SandRidge Energy (SD) 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

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  x    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  x    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	x	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  x

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on April 30, 2012, was 489,429,991.

SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended March 31, 2012

INDEX

PART I. FINANCIAL INFORMATION
ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements 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	46
ITEM 4.	Controls and Procedures	47
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	48
ITEM 1A.	Risk Factors	48
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
ITEM 6.	Exhibits	49

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, effects of the acquisition of Dynamic Offshore Resources, LLC (“Dynamic”) on the Company’s financial condition and financial results and other statements concerning the Company’s operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “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. The Company has based these forward-looking statements on its 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. 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’s 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 forward-looking statements in this respect speak only as of the date hereof. The Company disclaims any obligation to update or revise any forward-looking statements, unless required by law, and it cautions readers not to rely on them unduly. While the Company’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (the “2011

Form 10-K”).

PART I. Financial Information

ITEM 1.Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

	March 31, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	127,842		$	207,681
Accounts receivable, net		240,636			206,336
Derivative contracts		7,526			4,066
Inventories		9,491			6,903
Costs in excess of billings		1,621			—
Other current assets		32,324			16,854
Total current assets		419,440			441,840
Oil and natural gas properties, using full cost method of accounting
Proved		9,159,518			8,969,296
Unproved		748,953			689,393
Less: accumulated depreciation, depletion and impairment		(4,874,325	)		(4,791,534	)
		5,034,146			4,867,155
Other property, plant and equipment, net		576,668			522,269
Restricted deposits		27,904			27,912
Derivative contracts		1,109			26,415
Goodwill		235,396			235,396
Other assets		83,436			98,622
Total assets	$	6,378,099		$	6,219,609
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	1,070		$	1,051
Accounts payable and accrued expenses		601,785			506,784
Billings and estimated contract loss in excess of costs incurred		34,310			43,320
Derivative contracts		97,462			115,435
Asset retirement obligation		32,906			32,906
Total current liabilities		767,533			699,496
Long-term debt		2,813,484			2,813,125
Derivative contracts		292,110			49,695
Asset retirement obligation		100,126			95,210
Other long-term obligations		13,787			13,133
Total liabilities		3,987,040			3,670,659
Commitments and contingencies (Note 11)
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at March 31, 2012 and December 31, 2011; aggregate liquidation preference of $265,000		3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at March 31, 2012 and December 31, 2011; aggregate liquidation preference of $200,000		2			2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at March 31, 2012 and December 31, 2011; aggregate liquidation preference of $300,000		3			3
Common stock, $0.001 par value, 800,000 shares authorized; 416,478 issued and 415,544 outstanding at March 31, 2012 and 412,827 issued and 411,953 outstanding at December 31, 2011		401			399
Additional paid-in capital		4,632,544			4,568,856
Treasury stock, at cost		(6,617	)		(6,158	)
Accumulated deficit		(3,169,153	)		(2,937,094	)
Total SandRidge Energy, Inc. stockholders’ equity		1,457,183			1,626,011
Noncontrolling interest		933,876			922,939
Total equity		2,391,059			2,548,950
Total liabilities and equity	$	6,378,099		$	6,219,609

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 March 31,
	2012			2011
	(Unaudited)
Revenues
Oil and natural gas	$	341,365		$	266,942
Drilling and services		29,309			21,034
Midstream and marketing		8,306			22,258
Other		2,655			2,614
Total revenues		381,635			312,848
Expenses
Production		83,310			73,957
Production taxes		12,254			10,575
Drilling and services		17,560			15,041
Midstream and marketing		7,954			22,283
Depreciation and depletion — oil and natural gas		87,066			71,460
Depreciation and amortization — other		14,513			13,093
Accretion of asset retirement obligation		2,607			2,426
General and administrative		50,301			34,414
Loss on derivative contracts		254,646			277,628
Loss (gain) on sale of assets		3,080			(201	)
Total expenses		533,291			520,676
Loss from operations		(151,656	)		(207,828	)
Other income (expense)
Interest expense		(66,965	)		(59,438	)
Loss on extinguishment of debt		—			(36,181	)
Other income, net		2,468			1,197
Total other expense		(64,497	)		(94,422	)
Loss before income taxes		(216,153	)		(302,250	)
Income tax expense		71			88
Net loss		(216,224	)		(302,338	)
Less: net income attributable to noncontrolling interest		1,954			6
Net loss attributable to SandRidge Energy, Inc.		(218,178	)		(302,344	)
Preferred stock dividends		13,881			13,940
Loss applicable to SandRidge Energy, Inc. common stockholders	$	(232,059	)	$	(316,284	)
Loss per share
Basic	$	(0.58	)	$	(0.79	)
Diluted	$	(0.58	)	$	(0.79	)
Weighted average number of common shares outstanding
Basic		400,597			398,251
Diluted		400,597			398,251

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

5

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In thousands)

	SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock				Common Stock					Additional Paid-In			Treasury			Accumulated			Noncontrolling
	Shares		Amount		Shares			Amount		Capital			Stock			Deficit			Interest			Total
										(Unaudited)
Three months ended March 31, 2011
Balance, December 31, 2010		7,650	$	8		406,360		$	398	$	4,528,912		$	(3,547	)	$	(2,989,576	)	$	11,288		$	1,547,483
Distributions to noncontrolling interest owners		—		—		—			—		—			—			—			(1	)		(1	)
Stock issuance expense		—		—		—			—		(143	)		—			—			—			(143	)
Purchase of treasury stock		—		—		—			—		—			(4,809	)		—			—			(4,809	)
Retirement of treasury stock		—		—		—			—		(4,809	)		4,809			—			—			—
Stock purchases — retirement plans, net of distributions		—		—		(81	)		—		1,389			(598	)		—			—			791
Stock-based compensation		—		—		—			—		14,206			—			—			—			14,206
Stock-based compensation excess tax benefit		—		—		—			—		10			—			—			—			10
Issuance of restricted stock awards, net of cancellations		—		—		3,819			—		—			—			—			—			—
Net (loss) income		—		—		—			—		—			—			(302,344	)		6			(302,338	)
Convertible perpetual preferred stock dividends		—		—		—			—		—			—			(13,940	)		—			(13,940	)
Balance, March 31, 2011		7,650	$	8		410,098		$	398	$	4,539,565		$	(4,145	)	$	(3,305,860	)	$	11,293		$	1,241,259
Three months ended March 31, 2012
Balance, December 31, 2011		7,650	$	8		411,953		$	399	$	4,568,856		$	(6,158	)	$	(2,937,094	)	$	922,939		$	2,548,950
Sale of royalty trust units		—		—		—			—		57,126			—			—			41,723			98,849
Distributions to royalty trust unitholders		—		—		—			—		—			—			—			(32,740	)		(32,740	)
Purchase of treasury stock		—		—		—			—		—			(6,391	)		—			—			(6,391	)
Retirement of treasury stock		—		—		—			—		(6,391	)		6,391			—			—			—
Stock purchases — retirement plans, net of distributions		—		—		(59	)		—		553			(459	)		—			—			94
Stock-based compensation		—		—		—			—		12,395			—			—			—			12,395
Stock-based compensation excess tax benefit		—		—		—			—		7			—			—			—			7
Issuance of restricted stock awards, net of cancellations		—		—		3,650			2		(2	)		—			—			—			—
Net (loss) income		—		—		—			—		—			—			(218,178	)		1,954			(216,224	)
Convertible perpetual preferred stock dividends		—		—		—			—		—			—			(13,881	)		—			(13,881	)
Balance, March 31, 2012		7,650	$	8		415,544		$	401	$	4,632,544		$	(6,617	)	$	(3,169,153	)	$	933,876		$	2,391,059

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)

	Three Months Ended March 31,
	2012			2011
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(216,224	)	$	(302,338	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization		101,579			84,553
Accretion of asset retirement obligation		2,607			2,426
Debt issuance costs amortization		2,538			2,873
Discount amortization on long-term debt		635			575
Loss on extinguishment of debt		—			36,181
Unrealized loss on derivative contracts		127,836			267,254
Realized loss on amended derivative contracts		117,108			—
Realized loss on financing derivatives		2,978			2,348
Loss (gain) on sale of assets		3,080			(201	)
Investment income		(568	)		(150	)
Stock-based compensation		11,371			8,806
Changes in operating assets and liabilities		77,970			(22,665	)
Net cash provided by operating activities		230,910			79,662
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment		(601,841	)		(427,391	)
Acquisition of assets		(10,511	)		(1,548	)
Proceeds from sale of assets		269,008			159,536
Net cash used in investing activities		(343,344	)		(269,403	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		—			1,493,000
Repayments of borrowings		(257	)		(1,230,272	)
Premium on debt redemption		—			(28,795	)
Debt issuance costs		(7,223	)		(19,099	)
Proceeds from the sale of royalty trust units		98,849			—
Distributions to royalty trust unitholders		(32,740	)		—
Noncontrolling interest distributions		—			(1	)
Stock issuance expense		—			(143	)
Stock-based compensation excess tax benefit		7			10
Purchase of treasury stock		(7,144	)		(5,469	)
Dividends paid — preferred		(17,263	)		(18,130	)
Cash (paid) received on settlement of financing derivatives		(1,634	)		1,314
Net cash provided by financing activities		32,595			192,415
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(79,839	)		2,674
CASH AND CASH EQUIVALENTS, beginning of year		207,681			5,863
CASH AND CASH EQUIVALENTS, end of period	$	127,842		$	8,537
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	(32,183	)	$	(11,222	)
Change in convertible perpetual preferred stock dividends payable	$	(3,382	)	$	(4,190	)
Adjustment to oil and natural gas properties for estimated contract loss	$	10,000		$	19,000

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. (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 the Mid-Continent area of Oklahoma and Kansas, west Texas and the Gulf of Mexico. The Company’s primary areas of focus are the Mississippian formation in the Mid-Continent and the Permian Basin in west Texas. The Company also owns and operates other interests in the Mid-Continent, West Texas Overthrust (“WTO”) and Gulf Coast. The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and 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, 2011 have been derived from the audited financial statements contained in the Company’s 2011 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 2011 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 2011 Form 10-K.

Reclassifications. Certain reclassifications have been made to prior period financial statements to conform to the current period presentation. These reclassifications had no effect on the Company’s previously reported results of operations.

Use of Estimates. The preparation of the unaudited interim condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil and natural gas reserves; cash flow estimates used in impairment tests of goodwill and other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; assigning fair value and allocating purchase price in connection with business combinations; income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly from these estimates.

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, the global political environment, 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. See Note 9 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. Additionally, the Company has a drilling obligation to each of SandRidge Mississippian Trust I (the “Mississippian Trust I”) and SandRidge Permian Trust (the “Permian Trust”). See Note 3 for discussion of these drilling obligations. In addition, during April 2012, the Company entered into a development agreement with and incurred a drilling obligation to SandRidge Mississippian Trust II (the “Mississippian Trust II”). See Note 18 for discussion of this drilling obligation. 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, to fund such capital expenditures. Based on current cash balances, anticipated oil and natural gas prices and production and availability under the senior credit facility, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs 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 8 for discussion of the financial covenants in the senior credit facility.

8

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Recently Adopted Accounting Pronouncements. 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”), which clarifies the FASB’s intent regarding the application of existing fair value measurements and requires additional disclosure information regarding valuation processes and inputs used. The new disclosure requirements, which are effective for interim and annual reporting periods beginning after December 15, 2011, were implemented by the Company in the first quarter of 2012. The implementation of ASU 2011-04 had no impact on the Company’s financial position or results of operations. See Note 4.

Recent Accounting Pronouncements Not Yet Adopted. In September 2011, the FASB issued Accounting Standards Update 2011-08, “Testing Goodwill for Impairment” (“ASU 2011-08”), which 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 will implement ASU 2011-08 for its 2012 goodwill impairment test and does not expect this pronouncement to have any impact on the value of its goodwill.

For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2011 Form 10-K.

2. Acquisitions and Divestitures

2011 Divestitures

The Company completed the following divestitures in 2011, all of which were accounted for as adjustments to the full cost pool with no gain or loss recognized:

• In July 2011, the Company sold its Wolfberry assets in the Permian Basin for $151.6 million, net of fees and post-closing adjustments.

• In August 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for $199.0 million, net of fees and post-closing adjustments.

• In November 2011, the Company sold its east Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $225.8 million, net of fees and post-closing adjustments.

Sale of Working Interests and Associated Drilling Carry Commitments

During 2011 and 2012, the Company entered into two transactions whereby the Company sold non-operated working interests in the Mississippian formation. In these transactions, the Company received aggregate cash proceeds of $500.0 million for the sale of working interests and received drilling carry commitments to fund a portion of its future drilling and completion costs totaling $1.0 billion. For accounting purposes, initial cash proceeds from these transactions were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and amounts received during 2011 and 2012 attributable to the drilling carry reduced the Company’s capital expenditures. These transactions, as well as drilling carry amounts received and remaining as of March 31, 2012 are as follows:

Partner	Closing Date		Proceeds Received At Closing (1)		Drilling Carry Received or Billed		Drilling  Carry Remaining
			(in millions)
Atinum MidCon I, LLC		September 2011	$	287.0	$	41.8	$	208.2
Repsol E&P USA, Inc.		January 2012		272.5		10.8		739.2
			$	559.5	$	52.6	$	947.4

(1) Includes amounts related to the drilling carry

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

In September 2011, the Company sold to Atinum MidCon I, LLC (“Atinum”) non-operated working interests equal to approximately 113,000 net acres in the Mississippian formation in northern Oklahoma and southern Kansas for approximately $250.0 million. In addition, Atinum agreed to pay the development costs related to its working interest, as well as a portion of the Company’s development costs equal to Atinum’s working interest for wells within an area of mutual interest up to $250.0 million. The Company expects Atinum’s funding of the Company’s development cost for wells within the area of mutual interest to occur over a three-year period.

In January 2012, the Company sold (i) non-operated working interests equal to approximately 250,000 net acres, in the Mississippian formation in western Kansas and (ii) non-operated working interest equal to approximately 114,000 net acres, and a proportionate share of existing salt water disposal facilities in the Mississippian formation in northern Oklahoma and southern Kansas to Repsol E&P USA Inc. (“Repsol”) for approximately $250.0 million. In addition, Repsol agreed to pay the development costs related to its working interest, as well as a portion of the Company’s development costs equal to 200% of Repsol’s working interest for wells within an area of mutual interest up to $750.0 million. The Company expects Repsol’s funding of the Company’s development cost for wells within the area of mutual interest to occur over a three-year period.

During the three-month period ended March 31, 2012, the Company received or billed approximately $33.7 million of drilling carry from Atinum and Repsol, which reduced the Company’s capital expenditures for the period.

3. Variable Interest Entities

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.

Grey Ranch Plant, 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, which represents a variable interest. 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 due to certain equity holders lacking the ability to participate in decisions impacting GRLP. 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. As a result of amendments to certain agreements related to the ownership and operation of GRLP in October 2009, the Company 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. The Company began consolidating the activity of GRLP in its consolidated financial statements prospectively on October 1, 2009, the effective date of the amendments. The 50% ownership interest not held by the Company is presented as noncontrolling interest in the consolidated financial statements.

GRLP’s assets can only 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 March 31, 2012 and December 31, 2011, $8.0 million and $8.2 million, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying condensed unaudited consolidated balance sheets at March 31, 2012 and December 31, 2011 consisted of the following (in thousands):

	March 31, 2012		December 31, 2011
Cash and cash equivalents	$	989	$	1,702
Accounts receivable, net		23		24
Inventory		109		109
Other current assets		117		176
Total current assets		1,238		2,011
Other property, plant and equipment, net		14,696		14,985
Total assets	$	15,934	$	16,996
Accounts payable and accrued expenses	$	209	$	280
Total liabilities	$	209	$	280

10

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 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 and operator of the Plant, 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.

SandRidge Mississippian Trust I. On April 12, 2011, the Mississippian Trust I completed its initial public offering of 17,250,000 common units representing beneficial interests in the Mississippian Trust I. Net proceeds to the Mississippian Trust I, after offering expenses, were approximately $336.9 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust I in exchange for the net proceeds of the offering and 10,750,000 units representing approximately 38.4% of the beneficial interest in the Mississippian Trust I. The royalty interests conveyed to the Mississippian Trust I are in certain existing wells and wells to be drilled on oil and natural gas properties leased by the Company in the Mississippian formation in northern Oklahoma. The conveyance of the royalty interests to the Mississippian Trust I was recorded in April 2011 at the historical cost to the Company, or $309.0 million. The Mississippian Trust I 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 I terminates, 50% of the conveyed royalty interests will automatically revert to the Company.

On February 27, 2012, the Company sold 1,583,937 of its Mississippian Trust I common units in a transaction exempt from registration under Rule 144 under the Securities Act for proceeds of $52.3 million. As a result of the sale, the Company’s beneficial interest in the Mississippian Trust I decreased from 38.4% to 32.7%.

The Mississippian Trust I 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 I’s common units, the Company agreed to subordinate a portion of the Mississippian Trust I units it owns (the “Mississippian Trust I subordinated units”), which constitute 25% of the total outstanding Mississippian Trust I units. The Mississippian Trust I subordinated units are entitled to receive pro rata distributions from the Mississippian Trust I 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 I 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 February 2012, the Mississippian Trust I declared and paid quarterly distributions for the three-month period ended December 31, 2011 of $22.1 million, or $0.79 per unit. Of the total distribution, $13.6 million was distributed to third-party unitholders. See Note 18 for discussion of a distribution declaration by the Mississippian Trust I in April 2012.

Pursuant to a trust agreement, SandRidge has a loan commitment to the Mississippian Trust I, whereby SandRidge will loan funds to the Mississippian Trust I 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 I’s cash is not sufficient to pay ordinary course administrative expenses as they become due. There were no amounts outstanding under the loan commitment at March 31, 2012 or December 31, 2011.

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust I that obligates the Company to drill, or cause to be drilled, a specified number of wells, within an area of mutual interest, which are

11

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

also subject to the royalty interest granted to the Mississippian Trust I, 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 I subordination period”), the Company’s Mississippian Trust I 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 I 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 I a lien on 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 I is proportionately reduced. As of March 31, 2012, the maximum amount recoverable by the Mississippian Trust I under the lien had been reduced to approximately $77.3 million. Additionally, the Company and the Mississippian Trust I entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Mississippian Trust I, and a derivatives agreement, pursuant to which the Company provides to the Mississippian Trust I the economic effects of certain of the Company’s derivative contracts. The tables below present open oil and natural gas commodity derivative contracts at March 31, 2012, the economic effects of which will be provided to the Mississippian Trust I under the derivatives agreement. See Note 9 for further discussion of the derivatives agreement between the Company and the Mississippian Trust I.

Oil Price Swaps

	Notional (MBbl)		Weighted Avg. Fixed Price
April 2012 — December 2012		341	$	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

	Notional (MMBtu)		Weighted Avg. Fixed Price
April 2012 — June 2012		1,126	$	4.90

Natural Gas Collars

	Notional (MMBtu)		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

The Company’s ownership in the Mississippian Trust I and the loan commitment constitute variable interests. The Mississippian Trust I 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 I. The Company has determined it is the primary beneficiary of the Mississippian Trust I as it has (a) the power to direct the activities that most significantly impact the economic performance of the Mississippian Trust I through (i) its participation in the creation and structure of the Mississippian Trust I, (ii) the manner in which it fulfills its drilling obligation to the Mississippian Trust I 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 I subordination period, the obligation to absorb losses and right to receive residual returns, through its ownership of the Mississippian Trust I subordinated units, that could potentially be significant to the Mississippian Trust I. As a result, the Company began consolidating the activities of the Mississippian Trust I into its results of operations in April 2011. In consolidation, the common units of the Mississippian Trust I owned by third parties are reflected as noncontrolling interest in the consolidated financial statements. As discussed above, the Company’s Mississippian Trust I subordinated units will automatically convert to common units at the end of the Mississippian Trust I subordination period.

The Mississippian Trust I’s assets can only be used to settle its own obligations and not other obligations of the Company. The Mississippian Trust I’s creditors have no contractual recourse to the general credit of the Company. Although the Mississippian Trust I is included in the Company’s consolidated financial statements, the Company’s legal interest in the Mississippian Trust I’s assets is limited to its ownership of the Mississippian Trust I units. At March 31, 2012 and December 31, 2011, $356.2 million and $348.9 million, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were attributable to the

12

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Mississippian Trust I. The Mississippian Trust I’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at March 31, 2012 and December 31, 2011 consisted of the following (in thousands):

	March 31,			December 31,
	2012			2011
Cash and cash equivalents(1)	$	1,162		$	1,336
Accounts receivable		6,901			7,471
Total current assets		8,063			8,807
Investment in royalty interests(2)		308,964			308,964
Less: accumulated depletion		(22,822	)		(16,844	)
		286,142			292,120
Total assets	$	294,205		$	300,927
Accounts payable and accrued expenses	$	403		$	276
Total liabilities	$	403		$	276

(1) Includes $1.0 million held by the trustee as reserves for future general and administrative expenses.

(2) Included in oil and natural gas properties on the accompanying unaudited condensed consolidated balance sheets.

SandRidge Permian Trust. On August 16, 2011, the Permian 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 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 offering and 18,000,000 units representing approximately 34.3% of the beneficial interest in the Permian Trust. The royalty interests conveyed to the Permian Trust are in certain existing wells and wells to be drilled on 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. 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.

On March 14, 2012, the Company sold 2,000,000 of its Permian Trust common units in a transaction exempt from registration under Rule 144 under the Securities Act for proceeds of $46.5 million. As a result of the sale, the Company’s beneficial interest in the Permian Trust decreased from 34.3% to 30.5%.

The Permian Trust makes 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 February 2012, the Permian Trust declared and paid quarterly distributions for the three-month period ended December 31, 2011 of $29.1 million, or $0.55 per unit. Of the total distribution, $19.1 million was distributed to third-party unitholders. See Note 18 for discussion of a distribution declaration by the Permian Trust in April 2012.

Pursuant to a 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. There were no amounts outstanding under the loan commitment at March 31, 2012 or December 31, 2011.

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, within an area of mutual interest, 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

13

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Permian Trust a lien on 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 March 31, 2012, the maximum amount recoverable by the Permian Trust under the lien had been reduced to approximately $206.1 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 March 31, 2012 underlying the derivatives agreement, including the contracts novated to the Permian Trust, as of March 31, 2012. The combined volume in the tables below reflects the total volume of the Permian Trust’s oil derivative contracts. See Note 9 for further discussion of the derivatives agreement between the Company and the Permian Trust.

Oil Price Swaps Underlying the Derivatives Agreement

	Notional (MBbl)		Weighted Avg. Fixed Price
April 2012 — December 2012		516	$	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 Permian Trust

	Notional (MBbl)		Weighted Avg. Fixed Price
April 2012 — December 2012		350	$	102.20
January 2013 — December 2013		368	$	102.84
January 2014 — December 2014		311	$	101.75
January 2015 — March 2015		71	$	100.90

The Company’s ownership in the Permian Trust and the loan commitment constitute variable interests. The Permian Trust is considered a VIE due to the lack of voting or similar decision-making rights of its equity holders regarding activities that have a significant effect on the economic success of the Permian Trust. 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 in the consolidated financial statements. As discussed above, the Company’s Permian Trust subordinated units will automatically convert to common units at the end of the Permian Trust subordination period.

14

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The Permian Trust’s assets can only 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 March 31, 2012 and December 31, 2011, $569.7 million and $565.8 million, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were attributable to the Permian Trust. The Permian Trust’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at March 31, 2012 and December 31, 2011 consisted of the following (in thousands):

	March 31,			December 31,
	2012			2011
Cash and cash equivalents(1)	$	1,565		$	1,815
Accounts receivable		10,954			10,886
Derivative contracts		—			1,499
Total current assets		12,519			14,200
Investment in royalty interests(2)		549,831			549,831
Less: accumulated depletion		(12,899	)		(7,560	)
		536,932			542,271
Derivative contracts		1,085			5,668
Total assets	$	550,536		$	562,139
Accounts payable and accrued expenses	$	704		$	210
Derivative contracts		1,018			—
Total liabilities	$	1,722		$	210

(1) Includes $1.0 million held by the trustee as reserves for future general and administrative expenses.

(2) Included in oil and natural gas properties on the accompanying unaudited condensed consolidated balance sheets.

Piñon Gathering Company, LLC.The Company has a gas gathering and operations and maintenance agreement 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. Other than as required under the gas gathering and operations and maintenance agreements, the Company has not provided any support to PGC. 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. The Company had accounts receivable due from PGC of $3.2 million as of March 31, 2012 and December 31, 2011 included in the accompanying unaudited condensed consolidated balance sheets. The Company had accounts payable due to PGC of $6.4 million and $4.6 million as of March 31, 2012 and December 31, 2011, respectively, included in the accompanying unaudited condensed consolidated balance sheets.

4. Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis and 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. 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. 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 classified as Level 1, Level 2 and Level 3, as described below.

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 2 Fair Value Measurements

Derivative contracts. The fair values of the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, interest

15

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

rates and discount rates, or can be corroborated from active markets. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates.

Level 3 Fair Value Measurements

Derivative contracts. The fair values of the Company’s diesel fixed price swaps and natural gas basis swaps are based upon quotes obtained from counterparties to the derivative contracts. These values are reviewed internally for reasonableness through the use of a discounted cash flow model using non-exchange traded regional pricing information. 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 these derivative contracts. The significant unobservable input used in the fair value measurement of the Company’s diesel fixed price swaps is the estimate of diesel prices. Significant increases (decreases) in diesel prices could result in a significantly higher (lower) fair value measurement. The estimated fair value of the Company’s diesel fixed price swaps was $2.3 million at March 31, 2012 based upon diesel price forward curve inputs with a range of $3.24 – $3.40. The significant unobservable input used in the fair value measurement of the Company’s natural gas basis swaps is the estimate of future natural gas basis differentials. Significant increases (decreases) in natural gas basis differentials could result in a significantly higher (lower) fair value measurement. The estimated fair value of the Company’s natural gas basis swaps was ($4.9) million at March 31, 2012 based upon natural gas basis differential forward curve inputs with a range of $0.07 - $0.13.

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

March 31, 2012

	Fair Value Measurements									Assets/ Liabilities at
	Level 1		Level 2		Level 3		Netting(1)			Fair Value
Assets
Restricted deposits	$	27,904	$	—	$	—	$	—		$	27,904
Commodity derivative contracts		—		24,461		2,273		(18,099	)		8,635
Other assets		8,293		—		—		—			8,293
	$	36,197	$	24,461	$	2,273	$	(18,099	)	$	44,832
Liabilities
Commodity derivative contracts	$	—	$	393,629	$	4,948	$	(18,099	)	$	380,478
Interest rate swaps		—		9,094		—		—			9,094
	$	—	$	402,723	$	4,948	$	(18,099	)	$	389,572

December 31, 2011

	Fair Value Measurements									Assets/ Liabilities at
	Level 1		Level 2		Level 3		Netting(1)			Fair Value
Assets
Restricted deposits	$	27,912	$	—	$	—	$	—		$	27,912
Commodity derivative contracts		—		62,746		397		(32,662	)		30,481
Other assets		7,138		—		—		—			7,138
	$	35,050	$	62,746	$	397	$	(32,662	)	$	65,531
Liabilities
Commodity derivative contracts	$	—	$	182,694	$	4,650	$	(32,662	)	$	154,682
Interest rate swaps		—		10,448		—		—			10,448
	$	—	$	193,142	$	4,650	$	(32,662	)	$	165,130

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

16

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Fair values related to the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap were transferred from Level 3 to Level 2 in the fourth quarter of 2011 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the three-month periods ended March 31, 2012 and 2011, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred. 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-month periods ended March 31, 2012 and 2011 (in thousands):

Three Months Ended March 31, 2012	Commodity Derivative Contracts
Balance of Level 3, December 31	$	(4,253	)
Total gain or losses (realized/unrealized)		2,032
Purchases		—
Settlements		(454	)
Balance of Level 3, March 31	$	(2,675	)

Three Months Ended March 31, 2011	Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, December 31	$	(205,860	)	$	(16,694	)	$	(222,554	)
Total gain or losses (realized/unrealized)		(277,628	)		(278	)		(277,906	)
Purchases		—			—			—
Settlements		4,947			2,043			6,990
Balance of Level 3, March 31	$	(478,541	)	$	(14,929	)	$	(493,470	)

See Note 9 for further discussion of the Company’s derivative contracts.

Fair Value of Debt

The Company measures the fair value of its senior notes based on inputs that are readily available in the public market as all of the Company’s senior notes outstanding as of March 31, 2012 are freely tradable. The Company classifies these inputs as Level 2 in the fair value hierarchy. The estimated fair values and carrying values of the Company’s senior notes at March 31, 2012 and December 31, 2011 were as follows (in thousands):

	March 31, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	346,980	$	350,000	$	339,381	$	350,000
9.875% Senior Notes due 2016(1)		396,568		355,078		396,568		354,579
8.0% Senior Notes due 2018		765,000		750,000		765,000		750,000
8.75% Senior Notes due 2020(2)		465,750		443,704		475,875		443,568
7.5% Senior Notes due 2021		886,500		900,000		909,000		900,000

(1) Carrying value is net of $10,422 and $10,921 discount at March 31, 2012 and December 31, 2011, respectively.

(2) Carrying value is net of $6,296 and $6,432 discount at March 31, 2012 and December 31, 2011, respectively.

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 8 for discussion of the Company’s long-term debt.

5. Property, Plant and Equipment

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

	March 31, 2012			December 31, 2011
Oil and natural gas properties
Proved	$	9,159,518		$	8,969,296
Unproved		748,953			689,393
Total oil and natural gas properties		9,908,471			9,658,689
Less accumulated depreciation, depletion and impairment		(4,874,325	)		(4,791,534	)
Net oil and natural gas properties capitalized costs		5,034,146			4,867,155
Land		15,723			14,196
Non oil and natural gas equipment(1)		705,202			668,391
Buildings and structures		152,237			133,147
Total		873,162			815,734
Less accumulated depreciation and amortization		(296,494	)		(293,465	)
Net capitalized costs		576,668			522,269
Total property, plant and equipment, net	$	5,610,814		$	5,389,424

(1) Includes cumulative capitalized interest of approximately $7.6 million and $6.7 million at March 31, 2012 and December 31, 2011, respectively.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

There were no full cost ceiling impairments during the three-month periods ended March 31, 2012 or 2011. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both March 31, 2012 and December 31, 2011 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the table above.

6. Other Assets

Other assets consist of the following (in thousands):

	March 31, 2012		December 31, 2011
Debt issuance costs, net of amortization	$	56,409	$	51,724
Lease broker advances		7,330		13,086
Production tax credit receivable		7,665		7,665
Investments		8,293		7,138
Development advance		—		16,777
Other		3,739		2,232
Total other assets	$	83,436	$	98,622

7. Construction Contracts

The Company accounts for its two construction contracts 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. 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 loss will be incurred. Contract gains, if any, are recorded at the end of the project.

Century Plant.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 mid-2012, and Phase II is under construction and expected to be completed in 2012. The Company has recorded an addition of $140.0 million ($10.0 million in the first quarter of 2012) to its oil and natural gas properties for the estimated loss identified based on current projections of the costs to be incurred in excess of contract amounts. Billings and estimated contract loss in excess of costs incurred of $34.3 million and $43.3 million at March 31, 2012 and December 31, 2011, respectively, are reported as current liabilities in the accompanying unaudited condensed consolidated balance sheets.

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 minimum CO₂ volumes annually once Occidental takes title, and will have to compensate Occidental to the extent such requirements are not met. See Note 11 for additional discussion of this volume requirement. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.

Transmission Expansion Projects. The Company entered into a construction services agreement in November 2011 to manage the design, engineering and construction of a series of transmission expansion and upgrade projects in northern Oklahoma. Under the terms of the agreement, the Company will be reimbursed for costs incurred on these projects up to approximately $22.0 million. Construction on these projects began in 2012 and is expected to be completed by the end of the year. Costs in excess of billings on these projects of $1.6 million at March 31, 2012 is reported as a current asset in the accompanying unaudited condensed consolidated balance sheets.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

8. Long-Term Debt

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

	March 31, 2012		December 31, 2011
Senior Floating Rate Notes due 2014	$	350,000	$	350,000
Senior credit facility		—		—
9.875% Senior Notes due 2016, net of $10,422 and $10,921 discount, respectively		355,078		354,579
8.0% Senior Notes due 2018		750,000		750,000
8.75% Senior Notes due 2020, net of $6,296 and $6,432 discount, respectively		443,704		443,568
7.5% Senior Notes due 2021		900,000		900,000
Mortgage		15,772		16,029
Total debt		2,814,554		2,814,176
Less: current maturities of long-term debt		1,070		1,051
Long-term debt	$	2,813,484	$	2,813,125

For the three-month periods ended March 31, 2012 and 2011, interest payments, excluding amounts capitalized, were approximately $57.2 million and $53.2 million, respectively. Interest payments for the three months ended March 31, 2011 included $24.1 million of accrued interest paid in connection with the partial redemption of the 8.625% Senior Notes due 2015, discussed further below.

Senior Floating Rate Notes Due 2014. The Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) were issued in May 2008. The Senior Floating Rate Notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 17 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 for the three-month periods ended March 31, 2012 and 2011 was 4.21% and 3.93%, 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.

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 to interest expense over the term of the notes.

As of March 31, 2012, the Company had a $350.0 million notional interest rate swap agreement to effectively fix the variable interest rate on the Senior Floating Rate Notes to an annual rate of 6.69% through April 1, 2013. This swap has not been designated as a hedge.

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 March 29, 2017, unless neither the Company’s Senior Floating Rate Notes nor the Company’s 9.875% Senior Notes due 2016 have been repaid or refinanced by September 30, 2015 with a source of funds other than the senior credit facility, in which case the senior credit facility will mature on November 15, 2015.

On March 29, 2012, the senior credit facility was amended and restated to, among other things, (a) increase the borrowing base to $1.0 billion from $790.0 million, (b) allow for the incurrence or issuance of additional debt (including up to $750.0 million of unsecured debt to finance the cash portion of the Dynamic purchase price and related costs and expenses), (c) permit the Company to designate certain of its subsidiaries as unrestricted subsidiaries, and (d) effective on and after June 30, 2012, establish the financial covenants as maintaining agreed upon levels for (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 and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total funded debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, 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.

19

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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. As of and during the three-month period ended March 31, 2012, the Company was in compliance with all applicable financial covenants under the senior credit facility.

The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of certain of the Company’s material present and future subsidiaries; certain 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 1.75% and 2.75% 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 0.75% and 1.75% 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 Company made no interest payments during the three-month period ended March 31, 2012 as there were no amounts outstanding under the senior credit facility during the period. The average annual interest rate paid on amounts outstanding under the senior credit facility was 2.73% for the three-month period ended March 31, 2011.

Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. The Company’s borrowing base is redetermined in April and October of each year. As a result of the amendment and restatement of the senior credit facility in March 2012, the next borrowing base redetermination will be in October 2012. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. The Company 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 three-month period ended March 31, 2012, additional costs of approximately $7.2 million were incurred. These costs have been deferred, are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the senior credit facility.

At March 31, 2012, the Company had no amount outstanding under the senior credit facility and $28.7 million in outstanding letters of credit, which reduce the availability under the senior credit facility on a dollar-for-dollar basis.

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. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $36.2 million, were recorded as a loss on extinguishment of debt in the accompanying unaudited condensed consolidated statement of operations for the three-month period ended March 31, 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.

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 to 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, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable.

20

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 to interest expense 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, in full, 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 to interest expense 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 being amortized to 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, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 17 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $9.7 million incurred in connection with the offering 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 to interest expense 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 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, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries. See Note 17 for condensed financial information of the subsidiary guarantors.

In November 2011, pursuant to an exchange offer, the Company replaced a substantial majority of the 7.5% Senior Notes, which were issued under Rule 144A and Regulation S under the Securities Act, with 7.5% Senior Notes registered under the Securities Act. The exchange offer did not result in the incurrence of any additional indebtedness.

Debt issuance costs of $19.4 million incurred in connection with the offering and subsequent exchange of the 7.5% Senior Notes are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense 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 during the three-month period ended March 31, 2012, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

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.

21

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 of $0.5 million are due on a quarterly basis through the maturity date.

9. Derivatives

The Company has not designated any of its derivative contracts as hedges for accounting purposes. 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 statements of operations. Commodity derivative contracts are settled on a monthly or quarterly 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 sheets.

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to commodity price volatility on 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 in its operations. None of the Company’s derivative contracts may be terminated early as a result of a party to the contract having its credit rating downgraded. At March 31, 2012, 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.

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 that effectively converts the variable interest rate on its Senior Floating Rate Notes to a fixed rate through April 1, 2013. See Note 8 for further discussion of the Company’s interest rate swap.

Royalty Trust Derivatives Agreements. Effective April 1, 2011, the Company entered into a derivatives agreement with the Mississippian Trust I. The agreement provides the Mississippian Trust I 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 I amounts it receives from its counterparties in accordance with the underlying contracts, and the Mississippian Trust I will pay the Company any amounts that the Company is required to pay its counterparties under such contracts.

Effective August 1, 2011, the Company entered into a derivatives agreement with the Permian Trust. The agreement provides the Permian Trust with the economic effect of certain oil derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil production through March 31, 2015. Under this arrangement, the Company will pay the Permian Trust amounts it receives from its counterparty in accordance with the underlying contracts, and the Permian Trust will pay the Company any amounts that the Company is required to pay its counterparty undersuch 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

22

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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. 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.

All contracts underlying the derivatives agreements with the Mississippian Trust I and Permian Trust, including those novated to the Permian Trust, have been included in the Company’s consolidated derivative disclosures. See Note 3 for further discussion of the Mississippian Trust I and the Permian Trust.

Fair Value of Derivatives. The following table presents the fair value of the Company’s derivative contracts as of March 31, 2012 and December 31, 2011 on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract	Balance Sheet Classification	March 31, 2012			December 31, 2011
Derivative assets
Oil price swaps	Derivative contracts-current	$	1,836		$	6,095
Natural gas price swaps	Derivative contracts-current		4,886			6,585
Natural gas collars	Derivative contracts-current		735			313
Diesel price swaps	Derivative contracts-current		2,273			397
Oil price swaps	Derivative contracts-noncurrent		15,485			48,718
Natural gas collars	Derivative contracts-noncurrent		1,519			1,035
Derivative liabilities
Oil price swaps	Derivative contracts-current		(89,408	)		(116,243	)
Natural gas basis swaps	Derivative contracts-current		(1,164	)		—
Diesel price swaps	Derivative contracts-current		—			(41	)
Interest rate swaps	Derivative contracts-current		(9,094	)		(8,475	)
Oil price swaps	Derivative contracts-noncurrent		(304,221	)		(66,451	)
Natural gas basis swaps	Derivative contracts-noncurrent		(3,784	)		(4,609	)
Interest rate swaps	Derivative contracts-noncurrent		—			(1,973	)
Total net derivative contracts		$	(380,937	)	$	(134,649	)

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

The following table summarizes the effect of the Company’s derivative contracts on the accompanying unaudited condensed consolidated statements of operations for the three-month periods ended March 31, 2012 and 2011 (in thousands):

		Three Months Ended
	Location of Loss Recognized in Income	March 31,
Type of Contract		2012		2011
Commodity derivatives	Loss on derivative contracts	$	254,646	$	277,628
Interest rate swaps	Interest expense		846		278
Total		$	255,492	$	277,906

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-month periods ended March 31, 2012 and 2011 (in thousands):

	Three Months Ended March 31,
	2012			2011
Commodity Derivatives
Realized loss(1)	$	125,456		$	8,609
Unrealized loss		129,190			269,019
Loss on commodity derivative contracts	$	254,646		$	277,628
Interest Rate Swaps
Realized loss	$	2,200		$	2,043
Unrealized gain		(1,354	)		(1,765	)
Loss on interest rate swaps	$	846		$	278

(1) The three-month period ended March 31, 2012 includes $117.1 million non-cash realized losses on derivative contracts amended in January 2012. The three-month period ended March 31, 2011 includes $12.4 million of realized gains related to settlements of commodity derivative contracts with contractual maturities after March 31, 2011.

23

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

At March 31, 2012, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbl)		Weighted Avg. Fixed Price
April 2012 — December 2012		11,597	$	100.40
January 2013 — December 2013		16,320	$	95.95
January 2014 — December 2014		13,914	$	89.95
January 2015 — December 2015		7,635	$	84.77

Natural Gas Price Swaps

	Notional (MMBtu)		Weighted Avg. Fixed Price
April 2012 — June 2012		1,820	$	4.90

Natural Gas Basis Swaps

	Notional (MMBtu)		Weighted Avg. Fixed Price
January 2013 — December 2013		14,600	$	(0.46	)

Natural Gas Collars

	Notional (MMBtu)		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

Diesel Price Swaps

	Notional (Thousands of Gallons)		Weighted Avg. Fixed Price
April 2012 — December 2012		4,536	$	2.82

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, 2011 to March 31, 2012 is as follows (in thousands):

Asset retirement obligation, December 31, 2011	$	128,116
Liability incurred upon acquiring and drilling wells		1,377
Revisions in estimated cash flows		1,308
Liability settled or disposed in current period		(376	)
Accretion of discount expense		2,607
Asset retirement obligation, March 31, 2012		133,032
Less: current portion		32,906
Asset retirement obligation, net of current	$	100,126

11. Commitments and Contingencies

Legal Proceedings

The Company is a defendant in lawsuits from time to time in the normal course of business. While the results of litigation and claims cannot be predicted with certainty, the Company believes the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, the Company believes the probable final outcome of such matters will not have a material adverse effect on the Company’s consolidated results of operations, financial position, cash flows or liquidity.

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

24

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 is approximately $12.3 million. As the loss is not probable, 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 Aspen’s construction 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, LLC as plaintiffs. The plaintiffs’ amended claims seek damages relating to the construction of the pipeline and performance under a related gas purchase agreement, which damages are alleged to 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, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP 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 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 natural 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 associated with these claims, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. 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 associated with the demand for indemnity is approximately $4.0 million. As the loss is not probable, 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. 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, the “defendants”) in the U.S. District Court for the District of Connecticut. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and the 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 the plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, the plaintiffs have invested approximately $15.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this claim.

25

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Treating Agreement Commitment

In conjunction with the Century Plant construction agreement, the Company entered into a 30-year treating agreement with Occidental for CO₂ to be removed from the Company’s delivered production volumes. The Company is required to deliver a total of approximately 3,200 Bcf of CO₂volumes during the agreement period. If the Company does not meet the CO₂volume requirements, the Company will have to pay a fee for any volume shortfalls. Based upon current natural gas production levels, the Company expects to accrue between approximately $15.5 million and $19.0 million during the year ending December 31, 2012 for amounts related to the Company’s shortfall in meeting its delivery obligations based on the projected completion date of Phase I. Due to the sensitivity of natural gas production to prevailing market prices, the Company is unable to estimate additional amounts it may be required to pay under this agreement in subsequent periods.

12. Equity

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

	March 31, 2012		December 31, 2011
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 are designated as convertible perpetual preferred stock at March 31, 2012. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions and none of these shares is listed on a stock exchange. However, all of the outstanding shares of convertible perpetual preferred stock are freely tradable.

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, subject to customary adjustments in certain circumstances. 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 ($2.8 million paid and $2.8 million unpaid) and $5.6 million ($3.7 million paid and $1.9 million unpaid) in dividends on the 8.5% convertible perpetual preferred stock have been included in the calculation of loss applicable to the Company’s common stockholders and the Company’s basic loss per share calculation for the three-month periods ended March 31, 2012 and 2011, 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 $3.0 million ($1.0 million paid and $2.0 million unpaid) in dividends on the 6.0% convertible perpetual preferred stock have been included in the calculation of loss applicable to the Company’s common stockholders and the Company’s basic loss per share calculation for the three-month periods ended March 31, 2012 and 2011, 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, subject to customary adjustments in certain circumstances. After December 21, 2014, the Company may cause all outstanding shares of the 6.0% convertible preferred stock to convert 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, subject to customary adjustments in certain circumstances. 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 in dividends (all unpaid) on the 7.0% convertible perpetual preferred stock have been included in the calculation of loss applicable to the Company’s common stockholders and the Company’s basic

26

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

loss per share calculation for both of the three-month periods ended March 31, 2012 and 2011 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):

	March 31, 2012		December 31, 2011
Shares authorized		800,000		800,000
Shares outstanding at end of period		415,544		411,953
Shares held in treasury		934		874

Treasury Stock. The Company makes required statutory 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 777,000 shares having a total value of $6.4 million and 603,000 shares having a total value of $4.8 million during the three-month periods ended March 31, 2012 and 2011, 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 report. For corporate purposes and for purposes of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Equity Compensation. The Company awards restricted common stock under incentive compensation plans that vest over specified periods of time, subject to certain conditions and are valued based upon the market value of common stock on the date of grant. Awards issued prior to 2006 had vesting periods of one, four or seven years. Awards issued during and after 2006 generally 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.

Equity compensation provided to employees directly involved in oil and natural gas exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is reflected in general and administrative expenses, production expenses, midstream and marketing expenses and drilling and services expenses in the consolidated statements of operations. For the three-month periods ended March 31, 2012 and 2011, the Company recognized equity compensation expense of $10.5 million and $8.2 million, net of $1.9 million and $1.8 million capitalized, respectively, related to restricted common stock.

Noncontrolling Interest. Noncontrolling interests in the Company’s subsidiaries and four VIEs of which the Company was the primary beneficiary as of and for the three-month period ended March 31, 2012 (see Note 3), represent third-party ownership interests in the consolidated entity and are included as a component of equity in the unaudited condensed consolidated balance sheet and unaudited condensed consolidated statements of changes in equity.

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 (benefit) provision for income taxes consisted of the following components for the three-month periods ended March 31, 2012 and 2011 (in thousands):

	Three Months Ended March 31,
	2012			2011
Current
Federal	$	(83	)	$	21
State		154			67
		71			88
Deferred
Federal		—			—
State		—			—
		—			—
Total provision		71			88
Less: income tax provision attributable to noncontrolling interest		90			2
Total (benefit) provision attributable to SandRidge Energy, Inc.	$	(19	)	$	86

27

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 when a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. As of December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. The Company continued to have a full valuation allowance against its net deferred tax asset at March 31, 2012.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected 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 acquisition of Arena Resources, Inc. (“Arena”). The subsequent ownership change resulted in a more restrictive limitation on certain of the Company’s tax attributes than with the December 31, 2008 ownership change. The more restrictive limitation applies 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 net operating losses of approximately $554.3 million and certain other tax attributes generated in periods following the December 31, 2008 ownership change. The subsequent limitation could result in a material amount of existing loss carryforwards expiring unused. Arena also experienced an ownership change on July 16, 2010 as a result of its acquisition by the Company. This ownership change resulted in a limitation on Arena’s net operating loss carryforwards of $119.9 million available to the Company. None of the limitations discussed above resulted in a current federal tax liability at March 31, 2012 or December 31, 2011.

At March 31, 2012 and December 31, 2011, the Company had a liability of approximately $1.8 million for unrecognized tax benefits. If recognized, approximately $1.2 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate.

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 $0.05 million of accrued gross interest with respect to unrecognized tax benefits in the accompanying unaudited condensed consolidated statements of operations during the three-month periods ended March 31, 2012 and 2011, respectively. The Company had a corresponding accrued liability of $0.2 million for interest and penalties relating to uncertain tax positions at March 31, 2012 and December 31, 2011.

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. As a result of ongoing negotiations pertaining to the Company’s current state audits, it is reasonably possible that the Company’s gross unrecognized tax benefits balance may decrease within the next twelve months by approximately $1.6 million.

For the three-month period ended March 31, 2012, income tax refunds were approximately $0.1 million. Income tax payments, net of refunds, were approximately $1.0 million for the corresponding period in 2011.

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, using the treasury stock method, and outstanding convertible preferred stock. Under the treasury stock method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants are assumed to be used to repurchase shares. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the three-month periods ended March 31, 2012 and 2011 (in thousands):

	Three Months Ended March 31,
	2012		2011
Weighted average basic common shares outstanding		400,597		398,251
Effect of dilutive securities
Restricted stock		—		—
Convertible preferred stock		—		—
Weighted average diluted common and potential common shares outstanding		400,597		398,251

28

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

For the three-month periods ended March 31, 2012 and 2011, restricted stock awards covering 9.4 million shares and 7.2 million shares, respectively, were excluded from the computation of loss per share because their effect would have been antidilutive.

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock, 6.0% convertible perpetual preferred stock and 7.0% convertible perpetual preferred stock for the three-month periods ended March 31, 2012 and 2011. 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 (loss applicable) to common stockholders. For the three-month periods ended March 31, 2012 and 2011, the Company determined the if-converted method was not more dilutive and included the 8.5%, 6.0% and 7.0% preferred stock dividends in the determination of loss applicable to common stockholders.

15. 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. During the three-month periods ended March 31, 2012 and 2011, the Company had sales to related parties of $3.7 million and $4.8 million, respectively. At March 31, 2012 and December 31, 2011, the Company had accounts receivable due from related parties of $1.9 million and $1.6 million, respectively. These amounts primarily relate to sales of natural gas to Southern Union, the Company’s partner in GRLP.

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 basketball team. 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. At March 31, 2012 and December 31, 2011, the Company had no amounts due under these agreements.

16. 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 and includes the activities of the Mississippian Trust I and the Permian Trust. 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.

29

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, amortization and accretion. Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended March 31, 2012
Revenues	$	343,120		$	98,332		$	26,162		$	1,406		$	469,020
Inter-segment revenue		(77	)		(69,023	)		(18,295	)		10			(87,385	)
Total revenues	$	343,043		$	29,309		$	7,867		$	1,416		$	381,635
(Loss) income from operations	$	(123,836	)	$	3,479		$	(2,727	)	$	(28,572	)	$	(151,656	)
Interest income (expense), net		143			—			(156	)		(66,952	)		(66,965	)
Other income, net		1,768			—			—			700			2,468
(Loss) income before income taxes	$	(121,925	)	$	3,479		$	(2,883	)	$	(94,824	)	$	(216,153	)
Capital expenditures(1)	$	491,905		$	7,916		$	23,975		$	45,862		$	569,658
Depreciation, depletion, amortization and accretion	$	90,052		$	8,550		$	1,411		$	4,173		$	104,186
At March 31, 2012
Total assets	$	5,516,169		$	226,233		$	161,095		$	474,602		$	6,378,099
Three Months Ended March 31, 2011
Revenues	$	267,237		$	67,549		$	55,978		$	3,220		$	393,984
Inter-segment revenue		(67	)		(46,515	)		(34,038	)		(516	)		(81,136	)
Total revenues	$	267,170		$	21,034		$	21,940		$	2,704		$	312,848
Loss from operations(2)	$	(184,207	)	$	(108	)	$	(2,528	)	$	(20,985	)	$	(207,828	)
Interest income (expense), net		105			(105	)		(172	)		(59,266	)		(59,438	)
Loss on extinguishment of debt		—			—			—			(36,181	)		(36,181	)
Other income (expense), net		1,676			—			(701	)		222			1,197
Loss before income taxes	$	(182,426	)	$	(213	)	$	(3,401	)	$	(116,210	)	$	(302,250	)
Capital expenditures(1)	$	399,096		$	6,763		$	4,172		$	6,138		$	416,169
Depreciation, depletion, amortization and accretion	$	74,472		$	7,730		$	1,097		$	3,680		$	86,979
At December 31, 2011
Total assets	$	5,345,527		$	219,101		$	138,844		$	516,137		$	6,219,609

(1) On an accrual basis.

(2) Exploration and production segment (loss) income from operations includes net losses of $254.6 million and $277.6 million on commodity derivative contracts for the three-month periods ended March 31, 2012 and 2011, respectively.

17. 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, on a full, unconditional and unsecured basis, the Company’s Senior Floating Rate Notes, 8.75% Senior Notes and 7.5% Senior Notes as of March 31, 2012. Prior to their purchase and redemption, the 8.625% Senior Notes were also jointly and severally guaranteed, on a full, unconditional and 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; (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors; and (v) are only released under certain customary circumstances. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes.

The following unaudited 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.

30

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Condensed Consolidating Balance Sheets

	March 31, 2012
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	123,755	$	289	$	3,798	$	—		$	127,842
Accounts receivable, net		1,270,409		263,679		606,870		(1,900,322	)		240,636
Derivative contracts		—		9,236		3,250		(4,960	)		7,526
Other current assets		—		32,178		11,258		—			43,436
Total current assets		1,394,164		305,382		625,176		(1,905,282	)		419,440
Property, plant and equipment, net		—		4,674,871		935,943		—			5,610,814
Investment in subsidiaries		3,514,717		27,482		—		(3,542,199	)		—
Derivative contracts		—		24		9,703		(8,618	)		1,109
Goodwill		—		235,396		—		—			235,396
Other assets		56,409		54,931		—		—			111,340
Total assets	$	4,965,290	$	5,298,086	$	1,570,822	$	(5,456,099	)	$	6,378,099
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	696,324	$	1,212,872	$	590,779	$	(1,898,190	)	$	601,785
Derivative contracts		9,094		90,600		2,728		(4,960	)		97,462
Asset retirement obligation		—		32,906		—		—			32,906
Other current liabilities		—		34,310		1,070		—			35,380
Total current liabilities		705,418		1,370,688		594,577		(1,903,150	)		767,533
Long-term debt		2,798,783		—		14,701		—			2,813,484
Derivative contracts		—		300,728		—		(8,618	)		292,110
Asset retirement obligation		—		99,941		185		—			100,126
Other long-term obligations		1,774		12,013		—		—			13,787
Total liabilities		3,505,975		1,783,370		609,463		(1,911,768	)		3,987,040
Equity
SandRidge Energy, Inc. stockholders’ equity		1,459,315		3,514,716		961,359		(4,478,207	)		1,457,183
Noncontrolling interest		—		—		—		933,876			933,876
Total equity		1,459,315		3,514,716		961,359		(3,544,331	)		2,391,059
Total liabilities and equity	$	4,965,290	$	5,298,086	$	1,570,822	$	(5,456,099	)	$	6,378,099

	December 31, 2011
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	204,015	$	437	$	3,229	$	—		$	207,681
Accounts receivable, net		1,217,096		247,824		602,541		(1,861,125	)		206,336
Derivative contracts		—		2,567		10,368		(8,869	)		4,066
Other current assets		—		16,063		7,694		—			23,757
Total current assets		1,421,111		266,891		623,832		(1,869,994	)		441,840
Property, plant and equipment, net		—		4,462,846		926,578		—			5,389,424
Investment in subsidiaries		3,609,244		90,920		—		(3,700,164	)		—
Derivative contracts		—		20,746		35,774		(30,105	)		26,415
Goodwill		—		235,396		—		—			235,396
Other assets		51,724		74,760		50		—			126,534
Total assets	$	5,082,079	$	5,151,559	$	1,586,234	$	(5,600,263	)	$	6,219,609
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	643,376	$	1,166,029	$	556,165	$	(1,858,786	)	$	506,784
Derivative contracts		8,475		115,829		—		(8,869	)		115,435
Asset retirement obligation		—		32,906		—		—			32,906
Other current liabilities		—		43,320		1,051		—			44,371
Total current liabilities		651,851		1,358,084		557,216		(1,867,655	)		699,496
Long-term debt		2,798,147		—		14,978		—			2,813,125
Derivative contracts		1,973		77,827		—		(30,105	)		49,695
Asset retirement obligation		—		95,029		181		—			95,210
Other long-term obligations		1,758		11,375		—		—			13,133
Total liabilities		3,453,729		1,542,315		572,375		(1,897,760	)		3,670,659
Equity
SandRidge Energy, Inc. stockholders’ equity		1,628,350		3,609,244		1,013,859		(4,625,442	)		1,626,011
Noncontrolling interest		—		—		—		922,939			922,939
Total equity		1,628,350		3,609,244		1,013,859		(3,702,503	)		2,548,950
Total liabilities and equity	$	5,082,079	$	5,151,559	$	1,586,234	$	(5,600,263	)	$	6,219,609

31

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2012
Total revenues	$	—		$	322,226		$	91,193		$	(31,784	)	$	381,635
Expenses
Direct operating expenses		—			114,066			41,752			(31,660	)		124,158
General and administrative		86			48,113			2,433			(331	)		50,301
Depreciation, depletion, amortization, accretion and impairment		—			90,917			13,269			—			104,186
Loss on derivative contracts		—			220,935			33,711			—			254,646
Total expenses		86			474,031			91,165			(31,991	)		533,291
(Loss) income from operations		(86	)		(151,805	)		28			207			(151,656	)
Equity earnings from subsidiaries		(94,527	)		(2,303	)		—			96,830			—
Interest expense		(66,706	)		(13	)		(246	)		—			(66,965	)
Other income, net		—			59,594			—			(57,126	)		2,468
Loss before income taxes		(161,319	)		(94,527	)		(218	)		39,911			(216,153	)
Income tax (benefit) expense		(60	)		—			131			—			71
Net loss		(161,259	)		(94,527	)		(349	)		39,911			(216,224	)
Less: net income attributable to noncontrolling interest		—			—			—			1,954			1,954
Net loss attributable to SandRidge Energy, Inc.	$	(161,259	)	$	(94,527	)	$	(349	)	$	37,957		$	(218,178	)
Three Months Ended March 31, 2011
Total revenues	$	—		$	309,296		$	14,481		$	(10,929	)	$	312,848
Expenses
Direct operating expenses		—			119,226			13,212			(10,783	)		121,655
General and administrative		85			33,734			741			(146	)		34,414
Depreciation, depletion, amortization, accretion and impairment		—			85,240			1,739			—			86,979
Loss on derivative contracts		—			277,628			—			—			277,628
Total expenses		85			515,828			15,692			(10,929	)		520,676
Loss from operations		(85	)		(206,532	)		(1,211	)		—			(207,828	)
Equity earnings from subsidiaries		(206,987	)		(1,231	)		—			208,218			—
Interest expense		(59,007	)		(173	)		(258	)		—			(59,438	)
Loss on extinguishment of debt		(36,181	)		—			—			—			(36,181	)
Other income, net		—			955			242			—			1,197
Loss before income taxes		(302,260	)		(206,981	)		(1,227	)		208,218			(302,250	)
Income tax expense		84			—			4			—			88
Net loss		(302,344	)		(206,981	)		(1,231	)		208,218			(302,338	)
Less: net income attributable to noncontrolling interest		—			—			—			6			6
Net loss attributable to SandRidge Energy, Inc.	$	(302,344	)	$	(206,981	)	$	(1,231	)	$	208,212		$	(302,344	)

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2012
Net cash (used in) provided by operating activities	$	(48,637	)	$	202,554		$	78,163		$	(1,170	)	$	230,910
Net cash used in investing activities		—			(196,607	)		(79,567	)		(67,170	)		(343,344	)
Net cash (used in) provided by financing activities		(31,623	)		(6,095	)		1,973			68,340			32,595
Net (decrease) increase in cash and cash equivalents		(80,260	)		(148	)		569			—			(79,839	)
Cash and cash equivalents at beginning of year		204,015			437			3,229			—			207,681
Cash and cash equivalents at end of period	$	123,755		$	289		$	3,798		$	—		$	127,842
Three Months Ended March 31, 2011
Net cash (used in) provided by operating activities	$	(198,288	)	$	274,236		$	3,714		$	—		$	79,662
Net cash used in investing activities		—			(269,126	)		(278	)		1			(269,403	)
Net cash provided by (used in) financing activities		197,649			(4,988	)		(245	)		(1	)		192,415
Net (decrease) increase in cash and cash equivalents		(639	)		122			3,191			—			2,674
Cash and cash equivalents at beginning of year		1,441			564			3,858			—			5,863
Cash and cash equivalents at end of period	$	802		$	686		$	7,049		$	—		$	8,537

32

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

18. Subsequent Events

Dynamic Acquisition. On April 17, 2012, the Company completed its acquisition of Dynamic (“Dynamic Acquisition”) for approximately $1.2 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of the Company’s common stock. On April 18, 2012, the Company filed a shelf registration statement with the Securities and Exchange Commission to register the resale of the shares of common stock issued as consideration in the Dynamic Acquisition. Dynamic is an oil and natural gas exploration, development and production company with operations in the Gulf of Mexico.

The following allocation of the purchase price as of April 17, 2012, is preliminary and includes significant use of estimates. This preliminary allocation is based on information that was available to management at the time these unaudited condensed consolidated financial statements were prepared. Management has not yet had the opportunity to complete its assessment of the fair values of the assets acquired and liabilities assumed. Accordingly, the allocation will change as additional information becomes available and is assessed by the Company, and the impact of such changes may be significant. Additionally, the Company will monitor the need to adjust the Company’s valuation allowance on its deferred tax asset as the allocation is finalized and the full impact of the acquisition is determined.

The following table summarizes the estimated values of assets acquired, the liabilities assumed and the resulting bargain purchase gain based on the preliminary estimates of fair value (in thousands, except stock price):

Consideration(1)
Shares of SandRidge common stock issued		73,962
SandRidge common stock price	$	7.33
Fair value of common stock issued		542,138
Cash consideration(2)		680,000
Cash balance adjustment(3)		13,091
Total purchase price	$	1,235,229
Estimated Fair Value of Liabilities Assumed
Current liabilities	$	136,494
Asset retirement obligation(4)		316,183
Long-term deferred tax liability(5)		71,706
Other non-current liabilities		3,627
Amount attributable to liabilities assumed		528,010
Total purchase price plus liabilities assumed		1,763,239
Estimated Fair Value of Assets Acquired
Current assets		125,568
Oil and natural gas properties(6)		1,685,836
Other property, plant and equipment		1,342
Other non-current assets		17,853
Amount attributable to assets acquired		1,830,599
Bargain purchase gain(7)	$	(67,360	)

(1) Consideration paid by SandRidge consists of 73,961,554 shares of SandRidge common stock and cash of approximately $680.0 million. The value of the stock consideration is based upon the closing price of $7.33 per share of SandRidge common stock on April 17, 2012 (the closing date of the acquisition). Under the acquisition method of accounting, the purchase price is determined based on the total cash paid and the fair value of SandRidge common stock issued on the acquisition date.

(2) Cash paid to Dynamic, including amounts paid to retire Dynamic’s long-term debt, was funded through a portion of the net proceeds from the Company’s issuance of $750.0 million of unsecured 8.125% Senior Notes due 2022 (the “8.125% Senior Notes”).

(3) In accordance with the Equity Purchase Agreement, the Company remitted to the seller a cash payment equal to the Dynamic average daily cash balance for the 30-day period ending on the second day prior to closing. This resulted in an additional cash payment by SandRidge of $13.1 million at closing.

(4) The estimated fair value of the acquired asset retirement obligation was determined using SandRidge’s applicable discount rate.

(5) The deferred tax liability is a result of the difference between the estimated fair value and the Company’s expected tax basis in the assets acquired and liabilities assumed.

(6) The fair value of oil and natural gas properties acquired was estimated using a discounted cash flow model, with future cash flows estimated based upon estimated oil and natural gas reserve quantities and forward strip oil and natural gas prices as of April 17, 2012, discounted to present value using SandRidge’s risk weighted assessments for proved, probable and possible reserves and a weighted average cost of capital. The actual fair value of oil and natural gas properties may differ from this estimate based upon the Company’s additional evaluation of Dynamic’s reserves.

33

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

(7) The bargain purchase gain results from the excess of the net assets acquired over the consideration paid. The fair value of the acquired assets and assumed liabilities is ongoing and will be updated as additional information becomes available. As such, the bargain purchase gain is subject to adjustment.

The following unaudited pro forma results of operations are provided for the three-month periods ended March 31, 2012 and March 31, 2011 as though the Dynamic Acquisition had been completed as of the beginning of the earliest period presented, or January 1, 2011. The pro forma combined results of operations for the three-month periods ended March 31, 2012 and 2011 have been prepared by adjusting the historical results of the Company to include the historical results of Dynamic, certain reclassifications to conform Dynamic’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, or will result, from the acquisition or any estimated costs that will be incurred to integrate Dynamic. 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 March 31,
	2012(1)			2011(2)
	(In thousands, except per share data)
Revenues	$	526,797		$	413,185
Loss applicable to SandRidge Energy, Inc. common stockholders	$	(196,119	)	$	(220,719	)
Pro forma net loss per common share
Basic	$	(0.41	)	$	(0.47	)
Diluted	$	(0.41	)	$	(0.47	)

(1) Pro forma loss applicable to SandRidge Energy, Inc, common stockholders and net loss per common share include the reversal of $2.5 million of transaction costs incurred and included in general and administrative expenses and $10.9 million of fees incurred to secure financing for the Dynamic Acquisition and included in interest expense in the accompanying unaudited condensed consolidated statement of operations for the three months ended March 31, 2012.

(2) Pro forma loss applicable to SandRidge Energy, Inc, common stockholders and net loss per common share include a $67.4 million bargain purchase gain, as discussed above, $13.0 million of estimated transaction costs, $10.9 million of fees to secure financing for the Dynamic Acquisition and a partial valuation allowance release of $71.7 million.

Issuance of 8.125% Senior Notes due 2022.On April 17, 2012, concurrent with the closing of the Dynamic Acquisition, the Company issued the 8.125% 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 $730.7 million after deducting offering expenses, and were used to finance the cash portion of the Dynamic Acquisition and to pay related fees and expenses, with any remaining amount being used for general corporate purposes. The 8.125% Senior Notes bear interest at a fixed rate of 8.125% per annum, payable semi-annually, with the principal due on October 15, 2022. Prior to 2017, the 8.125% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. The notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries.

In conjunction with the issuance of the 8.125% Senior Notes, the Company entered into a registration rights agreement requiring the Company to commence a registered exchange offer for these notes no later than April 17, 2013. Under certain circumstances, in lieu of a registered exchange offer, the Company may be required to file a shelf registration statement relating to the resale of the 8.125% Senior Notes and to use its commercially reasonable best efforts to keep such registration statement effective until two years after its effective date (or such shorter period that will terminate when all of the 8.125% Senior Notes covered thereby have been sold pursuant thereto or in certain other circumstances). The Company is required to pay additional interest if it fails to fulfill its obligations under the agreement within the specified time periods.

SandRidge Mississippian Trust II. On April 23, 2012, the Mississippian Trust II, a newly formed Delaware statutory trust, completed its initial public offering of 29,900,000 common units representing beneficial interests in the Mississippian Trust II. Net proceeds to the Mississippian Trust II, after underwriting discounts and commissions, were approximately $590.0 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust II in exchange for the net proceeds of the Mississippian Trust II’s initial public offering and 19,825,000 units (7,393,750, common units and 12,431,250, subordinated units) representing approximately 39.9% of the beneficial interest in the Mississippian Trust II. The royalty interests conveyed to the Mississippian Trust II are in certain existing wells and wells to be drilled on certain oil and natural gas properties leased by the Company in the Mississippian formation in northern Oklahoma and southern Kansas. As the Mississippian Trust II is a VIE of which SandRidge has determined it is the primary beneficiary, its activities will be consolidated with those of the Company beginning in April 2012.

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust II that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to a royalty interest, by December 31, 2016. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust II a lien on the

34

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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. The maximum amount available under the lien is $269.1 million. Additionally, the Company and the Mississippian Trust II entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Mississippian Trust II, including hedge management services, and a derivatives agreement, effective April 1, 2012, pursuant to which the Company provides to the Mississippian Trust II 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 Mississippian Trust II. The tables below present the open contracts underlying the derivatives agreement, including the contracts novated to the Mississippian Trust II, as of April 1, 2012. The combined volume in the tables below reflects the total volume of the Mississippian Trust II’s oil derivative contracts.

Oil Price Swaps Underlying the Derivatives Agreement

	Notional (MBbl)		Weighted Avg. Fixed Price
April 2012 — December 2012		230	$	107.00
January 2013 — December 2013		612	$	104.00
January 2014 — December 2014		562	$	99.00

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

	Notional (MBbl)		Weighted Avg. Fixed Price
April 2012 — December 2012		458	$	107.00
January 2013 — December 2013		446	$	104.00
January 2014 — December 2014		338	$	99.00

Royalty Trust Distributions. On April 30, 2012, the Mississippian Trust I, the Permian Trust and the Mississippian Trust II announced quarterly distributions for the three-month period ended March 31, 2012 of $22.0 million, or $0.79 per unit, $30.5 million, or $0.58 per unit, and $13.3 million, or $0.27 per unit, respectively. Of these distribution amounts, $14.8 million, $21.2 million and $8.0 million will be distributed to third-party unitholders of the Mississippian Trust I, the Permian Trust and the Mississippian Trust II, respectively. The distributions are expected to occur on or before May 30, 2012 to holders of record as of the close of business on May 15, 2012.

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 2011 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; and

• Liquidity and Capital Resources.

The financial information with respect to the three-month periods ended March 31, 2012 and 2011, 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 its significant holdings in the Mid-Continent area of Oklahoma and Kansas, west Texas and the Gulf of Mexico. The Company’s primary areas of focus are the Mississippian formation in the Mid-Continent and the Permian Basin in west Texas. The Company also owns and operates other interests in the Mid-Continent, WTO and the Gulf Coast.

The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and gas marketing business and an oil field services business. These complementary businesses provide the Company with operational flexibility and an advantageous cost structure by reducing the Company’s dependence on third parties for these services. 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.

Recent Developments

Sale of Working Interest in Mississippian Properties.On January 5, 2012, the Company sold (i) non-operated working interests, equal to approximately 250,000 net acres, in the Mississippian formation in western Kansas and (ii) non-operated working interests, equal to approximately 114,000 net acres, and a proportionate share of existing salt water disposal facilities in the Mississippian formation in northern Oklahoma and southern Kansas to Repsol for approximately $250.0 million. In addition, Repsol agreed to pay the development costs related to its working interest, as well as a portion of the Company’s development costs equal to 200% of Repsol’s working interest for wells within an area of mutual interest up to $750.0 million. The Company expects Repsol’s funding of the Company’s development cost for wells within the area of mutual interest to occur over a three-year period.

Senior Credit Facility Amendment.On March 29, 2012, the senior credit facility was amended and restated to, among other things, (a) increase the borrowing base to $1.0 billion from $790.0 million, (b) allow for the incurrence or issuance of additional debt (including up to $750.0 million of unsecured debt to finance the cash portion of the Dynamic purchase price and related costs and expenses), (c) permit the Company to designate certain of its subsidiaries as unrestricted subsidiaries, and (d) effective on and after June 30, 2012, establish the financial covenants as maintaining agreed upon levels for (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 and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total funded debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, 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.

36

Dynamic Acquisition. On April 17, 2012, the Company completed its acquisition of Dynamic for approximately $1.2 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of the Company’s common stock.

Issuance of 8.125% Senior Notes due 2022.On April 17, 2012, concurrent with the closing of the Dynamic Acquisition, the Company issued $750.0 million of unsecured 8.125% 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 $730.7 million after deducting offering expenses, and were used to finance the cash portion of the Dynamic purchase price and to pay related fees and expenses, with any remaining amount being used for general corporate purposes. The 8.125% Senior Notes bear interest at a fixed rate of 8.125% per annum, payable semi-annually, with the principal due on October 15, 2022. Prior to 2017, the 8.125% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. The notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries.

SandRidge Mississippian Trust II. On April 23, 2012, the Mississippian Trust II, a newly formed Delaware statutory trust, completed its initial public offering of 29,900,000 common units representing beneficial interests in the Mississippian Trust II. Net proceeds to the Mississippian Trust II, after underwriting discounts and commissions, were approximately $590.0 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust II in exchange for the net proceeds of the Mississippian Trust II’s initial public offering and 19,825,000 units (7,393,750 common units and 12,431,250 subordinated units) representing approximately 39.9% of the beneficial interest in the Mississippian Trust II. The royalty interests conveyed to the Mississippian Trust II are in certain existing wells and wells to be drilled on certain oil and natural gas properties leased by the Company in the Mississippian formation in northern Oklahoma and southern Kansas. The Company intends to use the net proceeds from the offering for general corporate purposes, including to fund its 2012 capital expenditure program.

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust II that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to a royalty interest, by December 31, 2016. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust II a lien on 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. Additionally, the Company and the Mississippian Trust II entered into an administrative services agreement and a derivatives agreement. As the Mississippian Trust II is a VIE of which the Company has determined it is the primary beneficiary, its activities will be consolidated with those of the Company beginning in April 2012.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Note 1 to the Company’s unaudited interim 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 activities of the Mississippian Trust I and the Permian Trust are included in the exploration and production segment. 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, amortization and accretion. 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 table below is financial information regarding each of the Company’s business segments for the three-month periods ended March 31, 2012 and 2011 (in thousands).

	Exploration  and Production			Drilling and Oil Field Services			Midstream  Gas Services			All Other			Consolidated Total
Three Months Ended March 31, 2012
Revenues	$	343,120		$	98,332		$	26,162		$	1,406		$	469,020
Inter-segment revenue		(77	)		(69,023	)		(18,295	)		10			(87,385	)
Total revenues	$	343,043		$	29,309		$	7,867		$	1,416		$	381,635
(Loss) income from operations(1)	$	(123,836	)	$	3,479		$	(2,727	)	$	(28,572	)	$	(151,656	)
Interest income (expense), net		143			—			(156	)		(66,952	)		(66,965	)
Other income, net		1,768			—			—			700			2,468
(Loss) income before income taxes	$	(121,925	)	$	3,479		$	(2,883	)	$	(94,824	)	$	(216,153	)
Three Months Ended March 31, 2011
Revenues	$	267,237		$	67,549		$	55,978		$	3,220		$	393,984
Inter-segment revenue		(67	)		(46,515	)		(34,038	)		(516	)		(81,136	)
Total revenues	$	267,170		$	21,034		$	21,940		$	2,704		$	312,848
Loss from operations(1)	$	(184,207	)	$	(108	)	$	(2,528	)	$	(20,985	)	$	(207,828	)
Interest income (expense), net		105			(105	)		(172	)		(59,266	)		(59,438	)
Loss on extinguishment of debt		—			—			—			(36,181	)		(36,181	)
Other income (expense), net		1,676			—			(701	)		222			1,197
Loss before income taxes	$	(182,426	)	$	(213	)	$	(3,401	)	$	(116,210	)	$	(302,250	)

(1) Exploration and production segment (loss) income from operations includes net losses of $254.6 million and $277.6 million on commodity derivative contracts for the three-month periods ended March 31, 2012 and 2011, respectively.

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Exploration and Production Segment

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.

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. Quarterly comparisons of production and price data are presented in the tables below. Changes in the Company’s results for these periods are a result of increased oil production throughout 2011 and continuing in 2012 as a result of the Company’s strategic movement toward increased oil production in 2009 and 2010, which increased oil production volumes and revenues attributable to the Company’s exploration and production segment.

	Three Months Ended March 31,				Change
	2012		2011		Amount			Percent
Production data
Oil (MBbls)(1)		3,427		2,581		846			32.8	%
Natural gas (MMcf)		15,746		17,266		(1,520	)		(8.8	)%
Total volumes (MBoe)		6,051		5,459		592			10.8	%
Average daily total volumes (MBoe/d)		67		61		6			9.8	%
Average prices — as reported(2)
Oil (per Bbl)(1)	$	89.99	$	79.76	$	10.23			12.8	%
Natural gas (per Mcf)	$	2.10	$	3.54	$	(1.44	)		(40.7	)%
Total (per Boe)	$	56.42	$	48.90	$	7.52			15.4	%
Average prices — including impact of derivative contract settlements
Oil (per Bbl)(1)	$	86.27	$	72.26	$	14.01			19.4	%
Natural gas (per Mcf)	$	2.35	$	3.44	$	(1.09	)		(31.7	)%
Total (per Boe)	$	54.96	$	45.05	$	9.91			22.0	%

(1) Includes natural gas liquids.

(2) Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.

Exploration and Production Segment — Three months ended March 31, 2012 compared to the three months ended March 31, 2011

Exploration and production segment revenues increased $75.9 million, or 28.4%, to $343.0 million in the three-month period ended March 31, 2012 from the same period in 2011, as a result of a 846 MBbl, or 32.8%, increase in oil production and a $10.23, or 12.8%, increase in the average price received for oil production. These increases were slightly offset by a 1,520 MMcf, or 8.8%, decrease in natural gas production and a $1.44, or 40.7%, decrease in the average price received for natural gas production. The increase in oil production was due to the continued focus on increased oil drilling throughout 2011 and continuing in 2012 in the Mid-Continent and Permian Basin areas from the three-month period ended March 31, 2011 to 2012. The decrease in natural gas production was primarily a result of natural production declines in existing natural gas wells.

Due to the long-term nature of the Company’s investment in the development of its properties, the Company enters into oil and natural gas swaps and collars for a portion of its production in order to stabilize future cash inflows for planning purposes. The Company’s derivative contracts are not designated as accounting 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.”

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Realized gains or losses related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled (“out-of-period settlements”) are not considered in the calculation of effective prices. The effective price received for oil for the three-month period ended March 31, 2012 was $86.27 per Bbl compared to $72.26 per Bbl during the same period in 2011. The effective price received for natural gas for the three-month period ended March 31, 2012 was $2.35 per Mcf compared to $3.44 per Mcf during the same period in 2011.

During the three-month period ended March 31, 2012, the exploration and production segment reported a $254.6 million net loss on its commodity derivative positions ($125.4 million realized loss and $129.2 million unrealized loss) compared to a $277.6 million net loss on its commodity derivative positions ($8.6 million realized loss and $269.0 million unrealized loss) in the same period in 2011. The realized loss for the three-month periods ended March 31, 2012 and 2011 was primarily due to higher oil prices at the time of settlement compared to the contract price for the Company’s oil price swaps. Non-cash realized losses of $117.1 million resulting from the amendment of certain 2012 derivative contracts to contracts maturing in 2014 and 2015 were included in the net realized loss for the three-month period ended March 31, 2012. Realized gains totaling $12.4 million resulting from out-of-period settlements were included in the net realized loss for the three-month period ended March 31, 2011. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized loss on the Company’s commodity contracts recorded during the three-month periods ended March 31, 2012 and 2011 was primarily attributable to an increase in average oil prices at March 31, 2012 and 2011 compared to the average oil prices at December 31, 2011 and 2010 or the contract price for contracts entered into during the first quarter of 2012 and 2011.

For the three-month period ended March 31, 2012, the Company had a loss from operations of $123.8 million in its exploration and production segment compared to an operating loss of $184.2 million in the same period in 2011. An increase of $74.4 million in oil and natural gas revenues and a $23.0 million decrease in loss on derivative contracts was partially offset by increases of $9.4 million in production expense, $15.6 million in depreciation and depletion on oil and natural gas properties and $15.9 million in general and administrative expenses during the three-month period ended March 31, 2012. See further discussion of these changes under “Consolidated Results of Operations” below.

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. 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. 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 March 31, 2012, the Company owned 31 drilling rigs. The table below presents a summary of the Company’s rigs as of March 31, 2012 and 2011:

	March 31,
	2012		2011
Rigs
Working for SandRidge		20		20
Working for third parties		10		11
Total operational		30		31
Non-operational(1)		1		—
Total rigs		31		31

(1) Includes a rig stacked at March 31, 2012.

Drilling and Oil Field Services Segment — Three months ended March 31, 2012 compared to the three months ended March 31, 2011

Drilling and oil field services segment revenues increased $8.3 million to $29.3 million in the three-month period ended March 31, 2012 from the same period in 2011 and drilling and oil field services segment expenses increased $4.7 million during the same period to $25.8 million. The increase in revenues and expenses was primarily attributable to an increase in the average daily rate received per rig working for third parties and an increase in oil field services performed for third parties during the 2012 period. During the three-month period ended March 31, 2012, the average daily rate received per rig working for third parties increased to approximately $15,900 from approximately $14,600 during the same period in 2011. The increase in the average daily rate received from third parties resulted in income from operations of $3.5 million in the three-month period ended March 31, 2012 compared to a loss from operations of $0.1 million in 2011.

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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. The Company continued to monitor the status of the Century Plant, the related impact on its gas treating plants and CO₂ compression facilities and natural gas prices during the second half of 2011 and first quarter of 2012. As of March 31, 2012, no impairment of these plants or facilities was deemed necessary.

Midstream Gas Services Segment — Three months ended March 31, 2012 compared to the three months ended March 31, 2011

Midstream gas services segment revenues for the three-month period ended March 31, 2012 were $7.9 million compared to $21.9 million in the same period in 2011. The decrease in revenue was due to a decrease in third-party volumes the Company marketed of approximately 2.7 Bcf, a decrease in natural gas prices and a decrease in natural gas volumes processed in the Company’s gas treating plants. The decrease in revenue and related expense resulted in a loss from operations of $2.7 million for the three-month period ended March 31, 2012 compared to a loss from operations of $2.5 million in the same period in 2011.

Consolidated Results of Operations

Three months ended March 31, 2012 compared to the three months ended March 31, 2011

Revenues.Total revenues increased 22.0% for the three months ended March 31, 2012 from the same period in 2011. This increase was primarily due to the increase in oil and natural gas sales.

	Three Months Ended March 31,
	2012		2011		$ Change			% Change
	(In thousands)
Revenues
Oil and natural gas	$	341,365	$	266,942	$	74,423			27.9	%
Drilling and services		29,309		21,034		8,275			39.3	%
Midstream and marketing		8,306		22,258		(13,952	)		(62.7	)%
Other		2,655		2,614		41			1.6	%
Total revenues	$	381,635	$	312,848	$	68,787			22.0	%

Total oil and natural gas revenues increased $74.4 million for the three-month period ended March 31, 2012 compared to the same period in 2011, 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 and the average prices received for natural gas production. The 846 MBbl, or 32.8%, increase in oil production was due primarily to the increase in oil production in the Mid-Continent and Permian Basin due to the increased oil drilling during 2011 and the first quarter of 2012. The average price received for oil production, excluding the impact of derivative contracts, increased 12.8% in the three-month period ended March 31, 2012 period compared to the same period in 2011. The increase in oil production and prices was slightly offset by an 8.8% decrease in natural gas production and a 40.7% decrease in the average price received for natural gas production, excluding the impact of derivative contracts, in the three-month period ended March 31, 2012.

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Drilling and services revenues increased $8.3 million for the three-month period ended March 31, 2012 compared to the same period in 2011 due to an increase in the average daily rate received per rig working for third parties and an increase in oil field services work performed for third parties.

Midstream and marketing revenues decreased $14.0 million, or 62.7%, in the three-month period ended March 31, 2012 compared to the same period in 2011. 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 for the three-month period ended March 31, 2012 compared to the same period in 2011.

Expenses. Total expenses increased to $533.3 million for the three months ended March 31, 2012 compared to $520.7 million for the same period in 2011. The increase was primarily due to increases in production expenses, depreciation and depletion on oil and natural gas properties and general and administrative expense, partially offset by the decreases in midstream and marketing expense and the loss on derivative contracts.

	Three Months Ended March 31,
	2012		2011			$ Change			% Change
	(In thousands)
Expenses
Production	$	83,310	$	73,957		$	9,353			12.6	%
Production taxes		12,254		10,575			1,679			15.9	%
Drilling and services		17,560		15,041			2,519			16.7	%
Midstream and marketing		7,954		22,283			(14,329	)		(64.3	)%
Depreciation and depletion — oil and natural gas		87,066		71,460			15,606			21.8	%
Depreciation and amortization — other		14,513		13,093			1,420			10.8	%
Accretion on asset retirement obligation		2,607		2,426			181			7.5	%
General and administrative		50,301		34,414			15,887			46.2	%
Loss on derivative contracts		254,646		277,628			(22,982	)		(8.3	)%
Loss (gain) on sale of assets		3,080		(201	)		3,281			(1,632.3	)%
Total expenses	$	533,291	$	520,676		$	12,615			2.4	%

Production expense includes the costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production expenses increased $9.4 million primarily due to operating expenses associated with additional oil wells that began producing during 2011 and the first three months of 2012. Total production increased 10.8% with oil production increasing 32.8% for the three-month period ended March 31, 2012 compared to the same period in 2011.

Drilling and services expenses, which include operating expenses attributable to the drilling and oil field services segment and the Company’s CO₂ services companies, increased $2.5 million, or 16.7%, for the three-month period ended March 31, 2012 compared to the same period in 2011 primarily due to an increase in oil field services work performed for third parties.

Midstream and marketing expenses decreased $14.3 million, or 64.3%, due to decreased natural gas volumes purchased from third parties as a result of decreased natural gas production and a decrease in volumes processed at the Company’s treating plants during the three-month period ended March 31, 2012.

Depreciation and depletion for the Company’s oil and natural gas properties increased $15.6 million for the three-month period ended March 31, 2012 from the same period in 2011. The increase was due to an increase of 10.8% in the Company’s combined production volume as well as an increase in the depreciation and depletion per Boe to $14.39 in the three-month period ended March 31, 2012 from $13.09 per Boe in the same period in 2011 as a result of the sale of oil and gas properties in 2011.

General and administrative expenses increased $15.9 million, or 46.2%, to $50.3 million for the three-month period ended March 31, 2012 from the same period in 2011. This increase is due primarily to a $7.2 million increase in compensation costs as a result of an increase in number of employees, a $2.6 million increase in advertising expense and $2.5 million in costs associated with the Dynamic Acquisition.

The Company recorded a net loss of $254.6 million ($125.4 million realized loss and $129.2 million unrealized loss) on its commodity derivative contracts for the three-month period ended March 31, 2012 compared to a net loss of $277.6 million ($8.6 million realized loss and $269.0 million unrealized loss) in the same period in 2011. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment—Exploration and Production Segment.”

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Other Income (Expense), Taxes and Net Income Attributable to Noncontrolling Interest. Changes in other income (expense), taxes and net income attributable to noncontrolling interest are reflected in the table below.

	Three Months Ended March 31,
	2012			2011			$ Change			% Change
	(In thousands)
Other income (expense)
Interest expense		(66,965	)		(59,438	)		(7,527	)		12.7	%
Loss on extinguishment of debt		—			(36,181	)		36,181			(100.0	)%
Other income, net		2,468			1,197			1,271			106.2	%
Total other expense		(64,497	)		(94,422	)		29,925			(31.7	)%
Loss before income taxes		(216,153	)		(302,250	)		86,097			(28.5	)%
Income tax expense		71			88			(17	)		(19.3	)%
Net loss		(216,224	)		(302,338	)		86,114			(28.5	)%
Less: net income attributable to noncontrolling interest		1,954			6			1,948			32,466.7	%
Net loss attributable to SandRidge Energy, Inc.	$	(218,178	)	$	(302,344	)	$	84,166			(27.8	)%

Interest expense increased $7.5 million for the three-month period ended March 31, 2012 compared to the same period in 2011, due to fees incurred to secure committed financing for the Dynamic Acquisition. The Company elected to issue senior notes to fund the cash portion of the Dynamic Acquisition rather than utilize the committed financing, however. As a result, the fees associated with the committed financing of $10.9 million were fully expensed during the three-month period ended March 31, 2012. These fees were partially offset by a decrease in interest expense on the senior credit facility as no amounts were outstanding during the three-month period ended March 31, 2012.

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 $36.2 million, for the three-month period ended March 31, 2011, for the notes tendered prior to March 31, 2011. The loss represents the premium paid to purchase and redeem these notes and the unamortized debt issuance costs associated with the tendered notes.

For the three-month periods ended March 31, 2012 and 2011, the Company continues to have a low effective tax rate due to a full valuation allowance against its net deferred tax asset.

Net income attributable to noncontrolling interest increased to $2.0 million for the three-month period ended March 31, 2012 due to the completion of the Mississippian Trust I’s initial public offering in April 2011 and the Permian Trust’s initial public offering in August 2011, as it reflects the portion of net income attributable to beneficial interests of the trusts held by third parties.

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 and the issuance of equity and debt securities. As described in “Recent Developments,” the Company received approximately $272.5 million in January 2012 from the sale of working interests in the Mississippian formation and related drilling carry and received net proceeds of approximately $590.0 million in April 2012 as partial consideration for conveyance of royalty interests in certain of the Company’s oil and natural gas properties to the Mississippian Trust II.

The Company’s primary uses of capital are expenditures related to its oil and natural gas properties, such as costs related to drilling and completion of wells, including to fulfill its drilling commitments to the royalty trusts, and other fixed assets, the acquisition of oil and natural gas properties, the repayment of amounts outstanding under 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 maintains 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 March 31, 2012, the Company had a working capital deficit of $348.1 million compared to a deficit of $257.7 million at December 31, 2011. Current assets decreased $22.4 million at March 31, 2012, compared to current assets at December 31, 2011, primarily due to a $79.8 million decrease in cash and cash equivalents as a result of cash expenditures to fund operations. The

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decrease in cash and cash equivalents was offset by a $34.3 million increase in accounts receivable due to an increase in oil production and prices received on oil production and a $15.5 million increase in other current assets due to an increase in prepaid expenses. Current liabilities increased $68.0 million, primarily due to a $95.0 million increase in accounts payable and accrued expenses resulting from increased production and drilling activity, partially offset by a $9.0 million decrease in billings and estimated contract loss in excess of costs incurred on the Century Plant construction project and a $18.0 million decrease in the liability positions on the Company’s current derivative contracts.

The Company expects to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2012 from cash flows from operating activities, its existing cash balances, availability under its senior credit facility, proceeds from the sale of working interests in the Mississippian formation in January 2012 and proceeds from the Mississippian Trust II’s initial public offering in April 2012. However, a significant portion of the Company’s 2012 capital expenditures budget is discretionary and can be curtailed, if necessary, based on oil and natural gas prices and the availability of the sources of funds described above.

Cash Flows

The Company’s cash flows for the three-month periods ended March 31, 2012 and 2011 are presented in the following table and discussed below:

	Three Months Ended March 31,
	2012			2011
	(In thousands)
Cash flows provided by operating activities	$	230,910		$	79,662
Cash flows used in investing activities		(343,344	)		(269,403	)
Cash flows provided by financing activities		32,595			192,415
Net (decrease) increase in cash and cash equivalents	$	(79,839	)	$	2,674

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 three-month periods ended March 31, 2012 and 2011 was $230.9 million and $79.7 million, respectively. The increase in cash provided by operating activities in the 2012 period compared to the 2011 period was primarily due to an increase in oil sales as a result of increased oil production and prices received for oil production, partially offset by a decrease in natural gas sales as a result of decreased natural gas production during the three-month period ended March 31, 2012 compared to the same period in 2011.

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 increased to $343.3 million in the three-month period ended March 31, 2012 from $269.4 million in the same period in 2011 due to an increase in capital expenditures, primarily for the continued development of the Company’s oil properties, partially offset by increased proceeds from the sale of assets. Proceeds from asset sales, including the sale of working interests to Repsol, during the three-month period ended March 31, 2012 totaled $269.0 million compared to $159.5 million in the same period in 2011.

Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the three-month periods ended March 31, 2012 and 2011 are summarized below:

	Three Months Ended March 31,
	2012		2011
	(In thousands)
Capital Expenditures
Exploration and production	$	491,905	$	399,096
Drilling and oil field services		7,916		6,763
Midstream gas services		23,975		4,172
Other		45,862		6,138
Capital expenditures, excluding acquisitions		569,658		416,169
Acquisitions		10,511		1,548
Total	$	580,169	$	417,717

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Cash Flows from Financing Activities

The Company’s financing activities provided $32.6 million in cash for the three-month period ended March 31, 2012 compared to $192.4 million in the same period in 2011. Cash provided by financing activities during the 2012 period was primarily comprised of $98.8 million of proceeds from the sale of Mississippian Trust I and Permian Trust common units, offset by $32.7 million in distributions to royalty trust unitholders, $17.3 million in dividends paid on the Company’s 8.5% and 6.0% convertible perpetual preferred stock and $7.2 million in debt issuance costs. Cash provided by financing activities during the three months ended March 31, 2011 was primarily comprised of $881.2 million of net proceeds from the issuance of the 7.5% Senior Notes, offset by the redemption of $614.2 million of the 8.625% Senior Notes, the premium of $28.8 million paid in connection with the Company’s tender offer for its 8.625% Senior Notes, $16.5 million of net repayments under the senior credit facility and payment of dividends on the Company’s 8.5% and 6.0% convertible perpetual preferred stock.

Indebtedness

Long-term obligations under the senior credit facility, senior notes and other long-term debt consist of the following at March 31, 2012 (in thousands):

Senior Floating Rate Notes due 2014	$	350,000
Senior credit facility		—
9.875% Senior Notes due 2016, net of $10,422 discount		355,078
8.0% Senior Notes due 2018		750,000
8.75% Senior Notes due 2020, net of $6,296 discount		443,704
7.5% Senior Notes due 2021		900,000
Mortgage		15,772
Total debt	$	2,814,554

The indentures governing the senior notes referred to above contain covenants imposing certain restrictions on the Company’s activities, including, but not limited to, limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers.

Maturities of Long-Term Debt. Aggregate maturities of long-term debt and excluding discounts, for the next five fiscal years (as of March 31, 2012) are as follows (in thousands):

2012	$	793
2013		1,120
2014		351,190
2015		1,266
2016		366,844
Thereafter		2,110,059
Total debt	$	2,831,272

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 29, 2012, the borrowing base was increased to $1.0 billion from $790.0 million as further discussed below. 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. At March 31, 2012, the Company had no amount outstanding under the senior credit facility and $28.7 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $971.3 million at March 31, 2012. The senior credit facility matures on March 29, 2017, unless neither the Company’s Senior Floating Rate Notes nor the Company’s 9.875% Senior Notes have been repaid or refinanced by September 30, 2015 with a source of funds other than the senior credit facility, in which case the senior credit facility will mature on November 15, 2015.

On March 29, 2012, the senior credit facility was amended and restated to, among other things, (a) increase the borrowing base to $1.0 billion from $790.0 million, (b) allow for the incurrence or issuance of additional debt (including up to $750.0 million of unsecured debt to finance the cash portion of the Dynamic purchase price and the related costs and expenses), (c) permit the Company

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to designate certain of its subsidiaries as unrestricted subsidiaries, and (d) effective on and after June 30, 2012, establish the financial covenants as maintaining agreed upon levels for (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 and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total funded debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded. As of and during the three-month period ended March 31, 2012, the Company was in compliance with all applicable financial covenants under the senior credit facility.

Issuance of 8.125% Senior Notes due 2022.As discussed inRecent Developments, the Company issued $750.0 million of unsecured 8.125% Senior Notes in April 2012, concurrent with the closing of the Dynamic Acquisition to finance the cash portion of the consideration paid in the Dynamic Acquisition. The 8.125% Senior Notes mature on October 15, 2022.

For more information about the senior credit facility, the senior notes and the Company’s other long-term debt obligations, see Note 8 to the unaudited condensed consolidated financial statements included in this Quarterly Report. Additionally, see Note 18 for more information on the 8.125% Senior Notes issued in April 2012.

Outlook

The Company’s 2012 budget for capital expenditures, including expenditures related to its drilling programs for the Mississippian Trust I, Permian Trust and Mississippian Trust II, and excluding acquisitions and capital expenditures associated with properties acquired from Dynamic, is approximately $1.7 billion. 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 and one of its wholly owned subsidiaries have entered into development agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II that obligate the Company to drill, or cause to be drilled, a specified number of wells within specific areas of mutual interest for each trust by December 31, 2015, March 31, 2016 and December 31, 2016, respectively. Additionally, 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, to fund those capital expenditures. Based on current cash balances, anticipated oil and natural gas prices and availability under the Company’s senior credit facility, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2012. The Company plans to fund a portion of its 2012 budget for capital expenditures with existing cash balances, proceeds received from the sale of working interests in the Mississippian formation in January 2012 and the proceeds received from the initial public offering of the Mississippian Trust II in April 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 expects any capital and operating expenditures relating to Dynamic’s assets to be funded by the cash flow generated by such assets.

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 2012 through 2014, fixed price swap contracts are in place for only a portion of expected oil production for 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. 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.

As an alternative to borrowing under its senior credit facility, the Company may choose to issue 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 March 31, 2012, the Company’s cash and cash equivalents were $127.8 million, including $3.7 million attributable to the Company’s consolidated VIEs which is available to satisfy only obligations of the VIEs. The Company had approximately $2.8 billion in total debt outstanding and $28.7 million in outstanding letters of credit with no amount outstanding under its senior credit facility at

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March 31, 2012. As of and for the three-month period ended March 31, 2012, the Company was in compliance with applicable covenants under all of its senior notes and senior credit facility. As of April 30, 2012, the Company’s cash and cash equivalents were approximately $608.0 million, including $3.6 million attributable to the Company’s consolidated VIEs, which is available to satisfy only obligations of the VIEs. Additionally, there was no amount outstanding under the Company’s senior credit facility and $28.7 million outstanding in letters of credit.

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, including instruments used to manage commodity prices for production attributable to the royalty trusts. 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 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 and diesel fixed price swap transactions are settled based upon the average daily prices for the calendar month or quarter 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 and diesel derivative contracts occurs in the succeeding month or quarter 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 at fair value, which reflects changes in commodity prices. 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 9 to the Company’s unaudited condensed consolidated financial statements included in this Quarterly Report for a summary of the Company’s open oil and natural gas derivative contracts.

The following table summarizes the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts for the three-month periods ended March 31, 2012 and 2011(in thousands):

	Three Months Ended March 31,
	2012		2011
Commodity Derivatives
Realized loss(1)	$	125,456	$	8,609
Unrealized loss		129,190		269,019
Loss on commodity derivative contracts	$	254,646	$	277,628

(1) The three-month period ended March 31, 2012 includes $117.1 million non-cash realized losses on derivative contracts amended in January 2012. Includes $12.4 million of realized gains for the three-month period ended March 31, 2011 related to out-of-period settlements.

Credit Risk. All of the Company’s hedging transactions have been carried out in the over-the-counter market. The use of hedging transactions involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s hedging transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its hedging counterparties and considers its counterparties’ credit default risk rating in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. Additionally, the majority of the Company’s counterparties are lenders under its senior credit facility.

46

Under certain circumstances, a default by the Company under its senior credit facility constitutes a default under its hedging transactions. The Company does not require collateral or other security from counterparties to support derivative instruments. The Company has master netting agreements with all of its derivative contract counterparties, which allows the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under hedging transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. The Company’s loss is further limited as any amounts due from a defaulting counterparty can be offset against amounts owed to such counterparty under the Company’s senior credit facility under certain circumstances. As of March 31, 2012, the counterparties to the Company’s open derivative contracts consisted of 17 financial institutions, 14 of which are also lenders under the Company’s senior credit facility. As a result, the Company is not required to post additional collateral under derivative contracts as the counterparties to the Company’s derivative contracts share in the collateral supporting the Company’s senior credit facility.

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 23 financial institutions with commitments ranging from 1.00% to 6.00%.

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 the LIBOR and the federal funds rate.

The Company may enter into derivative transactions to fix the interest rate on its variable rate debt. At March 31, 2012, the Company had a $350.0 million notional interest rate swap agreement, which effectively serves to fix the rate on the Senior Floating Rate Notes at an annual rate of 6.69% through 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 March 31, 2012, 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 for the three-month period ended March 31, 2012.

The following table summarizes the cash settlements and valuation gains and losses, which are included in interest expense in the Company’s unaudited condensed consolidated statements of operations, on the Company’s interest rate swaps for the three-month periods ended March 31, 2012 and 2011 (in thousands):

	Three Months Ended March 31,
	2012			2011
Interest Rate Swaps
Realized loss	$	2,200		$	2,043
Unrealized gain		(1,354	)		(1,765	)
Loss on interest rate swaps	$	846		$	278

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 March 31, 2012 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 March 31, 2012 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 Aspen’s construction 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, LLC as plaintiffs. The plaintiffs’ amended claims seek damages relating to the construction of the pipeline and performance under a related gas purchase agreement, which damages are alleged to approach $100.0 million. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP, 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 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 associated with these claims, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. 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. 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, the “defendants”), in the U.S. District Court for the District of Connecticut. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and the 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 the plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, the plaintiffs have invested approximately $15.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. 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. While the results of litigation and claims cannot be predicted with certainty, the Company believes the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, the Company believes the probable final outcome of such matters will not have a material adverse effect on the Company’s consolidated results of operations, financial position, cash flows or liquidity.

ITEM 1A. Risk Factors

There has been no material change to the risk factors previously discussed in Item 1A – Risk Factors in the Company’s 2011 Form 10-K.

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 March 31, 2012, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:

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Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares  Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1, 2012 — January 31, 2012		667,937	$	8.26		N/A		N/A
February 1, 2012 — February 29, 2012		83,696	$	7.83		N/A		N/A
March 1, 2012 — March 31, 2012		25,314	$	8.51		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: May 7, 2012

EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date		Filed Herewith
2.1	Equity Purchase Agreement, dated as of February 1, 2012, among SandRidge Energy, Inc., Dynamic Offshore Holding, LP and R/C Dynamic Holdings, L.P. (solely with respect to Section 9.2)		8-K		001-33784		2.1		02/03/2012
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
4.1	Indenture, dated as of April 17, 2012, among the Company, certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee		8-K		001-33784		4.1		04/17/2012
4.2	Supplemental Indenture, dated April 17, 2012, among the Company, certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee		8-K		001-33784		4.3		04/17/2012
10.1	Registration Rights Agreement, dated as of February 1, 2012, between SandRidge Energy, Inc. and Dynamic Offshore Holding, LP		8-K		001-33784		10.1		02/03/2012
10.2	Second Amended and Restated Credit Agreement, dated as of March 29, 2012, among SandRidge Energy, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and the other lenders party thereto		8-K		001-33784		10.1		04/02/2012
10.3	Purchase Agreement, dated April 2, 2012, by and among the Company, certain subsidiary guarantors named therein, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, SunTrust Robinson Humphrey, Inc. and RBS Securities Inc., as representatives of the several initial purchasers		8-K		001-33784		10.1		04/02/2012
10.4	Registration Rights Agreement, dated April 17, 2012, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, SunTrust Robinson Humphrey, Inc. and RBS Securities Inc., as representatives of the several initial purchasers		8-K		001-33784		4.2		04/17/2012
10.5	Development Agreement, by and between SandRidge Energy, Inc., SandRidge Exploration and Production, LLC and SandRidge Mississippian Trust II		8-K		001-33784		10.1		04/24/2012
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									*

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		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
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					*

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