 30, 2011, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares  Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2011 — July 31, 2011		524,611	$	10.73	N/A	N/A
August 1, 2011 — August 31, 2011		712	$	9.53	N/A	N/A
September 1, 2011 — September 30, 2011		799	$	7.27	N/A	N/A

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

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SIGNATURE

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

SandRidge Energy, Inc.
By:	/s/    JAMES D. BENNETT
	James D. Bennett Executive Vice President and Chief Financial Officer

Date: November 7, 2011

EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
3.1	Certificate of Incorporation of SandRidge Energy, Inc.	S-1	333-148956	3.1	01/30/2008
3.2	Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated July 16, 2010	10-Q	001-33784	3.2	08/09/2010
3.3	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	03/09/2009
10.1	Development Agreement, by and between SandRidge Energy, Inc., SandRidge Exploration and Production, LLC and SandRidge Permian Trust	8-K	001-33784	10.1	08/19/2011
31.1	Section 302 Certification — Chief Executive Officer					*
31.2	Section 302 Certification — Chief Financial Officer					*
32.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer					*
101.INS	XBRL Instance Document					*
101.SCH	XBRL Taxonomy Extension Schema Document					*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					*
101.DEF	XBRL Taxonomy Extension Definition Document					*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					*