SANDRIDGE ENERGY INC - Quarter Report: 2013 March (Form 10-Q)

Notional (MMcf)

Weighted Average
Fixed Price

April 2013 - December 2013

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________

Form 10-Q

__________________________

(Mark One)



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

For the quarterly period ended March 31, 2013



£	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 R 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 R 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	R		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 R

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, 2013, was 493,071,763.

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References in this report to the “Company” and “SandRidge” mean SandRidge Energy, Inc., including its consolidated subsidiaries and variable interest entities of which it is the primary beneficiary.

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) of the Company 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, capital resources, debt profile, pending acquisitions or dispositions, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the effects thereof on the Company’s financial condition 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, may not have the expected consequences to or effects on the Company’s business or results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. These forward-looking statements speak only as of the date hereof. The Company disclaims any obligation to update or revise these 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 and uncertainties discussed in “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (the “2012 Form 10-K”).

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SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended March 31, 2013

INDEX



PART I. FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Statement of Changes in Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements	9
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	61
ITEM 4.	Controls and Procedures	64

PART II. OTHER INFORMATION

ITEM 1.	Legal Proceedings	65
ITEM 1A.	Risk Factors	67
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	68
ITEM 6.	Exhibits	68

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PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)



	March 31, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	1,308,733		$	309,766
Accounts receivable, net	389,399			445,506
Derivative contracts	25,693			71,022
Costs in excess of billings	6,735			11,229
Prepaid expenses	40,159			31,319
Restricted deposit	—			255,000
Other current assets	18,439			19,043
Total current assets	1,789,158			1,142,885
Oil and natural gas properties, using full cost method of accounting
Proved	9,975,304			12,262,921
Unproved	548,923			865,863
Less: accumulated depreciation, depletion and impairment	(5,384,132		)	(5,231,182		)
	5,140,095			7,897,602
Other property, plant and equipment, net	595,511			582,375
Derivative contracts	25,219			23,617
Other assets	128,328			144,252
Total assets	$	7,678,311		$	9,790,731

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS - Continued

(In thousands, except per share data)



	March 31, 2013			December 31, 2012
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	672,372		$	766,544
Billings and estimated contract loss in excess of costs incurred	5,798			15,546
Derivative contracts	12,970			14,860
Asset retirement obligations	91,113			118,504
Deposit on pending sale	—			255,000
Total current liabilities	782,253			1,170,454
Long-term debt	3,194,543			4,301,083
Derivative contracts	40,384			59,787
Asset retirement obligations	367,456			379,906
Other long-term obligations	18,183			17,046
Total liabilities	4,402,819			5,928,276
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, 2013 and December 31, 2012; aggregate liquidation preference of $265,000	3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at March 31, 2013 and December 31, 2012; aggregate liquidation preference of $200,000	2			2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at March 31, 2013 and December 31, 2012; aggregate liquidation preference of $300,000	3			3
Common stock, $0.001 par value, 800,000 shares authorized; 494,605 issued and 493,327 outstanding at March 31, 2013 and 491,578 issued and 490,359 outstanding at December 31, 2012	479			476
Additional paid-in capital	5,242,821			5,233,019
Additional paid-in capital—stockholder receivable	(5,000		)	(5,000		)
Treasury stock, at cost	(8,974		)	(8,602		)
Accumulated deficit	(3,344,269		)	(2,851,048		)
Total SandRidge Energy, Inc. stockholders’ equity	1,885,065			2,368,853
Noncontrolling interest	1,390,427			1,493,602
Total equity	3,275,492			3,862,455
Total liabilities and equity	$	7,678,311		$	9,790,731

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)



	Three Months Ended March 31,
	2013			2012
	(Unaudited)
Revenues
Oil and natural gas	$	478,017		$	341,365
Drilling and services	17,370			29,309
Midstream and marketing	13,032			8,306
Other	3,271			2,655
Total revenues	511,690			381,635
Expenses
Production	132,501			83,310
Production taxes	9,439			12,254
Cost of sales	16,317			17,560
Midstream and marketing	11,803			7,954
Depreciation and depletion—oil and natural gas	157,526			87,066
Depreciation and amortization—other	15,336			14,513
Accretion of asset retirement obligations	9,779			2,607
General and administrative	79,444			50,301
Loss on derivative contracts	40,897			254,646
Loss on sale of assets	398,174			3,080
Total expenses	871,216			533,291
Loss from operations	(359,526		)	(151,656		)
Other income (expense)
Interest expense	(85,910		)	(66,965		)
Loss on extinguishment of debt	(82,005		)	—
Other income, net	611			2,468
Total other expense	(167,304		)	(64,497		)
Loss before income taxes	(526,830		)	(216,153		)
Income tax expense	4,429			71
Net loss	(531,259		)	(216,224		)
Less: net (loss) income attributable to noncontrolling interest	(51,919		)	1,954
Net loss attributable to SandRidge Energy, Inc.	(479,340		)	(218,178		)
Preferred stock dividends	13,881			13,881
Loss applicable to SandRidge Energy, Inc. common stockholders	$	(493,221	)	$	(232,059	)
Loss per share
Basic	$	(1.03	)	$	(0.58	)
Diluted	$	(1.03	)	$	(0.58	)
Weighted average number of common shares outstanding
Basic	477,826			400,597
Diluted	477,826			400,597

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands)



	SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock			Common Stock				Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	Shares	Amount		Shares		Amount		Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	(Unaudited)
Three Months Ended March 31, 2013
Balance at December 31, 2012	7,650	$	8	490,359		$	476	$	5,228,019		$	(8,602	)	$	(2,851,048	)	$	1,493,602		$	3,862,455
Distributions to noncontrolling interest owners	—	—		—		—		—			—			—			(51,256		)	(51,256		)
Purchase of treasury stock	—	—		—		—		—			(11,216		)	—			—			(11,216		)
Retirement of treasury stock	—	—		—		—		(11,216		)	11,216			—			—			—
Stock purchase — retirement plans, net of distributions	—	—		(59	)	—		469			(372		)	—			—			97
Stock-based compensation	—	—		—		—		20,552			—			—			—			20,552
Issuance of restricted stock awards, net of cancellations	—	—		3,027		3		(3		)	—			—			—			—
Net loss	—	—		—		—		—			—			(479,340		)	(51,919		)	(531,259		)
Convertible perpetual preferred stock dividends	—	—		—		—		—			—			(13,881		)	—			(13,881		)
Balance at March 31, 2013	7,650	$	8	493,327		$	479	$	5,237,821		$	(8,974	)	$	(3,344,269	)	$	1,390,427		$	3,275,492

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Three Months Ended March 31,
	2013			2012
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(531,259	)	$	(216,224	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	172,862			101,579
Accretion of asset retirement obligations	9,779			2,607
Debt issuance costs amortization	3,008			2,538
Amortization of discount, net of premium, on long-term debt	672			635
Loss on extinguishment of debt	82,005			—
Deferred income taxes	4,359			—
Unrealized loss on derivative contracts	22,417			127,836
Realized loss on amended derivative contracts	—			117,108
Realized (gain) loss on financing derivative contracts	(3,190		)	2,978
Loss on sale of assets	398,174			3,080
Stock-based compensation	19,850			11,371
Other	(299		)	(385		)
Changes in operating assets and liabilities	(56,921		)	77,787
Net cash provided by operating activities	121,457			230,910
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(421,876		)	(601,841		)
Acquisition of assets	(5,048		)	(10,511		)
Proceeds from sale of assets	2,559,374			269,008
Net cash provided by (used in) investing activities	2,132,450			(343,344		)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of borrowings	(1,115,500		)	(257		)
Premium on debt redemption	(61,997		)	—
Debt issuance costs	(91		)	(7,223		)
Proceeds from the sale of royalty trust units	—			98,849
Noncontrolling interest distributions	(51,256		)	(32,740		)
Stock-based compensation excess tax benefit	—			7
Purchase of treasury stock	(12,041		)	(7,144		)
Dividends paid — preferred	(17,263		)	(17,263		)
Cash received (paid) on settlement of financing derivative contracts	3,208			(1,634		)
Net cash (used in) provided by financing activities	(1,254,940		)	32,595
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	998,967			(79,839		)
CASH AND CASH EQUIVALENTS, beginning of year	309,766			207,681
CASH AND CASH EQUIVALENTS, end of period	$	1,308,733		$	127,842
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(127,181	)	$	(57,174	)
Cash received for income taxes	476			83
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	$	(255,000	)	$	—
Change in accrued capital expenditures	$	(33,164	)	$	(32,183	)
Change in preferred stock dividends payable	$	(3,382	)	$	(3,382	)
Adjustment to oil and natural gas properties for estimated contract loss	$	—		$	10,000
Asset retirement costs capitalized	$	1,102		$	1,377

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

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SANDRIDGE ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Business. SandRidge is an independent oil and natural gas company concentrating on development and production activities in the Mid-Continent and Gulf of Mexico. The Company’s primary area of focus is the Mississippian formation in the Mid-Continent area of northern Oklahoma and Kansas. The Company owns and operates additional interests in the Mid-Continent, Gulf Coast, Permian Basin and West Texas Overthrust. The Company also operates businesses and infrastructure systems that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and natural gas marketing business, a saltwater disposal system, an electrical transmission system and an oil field services business, which includes a drilling rig business.

Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. All significant intercompany accounts and transactions have been eliminated in consolidation.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2012 have been derived from the audited financial statements contained in the Company’s 2012 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 2012 Form 10-K. Certain information and 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 2012 Form 10-K.

Significant Accounting Policies. For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2012 Form 10-K.

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

Use of Estimates. The preparation of these unaudited 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 long-lived assets; depreciation, depletion and amortization; asset retirement obligations; assignment of fair value and allocation of purchase price in connection with business combinations; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

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 overall oil and natural gas production and inventories in relevant markets, 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 enters into derivative arrangements in order 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.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Production targets contained in certain gathering and treating agreements require the Company to incur capital expenditures or make associated shortfall payments. Additionally, the Company has a drilling obligation to each of SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Permian Trust (the “Permian Trust”) and SandRidge Mississippian Trust II (the “Mississippian Trust II”). See Note 3 for discussion of these drilling obligations. The Company depends on cash flows from operating activities, funding commitments from third parties for drilling carries and, as necessary, the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Additionally, the Company may use proceeds from the issuance of equity and debt securities in the capital markets and from the sale or other monetization of assets to fund its capital expenditures. Based on current cash balances, cash flows from operating activities and funding commitments from third parties for drilling carries, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2013. 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. See Note 8 for discussion of the financial covenants in the senior credit facility.

Recent Accounting Pronouncements. In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), and in January 2013 issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”). These updates require disclosures about the nature of an entity’s rights of offset and related arrangements associated with its recognized derivatives contracts. The new disclosure requirements, which are effective for interim and annual periods beginning on or after January 1, 2013, were implemented by the Company on January 1, 2013. The implementation of ASU 2011-11 and ASU 2013-01 had no impact on the Company’s financial position or results of operations. See Note 9 for the Company’s derivative disclosures.

2. Acquisitions and Divestitures

2012 Acquisitions and Divestitures

Dynamic Acquisition. The Company acquired 100% of the equity interests of Dynamic Offshore Resources, LLC (“Dynamic”) in April 2012 for total consideration of approximately $1.2 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of SandRidge common stock (the “Dynamic Acquisition”). Upon completion of the initial purchase price allocation as of April 17, 2012, the Company reviewed and verified its assessment, including the identification and valuation of assets acquired and liabilities assumed. The Company recorded a net deferred tax liability associated with the Dynamic Acquisition, which resulted in the release of a portion of the previously recorded valuation allowance on the Company’s net deferred tax asset. The Company will monitor the need to further adjust its valuation allowance on its net deferred tax asset as the purchase price allocation is finalized and the full impact of the acquisition is determined, both of which are expected to occur during the second quarter of 2013. The Company believes the estimates used in the purchase price allocation are reasonable and the significant effects of the Dynamic Acquisition are properly reflected. However, the estimates are subject to change as additional information becomes available and is assessed by the Company. Changes to the purchase price allocation and any corresponding change to the bargain purchase gain will be adjusted retrospectively to the period of the acquisition.

During the fourth quarter of 2012, the Company updated certain of the estimates used in the preliminary purchase price allocation, primarily with respect to deferred taxes and other accruals for which the Company was awaiting additional information. No adjustments were made to the purchase price allocation in the first quarter of 2013.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

The following table summarizes the estimated values of assets acquired and liabilities assumed in connection with the Dynamic Acquisition (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	$	129,363
Asset retirement obligations(4)	315,922
Long-term deferred tax liability(5)	100,288
Other non-current liabilities	4,469
Amount attributable to liabilities assumed	550,042
Total purchase price plus liabilities assumed	1,785,271

Estimated Fair Value of Assets Acquired
Current assets	142,027
Oil and natural gas properties(6)	1,746,753
Other property, plant and equipment	1,296
Other non-current assets	17,891
Amount attributable to assets acquired	1,907,967
Bargain purchase gain(7)	$	(122,696	)

____________________

(1)

Consideration paid by the Company consisted of 74 million 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, which was the closing date of the Dynamic 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 consideration paid, 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.


(3)	In accordance with the acquisition agreement, the Company remitted to the seller a cash payment equal to Dynamic’s 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 the Company of $13.1 million at closing.


(4)	The estimated fair value of the acquired asset retirement obligation was determined using the Company’s credit adjusted risk-free rate.


(5)	The net deferred tax liability is primarily a result of the difference between the estimated fair value and the Company’s expected tax basis in the assets acquired and liabilities assumed. The net deferred tax liability also includes the effects of deferred tax assets associated with net operating losses and other tax attributes acquired as a result of the Dynamic Acquisition.

(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 projections of oil and natural gas reserve quantities and weighted average oil and natural gas prices of $113.62 per barrel of oil and $3.83 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The commodity prices utilized were based upon commodity strip prices as of April 17, 2012 for the first four years and escalated for inflation at a rate of 2.0% annually beginning with the fifth year through the end of production. Future cash flows were discounted using an industry weighted average cost of capital rate.


(7)	The bargain purchase gain results from the excess of the fair value of net assets acquired over consideration paid and, as additional information becomes available, is subject to adjustment. To validate the estimated bargain purchase gain on this acquisition, the Company reviewed its initial identification and valuation of assets acquired and liabilities assumed.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

The Company believes it was able to acquire Dynamic for less than the estimated fair value of its net assets due to their offshore location resulting in less bidding competition.

Market assumptions of future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates used by the Company to estimate the fair market value of the oil and natural gas properties acquired represent Level 3 inputs under the fair value hierarchy, as described in Note 4.

The following unaudited pro forma combined results of operations for the first quarter of 2012 are presented as though the Dynamic Acquisition had been completed as of January 1, 2011, which was the beginning of the earliest period presented at the time of the acquisition. The pro forma combined results of operations for the first quarter of 2012 have been prepared by adjusting the historical results of the Company to include the historical results of Dynamic and certain reclassifications to conform Dynamic’s presentation and accounting policies to the Company’s, and to exclude certain transaction costs. 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 period 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 may result, from the Dynamic Acquisition or any estimated costs 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
	(in thousands, except per share data)
Revenues	$	529,805
Net loss (1)	$	(218,725	)
Loss applicable to SandRidge Energy, Inc. common stockholders (1)	$	(234,560	)
Loss per common share (1)
Basic	$	(0.49	)
Diluted	$	(0.49	)

_________________


(1)	Pro forma net loss, loss applicable to SandRidge Energy, Inc. common stockholders and loss per common share exclude $2.5 million of acquisition costs and $10.9 million of fees to secure financing included in the accompanying unaudited condensed consolidated statement of operations for the three-month period ended March 31, 2012.

Transaction costs related to the Dynamic Acquisition of $2.5 million and fees incurred to secure financing for the acquisition of $10.9 million are included in general and administrative expense and interest expense, respectively, in the accompanying unaudited condensed consolidated statement of operations for the three-month period ended March 31, 2012.

Sale of Tertiary Recovery Properties. In June 2012, the Company sold its tertiary recovery properties located in the Permian Basin area of west Texas for approximately $130.8 million, net of post-closing adjustments. The sale of the acreage and working interests in wells was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

Acquisition of Gulf of Mexico Properties. In June 2012, the Company acquired oil and natural gas properties in the Gulf of Mexico (the “Gulf of Mexico Properties”) located on approximately 184,000 gross (103,000 net) acres for approximately $43.3 million, net of purchase price and post-closing adjustments. This acquisition expanded the Company’s presence in the Gulf of Mexico, adding oil and natural gas reserves and production to its existing asset base in this area.

This acquisition qualified as a business combination for accounting purposes and, as such, the Company estimated the fair value of the acquired properties as of June 20, 2012, which was the date on which the Company obtained control of the properties. The fair value was estimated using a discounted cash flow model based upon market assumptions of future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 4.

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The Company estimated the consideration paid for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase of these properties.

The Company completed its valuation of assets acquired and liabilities assumed related to the acquired Gulf of Mexico Properties in the first quarter of 2013 and updated estimates used in the preliminary purchase price allocation with respect to certain accruals, resulting in an adjustment of $4.8 million to proved developed and undeveloped properties. The following table summarizes the consideration paid to acquire the properties and the final valuation of assets acquired and liabilities assumed as of June 20, 2012 (in thousands):




Consideration paid
Cash, net of purchase price adjustments	$	43,282
Fair value of identifiable assets acquired and liabilities assumed
Proved developed and undeveloped properties	$	98,725
Asset retirement obligation	(55,443		)
Total identifiable net assets	$	43,282

The following unaudited pro forma combined results of operations for the three months ended March 31, 2012 are presented as though the Company acquired the Gulf of Mexico Properties as of January 1, 2011, which was the beginning of the earliest period presented at the time of the acquisition. The pro forma combined results of operations for the first quarter of 2012 have been prepared by adjusting the historical results of the Company to include the historical results of the acquired properties and estimates of the effect of the transaction on the combined results. 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 had the transaction been in effect for the periods presented or that may be achieved by the Company in the future. 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
	(In thousands, except per share data)
Revenues	$	396,252
Net loss	$	(215,020	)
Loss applicable to SandRidge Energy, Inc. common stockholders	$	(230,855	)
Loss per common share
Basic	$	(0.58	)
Diluted	$	(0.58	)

2013 Divestiture

Sale of Permian Properties. On February 26, 2013, the Company completed the sale of all of its oil and natural gas properties in the Permian Basin in west Texas, excluding the assets attributable to the Permian Trust’s area of mutual interest (the “Permian Properties”), for $2.6 billion, subject to post-closing adjustments. This transaction resulted in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded a loss of $399.1 million on the sale, which is included in loss on sale of assets in the accompanying unaudited condensed statement of operations for the three-month period ended March 31, 2013. A portion of the loss totaling $71.7 million was allocated to noncontrolling interests and is reflected in net (loss) income attributable to noncontrolling interest in the accompanying unaudited condensed statement of operations for the three-month period ended March 31, 2013. The loss was calculated based on a comparison of proceeds received and the asset retirement obligation attributable to the Permian Properties that was assumed by the buyer to the sum of (i) an allocation of the historical net book value of the Company’s proved oil and natural gas properties, (ii) the historical cost of unproved acreage sold and (iii) costs incurred by the Company to sell the properties. The allocated net book value attributable to the Permian Properties was calculated based on the relative fair value of the Permian Properties and the remaining proved oil and natural gas properties retained by the Company as of the date of sale.

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The following table presents revenues and direct operating expenses of the Permian Properties included in the accompanying unaudited condensed consolidated statements of operations for the three months ended March 31, 2013 and 2012 (in thousands):



	Three Months Ended March 31,
	2013(1)		2012
Revenue	$	68,027	$	161,765
Direct operating expenses	$	17,453	$	35,990

__________________

(1) Information for the three months ended March 31, 2013 is through February 26, 2013, the date of sale.

Sale of Working Interests and Associated Drilling Carry Commitments

During 2011 and 2012, the Company completed two transactions whereby it 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 within areas of mutual interest 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. These transactions and the associated drilling carries as of March 31, 2013 were as follows:



Partner	Closing Date	Total Drilling Carry		Drilling Carry Recorded		Drilling Carry Remaining
		(in millions)
Atinum MidCon I, LLC	September 2011	$	250.0	$	197.2	$	52.8
Repsol E&P USA, Inc.	January 2012	750.0		312.5		437.5
		$	1,000.0	$	509.7	$	490.3

During the three months ended March 31, 2013 and 2012, the Company recorded approximately $123.3 million and $33.7 million, respectively, for Atinum MidCon I, LLC’s and Repsol E&P USA, Inc.’s drilling carries, which reduced the Company’s capital expenditures for the respective period.

3. Variable Interest Entities

The Company consolidates the activities of 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.

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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 loss of GRLP is 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 because certain equity holders lack 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. 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 and, therefore, consolidates the activity of GRLP in its consolidated financial statements. 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, 2013 and December 31, 2012, $0.6 million and $1.1 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 unaudited condensed consolidated balance sheets at March 31, 2013 and December 31, 2012 consisted of the following (in thousands):



	March 31, 2013		December 31, 2012
Cash and cash equivalents	$	883	$	1,080
Accounts receivable, net	18		20
Prepaid expenses	45		64
Other current assets	109		109
Total current assets	1,055		1,273
Other property, plant and equipment, net	1,225		1,246
Total assets	$	2,280	$	2,519

Accounts payable and accrued expenses	$	982	$	274
Total liabilities	$	982	$	274

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.

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Royalty Trusts. SandRidge owns beneficial interests in three Delaware statutory trusts. The Mississippian Trust I, the Permian Trust and the Mississippian Trust II (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”) completed initial public offerings of their common units in April 2011, August 2011 and April 2012, respectively. Concurrent with the closing of each offering, the Company conveyed certain royalty interests to each Royalty Trust in exchange for the net proceeds of the offering and units representing beneficial interests in the Royalty Trust. Royalty interests conveyed to the Royalty Trusts are in certain existing wells and wells to be drilled on oil and natural gas properties leased by the Company in defined areas of mutual interest. The following table summarizes information about each Royalty Trust upon completion of its initial public offering:



	Mississippian Trust I			Permian Trust			Mississippian Trust II
Net proceeds of offering (in millions)	$	336.9		$	580.6		$	587.1
Total outstanding common units	21,000,000			39,375,000			37,293,750
Total outstanding subordinated units	7,000,000			13,125,000			12,431,250
Beneficial interest owned by Company(1)	38.4		%	34.3		%	39.9		%
Liquidation date(2)	12/31/2030			3/31/2031			12/31/2031

____________________


(1)	Subsequent to the initial public offerings, the Company sold common units of the Mississippian Trust I and the Permian Trust it owned in transactions exempt from registration under Rule 144 under the Securities Act. These transactions decreased the Company’s beneficial interests in the Royalty Trusts. See further discussion of the unit sales below.


(2)	At the time each Royalty Trust terminates, 50% of the royalty interests conveyed to the Royalty Trust will automatically revert to the Company, and the remaining 50% will be sold with the proceeds distributed to Royalty Trust unitholders.

The Royalty Trusts make quarterly cash distributions to unitholders based on calculated distributable income. In order to provide support for cash distributions on the common units, the Company agreed to subordinate a portion of the units it owns in each Royalty Trust (the “subordinated units”), which constitute 25% of the total outstanding units of each Royalty Trust. The subordinated units are entitled to receive pro rata distributions from the Royalty Trusts 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 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 exchange for agreeing to subordinate a portion of its Royalty Trust units, SandRidge is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Royalty Trust units exceeds the applicable quarterly incentive threshold. The Royalty Trusts declared and paid quarterly distributions during the three-month periods ended March 31, 2013 and 2012 as follows (in thousands):



	Three Months Ended March 31,
	2013		2012
Total distributions	$	76,361	$	52,068
Distributions to third-party unitholders	$	51,256	$	32,740

See Note 18 for discussion of the Royalty Trusts’ distribution declarations in April 2013.

Pursuant to the trust agreements governing the Royalty Trusts, SandRidge has a loan commitment to each Royalty Trust, whereby SandRidge will loan funds to the Royalty Trust on an unsecured basis, with terms substantially the same as would be obtained in an arm’s length transaction between SandRidge and an unaffiliated party, if at any time the Royalty Trust’s cash is not sufficient to pay ordinary course administrative expenses as they become due. Any funds loaned may not be used to satisfy indebtedness of the Royalty Trust or to make distributions. There were no amounts outstanding under the loan commitments at March 31, 2013 or December 31, 2012.

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The Company and one of its wholly owned subsidiaries entered into a development agreement with each Royalty Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells within respective areas of mutual interest, which are also subject to the royalty interests granted to the Mississippian Trust I, the Permian Trust and the Mississippian Trust II, by December 31, 2015, March 31, 2016 and December 31, 2016, respectively. At the end of the fourth full calendar quarter following satisfaction of the Company’s drilling obligation (the “subordination period”), the subordinated units of each Royalty Trust will automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions will terminate. One of the Company’s wholly owned subsidiaries also granted to each Royalty 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 drilling costs for the Royalty Trust’s interests in the wells. As the Company fulfills its drilling obligation to each Royalty Trust, development wells that have been drilled and perforated for completion are released from the lien and the total amount that may be recovered by each Royalty Trust is proportionately reduced. As of March 31, 2013, the total maximum amount recoverable by the Royalty Trusts under the liens was approximately $310.4 million.

Additionally, the Company and each Royalty Trust entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Royalty Trust, including hedge management services to the Permian Trust and the Mississippian Trust II. The Company also entered into derivatives agreements with each Royalty Trust, pursuant to which the Company provides to the Royalty Trust the economic effects of certain of the Company’s derivative contracts. Substantially concurrent with the execution of the derivatives agreements with the Permian Trust and the Mississippian Trust II, the Company novated certain of the derivative contracts underlying the respective derivatives agreements to the Permian Trust and the Mississippian Trust II. The Company novated certain additional derivative contracts underlying the derivatives agreements to the Permian Trust in April 2012 and to the Permian Trust and Mississippian Trust II in March 2013. The tables below present the open oil and natural gas commodity derivative contracts at March 31, 2013 underlying the derivatives agreements. The combined volume in the tables below reflects the total volume of the Royalty Trusts’ open oil and natural gas commodity derivative contracts.

Oil Price Swaps Underlying the Derivatives Agreements



	Notional (MBbls)	Weighted Average Fixed Price
April 2013 - December 2013	1,137	$	103.03
January 2014 - December 2014	1,862	$	100.70
January 2015 - December 2015	630	$	101.03

Natural Gas Collars Underlying the Derivatives Agreements



	Notional (MMcf)	Collar Range
April 2013 - December 2013	646	$	4.00	—	$	7.15
January 2014 - December 2014	937	$	4.00	—	$	7.78
January 2015 - December 2015	1,010	$	4.00	—	$	8.55

Oil Price Swaps Underlying the Derivatives Agreements and Novated to the Royalty Trusts



	Notional (MBbls)	Weighted Avg. Fixed Price
April 2013 - December 2013	999	$	103.27
January 2014 - December 2014	991	$	100.79
January 2015 - March 2015	141	$	100.90

See Note 9 for further discussion of the derivatives agreement between the Company and each Royalty Trust.

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(Unaudited)

The Royalty Trusts are considered VIEs due to the lack of voting or similar decision-making rights of the Royalty Trusts’ equity holders regarding activities that have a significant effect on the economic success of the Royalty Trusts. The Company has determined it is the primary beneficiary of the Royalty Trusts as it has (a) the power to direct the activities that most significantly impact the economic performance of the Royalty Trusts through (i) its participation in the creation and structure of the Royalty Trusts, (ii) the manner in which it fulfills its drilling obligations to the Royalty Trusts and (iii) its operation of a majority of the oil and natural gas properties that are subject to the conveyed royalty interests and marketing of the associated production, and (b) the obligation to absorb losses and right to receive residual returns, through its variable interests in the Royalty Trusts, including ownership of common and subordinated units, that could potentially be significant to the Royalty Trusts. As a result, the Company began consolidating the activities of the Royalty Trusts into its results of operations upon conveyance of the royalty interests to each Royalty Trust. The common units of the Royalty Trusts owned by third parties are reflected as noncontrolling interest in the consolidated financial statements.

Each Royalty Trust’s assets can be used to settle only that Royalty Trust’s obligations and not other obligations of the Company or another Royalty Trust. The Royalty Trusts’ creditors have no contractual recourse to the general credit of the Company. Although the Royalty Trusts are included in the Company’s consolidated financial statements, the Company’s legal interest in the Royalty Trusts’ assets is limited to its ownership of the Royalty Trusts units. At March 31, 2013 and December 31, 2012, $1.4 billion and $1.5 billion, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were attributable to the Royalty Trusts. The Royalty Trusts’ assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at March 31, 2013 and December 31, 2012 consisted of the following (in thousands):



	March 31, 2013			December 31, 2012
Cash and cash equivalents(1)	$	6,277		$	7,445
Accounts receivable	27,019			28,596
Derivative contracts	6,334			10,286
Total current assets	39,630			46,327
Investment in royalty interests(2)	1,325,942			1,325,942
Less: accumulated depletion	(125,322		)	(103,746		)
	1,200,620			1,222,196
Derivative contracts	5,931			7,660
Total assets	$	1,246,181		$	1,276,183
Accounts payable and accrued expenses	$	2,004		$	1,101
Total liabilities	$	2,004		$	1,101

____________________


(1)	Includes $3.0 million held by the trustee at March 31, 2013 and December 31, 2012 as reserves for future general and administrative expenses.


(2)	Investment in royalty interests is included in oil and natural gas properties in the accompanying unaudited condensed consolidated balance sheets, and was determined by allocating the historical net book value of the Company’s full cost pool based on the fair value of each Royalty Trust’s royalty interests relative to the fair value of the Company’s full cost pool.

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The Company sold Mississippian Trust I and Permian Trust common units it owned in transactions exempt from registration pursuant to Rule 144 under the Securities Act during the three-month period ended March 31, 2012 for total proceeds of $98.8 million. The Company also sold Mississippian Trust I common units in the second and fourth quarters of 2012, which further reduced its beneficial interest. The unit sales were accounted for as equity transactions with no gain or loss recognized. The Company continues to be the primary beneficiary of the Royalty Trusts, as discussed above, and, accordingly, continues to consolidate the activities of the Royalty Trusts. The Company’s beneficial interests in the Royalty Trusts at March 31, 2013 and December 31, 2012 were as follows:



	March 31, 2013		December 31, 2012
Mississippian Trust I	26.9	%	26.9	%
Permian Trust	30.5	%	30.5	%
Mississippian Trust II	39.9	%	39.9	%

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.

Amounts due from and due to PGC as of March 31, 2013 and December 31, 2012, respectively, included in the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):



	March 31, 2013		December 31, 2012
Accounts receivable due from PGC	$	1,858	$	1,976
Accounts payable due to PGC	$	5,004	$	5,053

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.

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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 approximates fair value. Restricted deposits are included in other assets in the accompanying unaudited condensed consolidated balance sheets.

Investments. The fair value of investments, consisting of assets attributable to the Company’s deferred compensation plan, is based on quoted market prices. Investments are included in other assets in the accompanying unaudited condensed consolidated balance sheets.

Level 2 Fair Value Measurements

Derivative contracts. The fair values of the Company’s oil and natural gas fixed price swaps, oil and 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, volatility factors, interest rates and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model or option pricing model using the applicable inputs, discussed above. 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 value of the Company’s oil 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 oil basis swaps is the estimate of future oil basis differentials. Significant increases (decreases) in oil basis differentials could result in a significantly higher (lower) fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of the Company’s oil basis swaps at March 31, 2013 and December 31, 2012 are included in the table below.



	Unobservable Input	Range			Weighted Average	Fair Value
		(price per Bbl)			(price per Bbl)	(in thousands)
March 31, 2013	Oil basis differential forward curve	$11.31	–	$15.49	$13.28	$	(211	)
December 31, 2012	Oil basis differential forward curve	$10.00	–	$21.98	$14.74	$	(512	)

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, 2013



	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3		Netting(1)			Assets/Liabilities at Fair Value
Assets
Restricted deposits	$	27,950	$	—	$	—	$	—		$	27,950
Commodity derivative contracts	—		90,585		122		(39,795		)	50,912
Investments	11,584		—		—		—			11,584
	$	39,534	$	90,585	$	122	$	(39,795	)	$	90,446
Liabilities
Commodity derivative contracts	$	—	$	92,816	$	333	$	(39,795	)	$	53,354
	$	—	$	92,816	$	333	$	(39,795	)	$	53,354

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December 31, 2012



	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3		Netting(1)			Assets/Liabilities at Fair Value
Assets
Restricted deposits	$	27,947	$	—	$	—	$	—		$	27,947
Commodity derivative contracts	—		130,220		183		(35,764		)	94,639
Investments	10,348		—		—		—			10,348
	$	38,295	$	130,220	$	183	$	(35,764	)	$	132,934
Liabilities
Commodity derivative contracts	$	—	$	107,321	$	695	$	(35,764	)	$	72,252
Interest rate swap	—		2,395		—		—			2,395
	$	—	$	109,716	$	695	$	(35,764	)	$	74,647

____________________

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

The table below sets forth a reconciliation of the Company’s commodity derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three-month periods ended March 31, 2013 and 2012 (in thousands):



	Three Months Ended March 31,
	2013			2012

Beginning balance of Level 3	$	(512	)	$	(4,253	)
Total realized and unrealized gains (losses)	(873		)	2,032
Settlements (received) paid	1,174			(454		)
Ending balance of Level 3	$	(211	)	$	(2,675	)

The Company’s policy is to recognize transfers between 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. During the three-month periods ended March 31, 2013 and 2012, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

Unrealized losses (gains) on the Company’s Level 3 commodity derivative contracts outstanding at period end were $0.9 million and $(1.6) million for the three-month periods ended March 31, 2013 and 2012, respectively, and have been included in loss on derivative contracts in the accompanying unaudited condensed consolidated statements of operations.

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

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Fair Value of Financial Instruments

The Company measures the fair value of its senior notes using pricing for the Company’s senior notes that is readily available in the public market. 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, 2013 and December 31, 2012 were as follows (in thousands):



	March 31, 2013				December 31, 2012
	Fair Value		Carrying Value		Fair Value		Carrying Value
9.875% Senior Notes due 2016(1)	$	—	$	—	$	392,913	$	356,657
8.0% Senior Notes due 2018	—		—		790,313		750,000
8.75% Senior Notes due 2020(2)	484,875		444,275		490,500		444,127
7.5% Senior Notes due 2021(3)	1,222,000		1,179,230		1,257,250		1,179,328
8.125% Senior Notes due 2022	800,625		750,000		823,125		750,000
7.5% Senior Notes due 2023(4)	855,938		821,038		882,750		820,971

____________________

(1)Carrying value is net of $8,843 discount at December 31, 2012.

(2)Carrying value is net of $5,725 and $5,873 discount at March 31, 2013 and December 31, 2012, respectively.


(3)	Carrying value includes a premium of $4,230 and $4,328 at March 31, 2013 and December 31, 2012, respectively, applicable to notes issued in August 2012.

(4)Carrying value is net of $3,962 and $4,029 discount at March 31, 2013 and December 31, 2012, respectively.

See Note 8 for discussion of the Company’s long-term debt, including the redemption in March 2013 of all of the outstanding 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018.

5. Property, Plant and Equipment

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



	March 31, 2013			December 31, 2012
Oil and natural gas properties
Proved(1)	$	9,975,304		$	12,262,921
Unproved	548,923			865,863
Total oil and natural gas properties	10,524,227			13,128,784
Less accumulated depreciation, depletion and impairment	(5,384,132		)	(5,231,182		)
Net oil and natural gas properties capitalized costs	5,140,095			7,897,602
Land	17,929			17,927
Non-oil and natural gas equipment(2)	657,115			643,370
Buildings and structures	214,884			205,349
Total	889,928			866,646
Less accumulated depreciation and amortization	(294,417		)	(284,271		)
Other property, plant and equipment, net	595,511			582,375
Total property, plant and equipment, net	$	5,735,606		$	8,479,977

____________________


(1)	Includes cumulative capitalized interest of $14.7 million and $11.7 million at March 31, 2013 and December 31, 2012, respectively.


(2)	Includes cumulative capitalized interest of approximately $12.4 million and $11.4 million at March 31, 2013 and December 31, 2012, respectively.

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6. Other Assets

Other assets consist of the following (in thousands):



	March 31, 2013		December 31, 2012
Debt issuance costs, net of amortization	$	69,005	$	83,643
Restricted deposits	27,950		27,947
Notes receivable on asset retirement obligations	11,655		11,433
Investments	11,584		10,348
Production tax credit receivable	5,673		6,313
Other	2,461		4,568
Total other assets	$	128,328	$	144,252

7. Construction Contracts

Century Plant. As of December 31, 2012, the Company had substantially completed construction of a carbon dioxide (“CO₂”) treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). The Company constructed the Century Plant for a contract price of $796.3 million, which included agreed upon change orders and scope revisions, that Occidental paid to the Company through periodic cost reimbursements based upon the percentage of the project completed. Upon substantial completion of construction in late 2012, Occidental took ownership and began operating the Century Plant for the purpose of separating and removing CO₂ from the delivered natural gas stream. The Company recorded additions totaling $180.0 million to its oil and natural gas properties for costs incurred in excess of contract amounts during the construction period. Billings and estimated contract loss in excess of costs incurred of $5.8 million and $15.5 million at March 31, 2013 and December 31, 2012, respectively, representing costs expected to be incurred in the final stages of construction, are reported as a current liability 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 is required to deliver certain minimum CO₂ volumes annually and is required to compensate Occidental to the extent such requirements are not met. See Note 11 for additional discussion of this contract. The Company retains all methane gas from the natural gas it delivers to the Century Plant.

Transmission Expansion Projects. The Company is managing the design, engineering and construction of a series of electrical 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 $23.3 million, plus any subsequently agreed-upon revisions. Construction on these projects began in 2012 with the final project expected to be completed in the second quarter of 2013. Costs in excess of billings on these projects of approximately $6.7 million and $11.2 million at March 31, 2013 and December 31, 2012, respectively, are included in current assets in the accompanying unaudited condensed consolidated balance sheets.

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8. Long-Term Debt

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



	March 31, 2013		December 31, 2012
Senior credit facility	$	—	$	—
Senior notes
9.875% Senior Notes due 2016, net of $8,843 discount at December 31, 2012	—		356,657
8.0% Senior Notes due 2018	—		750,000
8.75% Senior Notes due 2020, net of $5,725 and $5,873 discount, respectively	444,275		444,127
7.5% Senior Notes due 2021, including a premium of $4,230 and $4,328, respectively	1,179,230		1,179,328
8.125% Senior Notes due 2022	750,000		750,000
7.5% Senior Notes due 2023, net of $3,962 and $4,029 discount, respectively	821,038		820,971
Total debt	3,194,543		4,301,083
Less: current maturities of long-term debt	—		—
Long-term debt	$	3,194,543	$	4,301,083

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. As of March 31, 2013, the senior credit facility contained financial covenants, including maintaining agreed upon levels for the (i) ratio of total net 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 net 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. The senior credit facility matures in March 2017.

The senior credit facility also 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, 2013, 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 80.0% 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. During the three-month periods ended March 31, 2013 and 2012, the Company paid commitment fees assessed at an annual rate of 0.5% on the available portion of the senior credit facility as there were no amounts outstanding under the senior credit facility for these periods.

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Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. In August 2012, the borrowing base was reduced to $775.0 million from $1.0 billion as a result of the issuance of the 7.5% Senior Notes due 2023 and additional 7.5% Senior Notes due 2021, as discussed below. The Company’s borrowing base was reaffirmed at $775.0 million in March 2013, and the next redetermination will take place in October 2013. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base.

At March 31, 2013, the Company had no amount outstanding under the senior credit facility and $30.2 million in outstanding letters of credit, which reduce the availability under the senior credit facility on a dollar-for-dollar basis.

Senior Fixed Rate Notes

The Company’s unsecured senior fixed rate notes (“Senior Fixed Rate Notes”) bear interest at a fixed rate per annum, payable semi-annually, with the principal due upon maturity. Certain of the Senior Fixed Rate Notes were issued at a discount or a premium. The discount or premium is amortized to interest expense over the term of the respective series of senior notes. The Senior Fixed Rate 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. See Note17 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $70.2 million incurred in connection with the offerings of the Senior Fixed Rate Notes, including the senior notes issued in 2012 and excluding the senior notes redeemed in March 2013, both as discussed below, and any subsequent registered exchanges 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 respective senior notes.

2012 Activity. In 2012, the Company completed offerings of the 8.125% Senior Notes due 2022, additional 7.5% Senior Notes due 2021 and 7.5% Senior Notes due 2023 (collectively, the “2012 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. The Company incurred $41.0 million of debt issuance costs in connection with the 2012 Senior Notes offerings and subsequent registered exchange offers completed in November 2012. 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 respective senior notes.

In April 2012, the Company issued $750.0 million of unsecured 8.125% Senior Notes due 2022. Net proceeds from the offering were approximately $730.1 million after deducting offering expenses, and were used to finance the cash portion of the Dynamic Acquisition purchase price and to pay related fees and expenses, with any remaining amount used for general corporate purposes.

In August 2012, the Company issued $825.0 million of unsecured 7.5% Senior Notes due 2023 at 99.5% of par and $275.0 million of additional unsecured 7.5% Senior Notes due 2021 at 101.625% of par, plus accrued interest from March 15, 2012. The Company received net proceeds from this offering of approximately $1.1 billion, after deducting offering expenses and excluding accrued interest received. The net proceeds of the offering were used to fund the Company’s tender offer for, and subsequent redemption of, its Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”), discussed under Senior Floating Rate Notes due 2014 below, to fund the Company’s capital expenditures and for general corporate purposes.

In November 2012, pursuant to registered exchange offers, the Company replaced the 2012 Senior Notes with equivalent senior notes that are registered under the Securities Act. The exchange offers did not result in the incurrence of any additional indebtedness.

2013 Activity. In March 2013, the Company redeemed the outstanding $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and the outstanding $750.0 million aggregate principal amount of its 8.0% Senior Notes due 2018 for total consideration of $1,061.34 per $1,000 principal amount and $1,052.77 per $1,000 principal amount, respectively. The premiums paid to redeem these notes and the associated unamortized debt issuance costs, totaling $82.0 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, 2013.

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Indentures. The indentures governing the Company’s senior notes contain covenants which restrict the Company’s ability to take a variety of actions, including 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, 2013, the Company was in compliance with all of the covenants contained in the indentures governing its senior notes.

Senior Floating Rate Notes Due 2014

In August 2012, the Company purchased approximately 94.3%, or $329.9 million, of the aggregate principal amount of its Senior Floating Rate Notes pursuant to a tender offer, which expired on August 31, 2012. On September 4, 2012, the Company redeemed the remaining outstanding $20.1 million aggregate principal amount of its Senior Floating Rate Notes. All holders whose notes were purchased in the tender offer or redemption received accrued and unpaid interest from July 1, 2012 through the date of purchase. The Senior Floating Rate Notes were issued in May 2008 and bore interest at LIBOR plus 3.625% prior to their retirement.

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 loss on derivative contracts for 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 sheet.

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. None of the Company’s derivative contracts may be terminated prior to the contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. At March 31, 2013, 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	Two-way 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.
	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be New York Mercantile Exchange plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract.

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 oil and 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.

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The Company had a $350.0 million notional interest rate swap agreement which effectively fixed the variable interest rate on the Senior Floating Rate Notes at an annual rate of 6.69% for periods prior to the Company’s purchase of the Senior Floating Rate Notes in the third quarter of 2012. The interest rate swap, which was not designated as a hedge, matured on April 1, 2013.

Derivatives Agreements with Royalty Trusts. Effective April 1, 2011, August 1, 2011 and April 1, 2012, the Company entered into derivatives agreements with the Mississippian Trust I, the Permian Trust and the Mississippian Trust II, respectively, to provide each Royalty Trust with the economic effect of certain oil and natural gas derivative contracts 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, March 31, 2015 and December 31, 2014 for the Mississippian Trust I, Permian Trust and Mississippian Trust II, respectively. Under these arrangements, the Company pays the Royalty Trusts amounts it receives from its counterparties in accordance with the underlying contracts, and the Royalty Trusts pay the Company any amounts that the Company is required to pay its counterparties under such contracts.

Substantially concurrent with the execution of the respective derivatives agreements, the Company novated certain of the derivatives contracts underlying the derivatives agreements to each of the Permian Trust and the Mississippian Trust II. As a party to these contracts, the Permian Trust and the Mississippian Trust II receive payment directly from the counterparty and pay any amounts owed directly to the counterparty. To secure its obligations under the respective derivatives contracts novated to it, each of the Permian Trust and Mississippian Trust II granted the counterparties liens on the royalty interests held by each respective trust. Under the derivatives agreements, as development wells are drilled for the benefit of the Permian Trust and the Mississippian Trust II, the Company has the right, under certain circumstances, to assign or novate to the Permian Trust and the Mississippian Trust II additional derivative contracts. The Company novated certain additional derivative contracts underlying the derivatives agreements to the Permian Trust in April 2012 and to the Permian Trust and Mississippian Trust II in March 2013.

All contracts underlying the derivatives agreements with the Royalty Trusts, including those novated to the Permian Trust and the Mississippian Trust II, have been included in the Company’s consolidated derivative disclosures. See Note 3 for information on the Royalty Trusts’ open derivative contracts.

Fair Value of Derivatives. The following table presents the fair value of the Company’s derivative contracts as of March 31, 2013 and December 31, 2012 on a gross basis without regard to same-counterparty netting (in thousands):



Type of Contract	Balance Sheet Classification	March 31, 2013			December 31, 2012
Derivative assets
Oil price swaps	Derivative contracts-current	$	44,306		$	88,052
Oil basis swaps	Derivative contracts-current	122			183
Oil collars - three way	Derivative contracts-current	311			—
Natural gas collars	Derivative contracts-current	600			3,111
Oil price swaps	Derivative contracts-noncurrent	32,710			37,983
Oil collars - three way	Derivative contracts-noncurrent	12,019			190
Natural gas collars	Derivative contracts-noncurrent	639			884
Derivative liabilities
Oil price swaps	Derivative contracts-current	(29,161		)	(31,991		)
Natural gas price swaps	Derivative contracts-current	(2,985		)	—
Oil basis swaps	Derivative contracts-current	(333		)	(695		)
Oil collars - two way	Derivative contracts-current	(137		)	(103		)
Interest rate swap	Derivative contracts-current	—			(2,395		)
Oil price swaps	Derivative contracts-noncurrent	(60,533		)	(67,900		)
Oil collars - three way	Derivative contracts-noncurrent	—			(7,327		)
Total net derivative contracts		$	(2,442	)	$	19,992

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

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Master Netting Agreements and the Right of Offset. The Company has master netting agreements with all of its derivative counterparties, which allow the Company to net its derivative assets and liabilities with the same counterparty. As a result, the Company's maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from its counterparties. The Company's open derivative contracts are with counterparties that share in the collateral supporting the Company's senior credit facility. As a result, the Company is not required to post additional collateral under its derivative contracts. To secure their obligations under the derivative contracts novated by the Company, the Permian Trust and the Mississippian Trust II have each given the counterparties to such contracts a lien on its royalty interests. The following tables summarize the Company's derivative contracts on a gross basis, the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements, and the applicable portion of shared collateral under the senior credit facility for SandRidge's derivative contracts and under the liens granted by the Permian Trust and the Mississippian Trust II on their royalty interest for the Trusts' novated derivative contracts associated with the Company's net derivative liability position (in thousands):

March 31, 2013



	Gross Amounts		Gross Amounts Offset			Net Amounts		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	45,339	$	(19,646	)	$	25,693	$	—		$	25,693
Derivative contracts - noncurrent	45,368		(20,149		)	25,219		—			25,219
Total	$	90,707	$	(39,795	)	$	50,912	$	—		$	50,912

Liabilities
Derivative contracts - current	$	32,616	$	(19,646	)	$	12,970	$	(12,970	)	$	—
Derivative contracts - noncurrent	60,533		(20,149		)	40,384		(40,384		)	—
Total	$	93,149	$	(39,795	)	$	53,354	$	(53,354	)	$	—

December 31, 2012



	Gross Amounts		Gross Amounts Offset			Net Amounts		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	91,346	$	(20,324	)	$	71,022	$	—		$	71,022
Derivative contracts - noncurrent	39,057		(15,440		)	23,617		—			23,617
Total	$	130,403	$	(35,764	)	$	94,639	$	—		$	94,639

Liabilities
Derivative contracts - current	$	35,184	$	(20,324	)	$	14,860	$	(14,860	)	$	—
Derivative contracts - noncurrent	75,227		(15,440		)	59,787		(59,787		)	—
Total	$	110,411	$	(35,764	)	$	74,647	$	(74,647	)	$	—

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The following table summarizes the cash settlements and valuation gain and loss on the Company’s commodity derivative contracts and interest rate swap, which are included in loss on derivative contracts and interest expense, respectively, in the accompanying unaudited condensed consolidated statements of operations for the three-month periods ended March 31, 2013 and 2012 (in thousands):



	Three Months Ended March 31,
	2013			2012
Commodity Derivatives
Realized loss(1)	$	16,085		$	125,456
Unrealized loss	24,812			129,190
Loss on commodity derivative contracts	$	40,897		$	254,646
Interest Rate Swap
Realized loss	$	2,409		$	2,200
Unrealized gain	(2,395		)	(1,354		)
Loss on interest rate swap	$	14		$	846

____________________

(1)

The three-month period ended March 31, 2013 includes $29.6 million of realized losses related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled (“early settlements”) in conjunction with the sale of the Permian Properties. The three-month period ended March 31, 2012 includes $117.1 million of non-cash realized losses on derivative contracts amended in January 2012.

At March 31, 2013, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps



	Notional (MBbls)	Weighted Average Fixed Price
April 2013 - December 2013	10,142	$	98.64
January 2014 - December 2014	7,511	$	92.43
January 2015 - December 2015	5,076	$	83.69

Natural Gas Price Swaps

Oil Basis Swaps

Oil Collars - Two-way

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Oil Collars - Three-way



	Notional (MBbls)	Sold Put	Purchased Put	Sold Call
January 2014 - December 2014	8,213	$70.00	$90.20	$100.00
January 2015 - December 2015	2,920	$73.13	$90.82	$103.13

Natural Gas Collars



	Notional (MMcf)	Collar Range
April 2013 - December 2013	5,146	$3.78	—	$6.71
January 2014 - December 2014	937	$4.00	—	$7.78
January 2015 - December 2015	1,010	$4.00	—	$8.55

10. Asset Retirement Obligations

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2012 to March 31, 2013 is as follows (in thousands):



Asset retirement obligations at December 31, 2012	$	498,410
Liability incurred upon acquiring and drilling wells	1,102
Liability settled or disposed in current period	(50,722		)
Accretion	9,779
Asset retirement obligations at March 31, 2013	458,569
Less: current portion	91,113
Asset retirement obligations, net of current	$	367,456

Liability settled or disposed during the three-month period ended March 31, 2013 includes $22.7 million for the balance of a plugging and abandonment obligation associated with the Company’s Bullwinkle platform in the Gulf of Mexico and $15.2 million disposed in conjunction with the sale of the Permian Properties in February 2013.

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11. Commitments and Contingencies

Legal Proceedings

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP filed suit against the Company and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83rd 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 and 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 approximately $45.5 million in actual damages for the period of time between January 2004 and December 2011, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from the 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 and seeking approximately $13.0 million in actual damages, inclusive of penalties and interest. On February 5, 2013, the Company received a favorable summary judgment ruling that effectively removes a majority of the plaintiffs' and GLO's claims. On April 29, 2013, the court entered an order allowing for an interlocutory appeal of its summary judgment ruling. The Company intends to continue to defend the remaining issues in this lawsuit as well as any appellate proceedings. At the time of the ruling on summary judgment, the lawsuit was still in the discovery stage and, accordingly, an estimate of reasonably possible losses associated with the remaining causes of action, if any, cannot be made until all of the facts, circumstances and legal theories relating to such claims and the Company's defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

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 the Company, SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain directors and senior executive officers of the Company (collectively, the “defendants”) in the U.S. District Court for the District of Connecticut. On October 28, 2011, the plaintiffs filed an amended complaint alleging substantially the same allegations as those contained in the original complaint. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and to 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 $16.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. On November 28, 2011, the defendants filed a motion to dismiss the amended complaint, which was recently denied. The Company intends to defend this lawsuit vigorously and believes the plaintiffs' claims are without merit. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, 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 action.

Between December 2012 and March 2013, seven putative shareholder derivative actions were filed in state and federal court in Oklahoma:


•	Arthur I. Levine v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on December 19, 2012 in the U.S. District Court for the Western District of Oklahoma


•	Deborah Depuy v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 22, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Paul Elliot, on Behalf of the Paul Elliot IRA R/O, v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 29, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Dale Hefner v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 4, 2013 in the District Court of Oklahoma County, Oklahoma


•	Rocky Romano v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 22, 2013 in the District Court of Oklahoma County, Oklahoma

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•	Joan Brothers v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on February 15, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Lisa Ezell, Jefferson L. Mangus, and Tyler D. Mangus v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on March 22, 2013 in the U.S. District Court for the Western District of Oklahoma

Each lawsuit identified above was filed derivatively on behalf of the Company and names as defendants the Company's current directors. The Hefner lawsuit also names as defendants certain senior executive officers and past directors of the Company. All seven lawsuits assert overlapping claims - generally that the defendants breached their fiduciary duties, mismanaged the Company, wasted corporate assets, and engaged in, facilitated or approved self-dealing transactions in breach of their fiduciary obligations. The Depuy lawsuit also alleges violations of federal securities laws in connection with the Company allegedly filing and distributing certain misleading proxy statements. The lawsuits seek, among other relief, injunctive relief related to the Company's corporate governance and unspecified damages.

On April 10, 2013, the U.S. District Court for the Western District of Oklahoma consolidated the Levine, Depuy, Elliot, Brothers, and Ezell actions (the “Federal Shareholder Derivative Litigation”) under the caption “In re SandRidge Energy, Inc. Shareholder Derivative Litigation,” appointed a lead plaintiff and lead counsel, and ordered the lead plaintiff to file a consolidated amended complaint by May 1, 2013. The Company and the individual defendants in the Romano and Hefner actions (the “State Shareholder Derivative Litigation”) have moved to stay each of those actions in favor of the Federal Shareholder Derivative Litigation, in order to avoid duplicative proceedings, and also have requested, in the alternative, the dismissal of the State Shareholder Derivative Litigation. Following the filing of the defendants' initial motion to stay in the Romano case, the plaintiff agreed to stay the proceeding pending the Federal Shareholder Derivative Litigation, and the parties filed a joint motion to stay pending the Federal Shareholder Derivative Litigation. Because the lawsuits comprising the State Shareholder Derivative Litigation and the Federal Shareholder Derivative Litigation have only been recently filed, an estimate of reasonably possible losses associated with each of them, if any, cannot be made until the facts, circumstances and legal theories relating to the claims asserted and available defenses are fully disclosed and analyzed. The Company has not established any reserves relating to these actions.

On December 5, 2012, James Glitz and Rodger A. Thornberry, on behalf of themselves and all other similarly situated stockholders, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and certain of the Company's executive officers. On January 4, 2013, Louis Carbone, on behalf of himself and all other similarly situated stockholders, filed a substantially similar putative class action complaint in the same court and against the same defendants. In each case, the plaintiffs allege that, between February 24, 2011, and November 8, 2012, the defendants made false and misleading statements, and omitted material information, concerning the Company's oil reserves and business fundamentals, and engaged in a scheme to deceive the market. The plaintiffs seek, among other relief, unspecified damages. On March 6, 2013, the court consolidated these two actions under the caption “In re SandRidge Energy, Inc. Securities Litigation” and appointed a lead plaintiff and lead counsel. By order dated April 10, 2013, the court granted the lead plaintiff until July 23, 2013 to file a consolidated amended complaint in the action. Because these lawsuits have only been recently filed, an estimate of reasonably possible losses associated with them, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and available defenses are fully disclosed and analyzed. The Company has not established any reserves relating to these actions.

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On January 7, 2013, Gerald Kallick, on behalf of himself and all other similarly situated stockholders, filed a putative class action complaint in the Court of Chancery of the State of Delaware against SandRidge Energy, Inc., and each of the Company's current directors. On January 31, 2013, the plaintiff filed an amended class action complaint. In his amended complaint, the plaintiff seeks: (i) declaratory relief that certain change-in-control provisions in the Company's indentures and credit agreement are invalid and unenforceable, (ii) declaratory relief that the directors breached their fiduciary duties by failing to approve the slate of directors proposed by TPG-Axon in its consent solicitation in order to disable the change-in-control provisions described above, (iii) a mandatory injunction requiring the directors to approve nominees for the Board of Directors (the “Board”) submitted by TPG-Axon, (iv) a mandatory injunction prohibiting the Company from paying the Company's CEO his change-in-control benefits under his employment agreement in the event the CEO is removed as a director, but remains employed as the Company's CEO, (v) a mandatory injunction enjoining the defendants from impeding or interfering with the dissident stockholder's consent solicitation, (vi) a mandatory injunction requiring the defendants to disclose all material information related to the change-in-control provisions in the Company's indentures and credit agreement; and (vii) an order requiring the Company's current directors to account to the plaintiff and the putative class for alleged damages. On March 8, 2013, the court granted plaintiff's motion for a preliminary injunction, enjoining the Board, unless and until it approved the TPG-Axon nominees for purposes of the change-in-control provisions of the Company's outstanding debt agreements, from (i) soliciting any further consent revocations in opposition to TPG-Axon's consent solicitation, (ii) relying upon or otherwise giving effect to any consent revocations received by the Company as of March 11, 2013, and (iii) impeding the dissident stockholder's consent solicitation in any way. On March 9, 2013, the Board approved TPG-Axon's nominees for purposes of the change-in-control provisions in the Company's debt instruments. On March 13, 2013, TPG-Axon and the Board entered into a settlement agreement under which TPG-Axon's consent solicitation was withdrawn. As a result of these actions, the Company believes that many of the claims asserted by the plaintiff in the Kallick action have been rendered moot. On April 9, 2013, however, the plaintiff filed a motion to supplement his complaint to assert a new claim. The court has not yet ruled on the motion.

In addition to the litigation described above, 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 financial position, results of operations, cash flows or liquidity.

Treating Agreement Commitment

In conjunction with the Century Plant construction agreement, the Company entered into a 30-year treating agreement with Occidental for the removal of CO₂ from the Company’s delivered production volumes. Under the agreement, the Company is required to deliver a total of approximately 3,200 Bcf of CO₂ during the agreement period and is required to compensate Occidental to the extent certain minimum annual CO₂ volume requirements are not met. The Company expects to accrue between approximately $29.5 million and $36.0 million at December 31, 2013 for amounts related to the Company’s anticipated shortfall in meeting its 2013 annual delivery obligations based on current projected natural gas production levels. 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; however, curtailed drilling due to continued low natural gas prices may result in additional shortfall payments in future periods.

12. Equity

Preferred Stock

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



	March 31, 2013	December 31, 2012
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

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The Company is authorized to issue 50.0 million shares of preferred stock, $0.001 par value, of which approximately 7.7 million shares were designated as convertible perpetual preferred stock at March 31, 2013 and December 31, 2012. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions. However, all of the outstanding shares of convertible perpetual preferred stock are freely tradable.

8.5% Convertible perpetual preferred stock. 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. 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. 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. 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. On December 21, 2014, all outstanding shares of the 6.0% convertible preferred stock will be converted automatically into shares of the Company’s common stock at the then-prevailing conversion rate as long as all dividends accrued at that time have been paid.

7.0% Convertible perpetual preferred stock. Each share of the 7.0% convertible preferred stock has a liquidation preference of $100.00 per share and is convertible at the holder’s option at any time, 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. 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.

Preferred stock dividends. All dividend payments to date on the Company’s 8.5%, 6.0% and 7.0% convertible perpetual preferred stock have been paid in cash. Paid and unpaid dividends 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, 2013 and 2012 as presented in the accompanying unaudited condensed consolidated statements of operations, are included in table below (in thousands):



	Three Months Ended March 31,
	2013						2012
	Dividends Paid		Dividends Unpaid		Total		Dividends Paid		Dividends Unpaid		Total
8.5% Convertible perpetual preferred stock	$	2,815	$	2,816	$	5,631	$	2,815	$	2,816	$	5,631
6.0% Convertible perpetual preferred stock	500		2,500		3,000		500		2,500		3,000
7.0% Convertible perpetual preferred stock	—		5,250		5,250		—		5,250		5,250
Total	$	3,315	$	10,566	$	13,881	$	3,315	$	10,566	$	13,881

Common Stock

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



	March 31, 2013	December 31, 2012
Shares authorized	800,000	800,000
Shares outstanding at end of period	493,327	490,359
Shares held in treasury	1,278	1,219

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Stockholder Rights Plan

On November 19, 2012, the Board adopted a stockholder rights plan pursuant to which the Board authorized and declared to stockholders of record on November 29, 2012 a dividend of one preferred share purchase right (the “Right”) for each outstanding share of common stock. Effective April 29, 2013, at the direction of the Board, the Company amended the stockholder rights plan to accelerate the expiration date of the Rights to April 29, 2013. Accordingly, the Rights have expired and are no longer outstanding, and the stockholder rights plan has been terminated.

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 1.8 million shares having a total value of $11.2 million and approximately 0.8 million shares having a total value of $6.4 million during the three-month periods ended March 31, 2013 and 2012, respectively. These shares were accounted for as treasury stock when withheld, and then immediately retired.

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, including for the purpose of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Stockholder Receivable

On November 9, 2012, Tom L. Ward, the Company’s Chairman and Chief Executive Officer, and the Company entered into a settlement agreement with a stockholder plaintiff relating to a third-party claim under Section 16(b) of the Exchange Act. The claim was filed in December 2010 and related to certain transactions involving Company common stock by Mr. Ward in 2008 and 2009. The settlement agreement finds no liability or other wrongdoing under Section 16(b) regarding the transactions in question. Under the settlement agreement, Mr. Ward agreed to pay to the Company $5.0 million in four installments over four years commencing October 2013 and to waive his rights under his indemnification agreement with the Company with respect to this Section 16(b) action. The Company agreed to pay the fees of the plaintiff’s lawyers and paid Mr. Ward’s legal expenses as required under his indemnification agreement.

Based on the nature of the settlement as well as Mr. Ward’s position as an officer of the Company, a $5.0 million receivable was recorded as a component of additional paid-in capital and is included in the accompanying unaudited condensed consolidating balance sheets.

Equity Compensation

The Company awards restricted common stock under its long-term incentive compensation plan 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, 2013 and 2012, the Company recognized equity compensation expense of $18.9 million and $10.5 million, net of $1.6 million and $1.9 million capitalized, respectively, related to restricted common stock. The three-month period ended March 31, 2013 includes approximately $7.6 million of equity compensation expense recognized in connection with the Company’s separation agreement with its former President and Chief Operating Officer.

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Noncontrolling Interest

Noncontrolling interest represents third-party ownership interests in the Company’s subsidiaries and consolidated VIEs (see Note 3), and is included as a component of equity in the accompanying unaudited condensed consolidated balance sheets and consolidated statement 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 provision (benefit) for income taxes consisted of the following components for three-month periods ended March 31, 2013 and 2012 (in thousands):



	Three Months Ended March 31,
	2013		2012
Current
Federal	$	4,359	$	(83	)
State	70		154
	4,429		71
Deferred
Federal	—		—
State	—		—
	—		—
Total provision	4,429		71
Less: income tax provision attributable to noncontrolling interest	75		90
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	4,354	$	(19	)

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 continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. As a result of significant weight being placed on the Company's cumulative negative earnings position, the Company continued to have a full valuation allowance against its net deferred tax asset at March 31, 2013.

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 $627.8 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, 2013 or December 31, 2012.

At March 31, 2013, the Company had a liability of approximately $1.9 million for unrecognized tax benefits, compared to a liability of approximately $1.3 million at December 31, 2012. 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.

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Consistent with its policy to record interest and penalties on income taxes as a component of the income tax provision, the Company included $3,000 and $17,000 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, 2013 and 2012, respectively. The Company had a corresponding accrued liability of $0.2 million for interest and penalties relating to uncertain tax positions at March 31, 2013 and December 31, 2012.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2009 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.

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 at the average market price. 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, 2013 and 2012 (in thousands):



	Three Months Ended March 31,
	2013	2012
Weighted average basic common shares outstanding	477,826	400,597
Effect of dilutive securities
Restricted stock	—	—
Convertible preferred stock	—	—
Weighted average diluted common and potential common shares outstanding	477,826	400,597

For the three-month periods ended March 31, 2013 and 2012, restricted stock awards covering 1.2 million and 9.4 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 convertible perpetual preferred stock for the three-month periods ended March 31, 2013 and 2012. 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, 2013 and 2012, the Company determined the if-converted method was antidilutive and included the 8.5%, 6.0% and 7.0% preferred stock dividends in the determination of loss applicable to common stockholders.

As discussed in Note 12, the Board adopted a stockholder rights plan in November 2012 under which holders of common stock were issued preferred stock purchase rights. As the contingency for exercising these rights had not been met as of March 31, 2013, the Company did not include the conversion of any preferred stock purchase rights in its computation of diluted loss per share for the three-month period ended March 31, 2013.

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, 2013 and 2012, sales by the Company to related parties were $1.5 million and $3.7 million, respectively. Accounts receivable due from related parties totaled $0.7 million and $1.0 million at March 31, 2013 and December 31, 2012, respectively. These amounts primarily relate to sales of natural gas to Southern Union, the Company’s partner in GRLP.

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Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer and one of its independent directors own minority interests in a limited liability company that owns and operates the Oklahoma City Thunder basketball team. The Company is party to a sponsorship agreement, whereby it pays approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder, that will end with the 2012- 2013 season. Additionally, the Company has an agreement to license a suite at the arena where the Oklahoma City Thunder plays its home games. Under this agreement, the Company pays an annual license fee of $0.2 million through September 2020. The Company had no amount due under these agreements at March 31, 2013 and $0.9 million due under these agreements at December 31, 2012.

Office Lease. In July 2012, the Company entered into a commercial lease to rent space in a building owned by an entity that is partially owned by one of the Company’s directors. The terms provide for an initial lease term of three years with annual rent of approximately $0.5 million, and any renovation costs paid by the Company with respect to the leased space will be applied toward future rent payments. Renovation costs in excess of the total rent will be reimbursed to the Company at the end of the lease agreement. As of March 31, 2013, the Company has made renovations costing approximately $3.3 million. The terms of the lease were reviewed and approved by the Board and the Company believes that the rent expense to be paid under the lease is at a fair market rate.

See Note 12 for discussion of a receivable due from the Company’s Chairman and Chief Executive Officer.

16. Business Segment Information

The Company has three business segments: exploration and production, drilling and oil field services and midstream 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 Royalty Trusts. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells and provides various oil field services. The midstream 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 as well as its corporate operations.

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	Exploration and Production			Drilling and Oil Field Services			Midstream Services			All Other			Consolidated Total
Three Months Ended March 31, 2013
Revenues	$	481,410		$	49,737		$	36,834		$	853		$	568,834
Inter-segment revenue	(81		)	(32,367		)	(24,696		)	—			(57,144		)
Total revenues	$	481,329		$	17,370		$	12,138		$	853		$	511,690

Loss from operations(1)	$	(301,707	)	$	(8,965	)	$	(2,459	)	$	(46,395	)	$	(359,526	)
Interest income (expense), net	318			—			(125		)	(86,103		)	(85,910		)
Loss on extinguishment of debt	—			—			—			(82,005		)	(82,005		)
Other income (expense), net	628			—			(800		)	783			611
Loss before income taxes	$	(300,761	)	$	(8,965	)	$	(3,384	)	$	(213,720	)	$	(526,830	)
Capital expenditures(2)	$	357,591		$	632		$	15,221		$	15,268		$	388,712
Depreciation, depletion, amortization and accretion	$	167,513		$	8,814		$	1,687		$	4,627		$	182,641
At March 31, 2013
Total assets	$	5,647,302		$	192,087		$	159,843		$	1,679,079		$	7,678,311
Three Months Ended March 31, 2012
Revenues	$	343,120		$	98,332		$	26,162		$	1,416		$	469,030
Inter-segment revenue	(77		)	(69,023		)	(18,295		)	—			(87,395		)
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	)
Capital expenditures(2)	$	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 December 31, 2012
Total assets	$	8,681,056		$	199,523		$	151,492		$	758,660		$	9,790,731

____________________


(1)	Exploration and production segment income from operations includes unrealized losses of $24.8 million and $129.2 million on commodity derivative contracts for the three-month periods ended March 31, 2013 and 2012, respectively. Exploration and production segment also includes a loss on the sale of the Permian Properties of $399.1 million for the three-month period ended March 31, 2013.


(2)	On an accrual basis.

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17. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. As of March 31, 2013, the subsidiary guarantors, which are 100% owned by the Company, have jointly and severally guaranteed, on a full, unconditional and unsecured basis, the Company’s 8.75% Senior Notes due 2020, 7.5% Senior Notes due 2021, 8.125% Senior Notes due 2022 and 7.5% Senior Notes due 2023. The Senior Floating Rate Notes, prior to their purchase and redemption in 2012, were also jointly and severally guaranteed, on a full, unconditional and unsecured basis by the 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 subsidiary 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.

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The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiaries, prepared on the equity basis of accounting. The non-guarantor subsidiaries, including consolidated VIEs, majority owned subsidiaries and certain immaterial wholly owned subsidiaries, are included in the non-guarantors column in the tables below. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.

Condensed Consolidating Balance Sheets



	March 31, 2013
	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,285,392	$	16,091		$	7,250	$	—		$	1,308,733
Accounts receivable, net	—		1,554,283			715,628		(1,880,512		)	389,399
Derivative contracts	—		19,359			18,165		(11,831		)	25,693
Prepaid expenses	—		39,992			167		—			40,159
Other current assets	1,375		19,585			4,214		—			25,174
Total current assets	1,286,767		1,649,310			745,424		(1,892,343		)	1,789,158
Property, plant and equipment, net	—		4,515,107			1,276,084		(55,585		)	5,735,606
Investment in subsidiaries	5,119,024		(30,760		)	—		(5,088,264		)	—
Derivative contracts	—		19,288			27,163		(21,232		)	25,219
Other assets	69,005		65,196			29		(5,902		)	128,328
Total assets	$	6,474,796	$	6,218,141		$	2,048,700	$	(7,063,326	)	$	7,678,311
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	1,330,207	$	532,220		$	688,833	$	(1,878,888	)	$	672,372
Derivative contracts	—		24,801			—		(11,831		)	12,970
Asset retirement obligations	—		91,113			—		—			91,113
Other current liabilities	—		5,798			—		—			5,798
Total current liabilities	1,330,207		653,932			688,833		(1,890,719		)	782,253
Long-term debt	3,200,445		—			—		(5,902		)	3,194,543
Derivative contracts	—		61,616			—		(21,232		)	40,384
Asset retirement obligations	—		367,256			200		—			367,456
Other long-term obligations	1,870		16,313			—		—			18,183
Total liabilities	4,532,522		1,099,117			689,033		(1,917,853		)	4,402,819
Equity
SandRidge Energy, Inc. stockholders’ equity	1,942,274		5,119,024			1,359,667		(6,535,900		)	1,885,065
Noncontrolling interest	—		—			—		1,390,427			1,390,427
Total equity	1,942,274		5,119,024			1,359,667		(5,145,473		)	3,275,492
Total liabilities and equity	$	6,474,796	$	6,218,141		$	2,048,700	$	(7,063,326	)	$	7,678,311

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	December 31, 2012
	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	300,228	$	922		$	8,616	—			$	309,766
Accounts receivable, net	2,162,471		808,435			717,715		(3,243,115		)	445,506
Derivative contracts	—		60,736			28,484		(18,198		)	71,022
Prepaid expenses	—		31,135			184		—			31,319
Restricted deposit	—		255,000			—		—			255,000
Other current assets	1,375		24,188			4,709		—			30,272
Total current assets	2,464,074		1,180,416			759,708		(3,261,313		)	1,142,885
Property, plant and equipment, net	—		7,236,685			1,298,877		(55,585		)	8,479,977
Investment in subsidiaries	5,425,907		(86,235		)	—		(5,339,672		)	—
Derivative contracts	—		15,957			33,114		(25,454		)	23,617
Other assets	83,642		66,512			—		(5,902		)	144,252
Total assets	$	7,973,623	$	8,413,335		$	2,091,699	$	(8,687,926	)	$	9,790,731
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	1,236,793	$	2,087,046		$	684,136	$	(3,241,431	)	$	766,544
Derivative contracts	2,394		30,664			—		(18,198		)	14,860
Asset retirement obligations	—		118,504			—		—			118,504
Deposit on pending sale	—		255,000			—		—			255,000
Other current liabilities	—		15,546			—		—			15,546
Total current liabilities	1,239,187		2,506,760			684,136		(3,259,629		)	1,170,454
Long-term debt	4,306,985		—			—		(5,902		)	4,301,083
Derivative contracts	—		85,241			—		(25,454		)	59,787
Asset retirement obligations	—		379,710			196		—			379,906
Other long-term obligations	1,329		15,717			—		—			17,046
Total liabilities	5,547,501		2,987,428			684,332		(3,290,985		)	5,928,276
Equity
SandRidge Energy, Inc. stockholders’ equity	2,426,122		5,425,907			1,407,367		(6,890,543		)	2,368,853
Noncontrolling interest	—		—			—		1,493,602			1,493,602
Total equity	2,426,122		5,425,907			1,407,367		(5,396,941		)	3,862,455
Total liabilities and equity	$	7,973,623	$	8,413,335		$	2,091,699	$	(8,687,926	)	$	9,790,731

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Condensed Consolidating Statements of Operations



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)

Three Months Ended March 31, 2013
Total revenues	$	—		$	440,318		$	77,536		$	(6,164	)	$	511,690
Expenses
Direct operating expenses	—			163,611			12,241			(5,792		)	170,060
General and administrative	87			76,819			2,970			(432		)	79,444
Depreciation, depletion, amortization and accretion	—			159,889			22,752			—			182,641
Loss on derivative contracts	—			30,900			9,997			—			40,897
Loss on sale of assets	—			290,956			107,218			—			398,174
Total expenses	87			722,175			155,178			(6,224		)	871,216
Loss from operations	(87		)	(281,857		)	(77,642		)	60			(359,526		)
Equity earnings from subsidiaries	(306,884		)	(26,641		)	—			333,525			—
Interest (expense) income	(86,103		)	192			1			—			(85,910		)
Loss on extinguishment of debt	(82,005		)	—			—			—			(82,005		)
Other income (expense), net	—			1,422			(811		)	—			611
Loss before income taxes	(475,079		)	(306,884		)	(78,452		)	333,585			(526,830		)
Income tax expense	4,321			—			108			—			4,429
Net loss	(479,400		)	(306,884		)	(78,560		)	333,585			(531,259		)
Less: net loss attributable to noncontrolling interest	—			—			—			(51,919		)	(51,919		)
Net loss attributable to SandRidge Energy, Inc.	$	(479,400	)	$	(306,884	)	$	(78,560	)	$	385,504		$	(479,340	)
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, net	(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	)

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Condensed Consolidating Statements of Cash Flows



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2013
Net cash provided by (used in) operating activities	$	2,192,056		$	(2,142,481	)	$	68,705		$	3,177		$	121,457
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(421,876		)	—			—			(421,876		)
Proceeds from sale of assets	—			2,559,371			3			—			2,559,374
Other	—			16,947			—			(21,995		)	(5,048		)
Net cash provided by investing activities	—			2,154,442			3			(21,995		)	2,132,450
Cash flows from financing activities
Repayments of borrowings	(1,115,500		)	—			—			—			(1,115,500		)
Premium on debt redemption	(61,997		)	—			—			—			(61,997		)
Other	(29,395		)	3,208			(70,074		)	18,818			(77,443		)
Net cash (used in) provided by financing activities	(1,206,892		)	3,208			(70,074		)	18,818			(1,254,940		)
Net increase (decrease) in cash and cash equivalents	985,164			15,169			(1,366		)	—			998,967
Cash and cash equivalents at beginning of year	300,228			922			8,616			—			309,766
Cash and cash equivalents at end of period	$	1,285,392		$	16,091		$	7,250		$	—		$	1,308,733
Three Months Ended March 31, 2012
Net cash (used in) provided by operating activities	$	(48,637	)	$	202,554		$	78,163		$	(1,170	)	$	230,910
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(572,334		)	(29,507		)	—			(601,841		)
Proceeds from sale of assets	—			267,001			2,007			—			269,008
Other	—			56,658			1			(67,170		)	(10,511		)
Net cash used in investing activities	—			(248,675		)	(27,499		)	(67,170		)	(343,344		)
Cash flows from financing activities
Proceeds from the sale of royalty trust units	—			—			—			98,849			98,849
Other	(31,623		)	45,973			(50,095		)	(30,509		)	(66,254		)
Net cash (used in) provided by financing activities	(31,623		)	45,973			(50,095		)	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

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18. Subsequent Events

Events occurring after March 31, 2013 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this Quarterly Report have been included.

Royalty Trust Distributions. On April 25, 2013, the Royalty Trusts announced quarterly distributions for the three-month period ended March 31, 2013. The following distributions are expected to be paid on May 30, 2013 to holders of record as of the close of business on May 15, 2013 (in thousands):



Royalty Trust	Total Distribution		Amount to be Distributed to Third-Party Unitholders
Mississippian Trust I	$	15,909	$	12,087
Permian Trust	24,787		18,688
Mississippian Trust II	27,761		16,693
Total	$	68,457	$	47,468

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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 2012 Form 10-K. The Company’s discussion and analysis includes the following subjects:


•	Overview;


•	Results by Segment;


•	Consolidated Results of Operations;


•	Liquidity and Capital Resources;


•	Critical Accounting Policies and Estimates; and


•	Valuation Allowance.

The financial information with respect to the three months ended March 31, 2013 and 2012, 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

SandRidge is an independent oil and natural gas company concentrating on development and production activities in the Mid-Continent and Gulf of Mexico. The Company’s primary area of focus is the Mississippian formation in the Mid-Continent area of northern Oklahoma and Kansas. The Company owns and operates additional interests in the Mid-Continent, Gulf Coast, Permian Basin and West Texas Overthrust.

The Company also operates businesses and infrastructure systems that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and gas marketing business, a saltwater disposal system, an electrical transmission system and an oil field services business, which includes a drilling rig 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.

First Quarter 2013 Operational Highlights

Operational highlights for the first quarter of 2013 include the following:


•	Drilled 123 wells, excluding salt water disposal wells, in the Mid-Continent area during the three months ended March 31, 2013. Mid-Continent properties contributed approximately 3,751 MBoe, or 42%, of the Company’s total production during the three months ended March 31, 2013 compared to approximately 2,005 MBoe, or 33%, in the same period of 2012.


•	Gulf of Mexico properties acquired during the second quarter of 2012 contributed production of approximately 2,664 MBoe, or 30% of the Company’s total production, during the three months ended March 31, 2013.

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•	Production, revenues and direct operating expenses of the properties located in the Permian Basin sold in February 2013, described below, that are included in the Company’s results during the three months ended March 31, 2013 and 2012 were as follows:



	Three Months Ended March 31,
	2013		2012
Production (MBoe)	1,148		2,255
Revenue (in thousands)	$	68,027	$	161,765
Direct operating expenses (in thousands)	$	17,453	$	35,990

_______________

(1) Information for the three months ended March 31, 2013 is through February 26, 2013, the date of sale.

In addition to including activity for only a portion of the three-month period, the decrease in production, revenue and direct operating expenses for the three-month period ended March 31, 2013 compared to the same period in 2012 is a result of natural declines in production due to decreased drilling activity in the Permian Basin in advance of the sale.

First Quarter 2013 Developments and Outlook

Sale of Permian Properties. On February 26, 2013, the Company sold all of its oil and natural gas properties in the Permian Basin in west Texas, excluding the assets attributable to the SandRidge Permian Trust area of mutual interest (the “Permian Properties”), for net proceeds of $2.6 billion, subject to post-closing adjustments. The Company used a portion of the sale proceeds to fund the redemption of approximately $1.1 billion aggregate principal amount of outstanding senior notes, discussed below, and intends to use the remaining proceeds to fund its capital expenditures in the Mississippian formation and for general corporate purposes. The Company recorded a non-cash loss on the sale of $399.1 million, of which $71.7 million was allocated to noncontrolling interests. Additionally, the Company settled a portion of its existing oil derivative contracts in February 2013 prior to their respective maturities to reduce volumes hedged in proportion to the anticipated reduction in daily production volumes due to the sale, which resulted in a realized loss of approximately $29.6 million. Including the impact from the sale of the Permian Properties, the Company anticipates total production during 2013 of approximately 32.7MMBoe.

Redemption of Senior Fixed Rate Notes. In March 2013, the Company redeemed the outstanding $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and the outstanding $750.0 million aggregate principal amount of its 8.0% Senior Notes due 2018 for total consideration of $1,061.34 per $1,000 principal amount and $1,052.77 per $1,000 principal amount, respectively. The premium paid to redeem these notes and the associated unamortized debt issuance costs resulted in a loss on extinguishment of debt of $82.0 million for the three-month period ended March 31, 2013. The redemption of these senior notes will result in a reduction in interest expense from the anticipated total for the year ending December 31, 2013, of approximately $72.8 million.

Results by Segment

The Company operates in three business segments: exploration and production, drilling and oil field services and midstream 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 Royalty Trusts. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells and provides various oil field services. The midstream services segment is engaged in the purchasing, gathering, treating and selling of natural gas and the distribution of electricity to the Company’s exploration and production operations in the Mississippian formation.

Management evaluates the performance of the Company’s business segments based on income (loss) from operations, 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, profitability and contributions of each of the Company’s lines of business. Each of the Company’s business segments for the three months ended March 31, 2013 and 2012 is discussed below.

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Exploration and Production Segment

The Company 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 and are difficult to predict. 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 mitigates the risk that it will not have 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 its commodity derivative contracts. The average New York Mercantile Exchange (“NYMEX”) prices for oil and natural gas during the three months ended March 31, 2013 and 2012 are shown in the following table:



	Three Months Ended March 31,
	2013		2012
Oil (per Bbl)	$	94.30	$	102.99
Natural gas (per Mcf)	$	3.47	$	2.43

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Set forth in the table below is financial, production and pricing information for the three months ended March 31, 2013 and 2012.



	Three Months Ended March 31,
	2013			2012
Results (in thousands)
Revenues
Oil(1)	$	390,324		$	308,352
Natural gas	87,693			33,013
Other	3,393			1,755
Inter-segment revenue	(81		)	(77		)
Total revenues	481,329			343,043
Operating expenses
Production	133,442			84,067
Production taxes	9,439			12,254
Depreciation and depletion—oil and natural gas	157,526			87,066
Accretion of asset retirement obligations	9,779			2,607
Loss on derivative contracts	40,897			254,646
Loss on sale of assets	399,065			3,358
Other operating expenses	32,888			22,881
Total operating expenses	783,036			466,879
Loss from operations	$	(301,707	)	$	(123,836	)

Production data
Oil (MBbls)(1)	4,442			3,427
Natural gas (MMcf)	27,321			15,746
Total volumes (MBoe)	8,995			6,051
Average daily total volumes (MBoe/d)	99.9			66.5
Average prices—as reported(2)
Oil (per Bbl)(1)	$	87.88		$	89.99
Natural gas (per Mcf)	$	3.21		$	2.10
Total (per Boe)	$	53.14		$	56.42
Average prices—including impact of derivative contract settlements
Oil (per Bbl)(1)	$	91.03		$	86.27
Natural gas (per Mcf)	$	3.19		$	2.35
Total (per Boe)	$	54.65		$	54.96

__________________


(1)	Includes natural gas liquids.


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

Revenues

Exploration and production segment revenues increased $138.3 million, or 40.3%, in the three months ended March 31, 2013 from the same period in 2012, as a result of a 1,015 MBbls, or 29.6%, increase in oil production, a 11.6 Bcf, or 73.5%, increase in natural gas production and a $1.11 per Mcf, or 52.9%, increase in the average price received for natural gas production. The increase in oil and natural gas production in the three months ended March 31, 2013 compared to the same period in 2012 was due to production of approximately 2,664 MMBoe from properties located in the Gulf of Mexico that were acquired during the second quarter of 2012 combined with an increase in production from Mid-Continent properties of approximately 1,746 MBoe as a result of increased drilling throughout 2012 and the three-month period ended March 31, 2013. The increases were partially offset by a decrease in revenues from the Permian Basin due to the sale of the Permian Properties in February 2013 and natural declines in production as a result of decreased drilling activity in this area prior to the closing of the sale.

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Operating Expenses

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 $49.4 million, or 58.7%, in the first quarter of 2013 compared to the first quarter of 2012 primarily due to increased production. Combined production increased 2,944 MBoe, or 48.7%. On a per Boe basis, production expense for 2013 increased by $0.95, or 6.8%, to $14.84 per Boe during the three months ended March 31, 2013 from $13.89 per Boe for the comparable period in 2012. The slight increase in production expense on a per Boe basis is attributable to oil production from properties located in the Gulf of Mexico that were acquired during the second quarter of 2012. The increases were partially offset by a decrease in Permian Basin production expenses due to the sale of the Permian Properties in February 2013 and natural declines in production as a result of decreased drilling activity in this area prior to the closing of the sale.

Production taxes decreased by $2.8 million, or 23.0%, in the first quarter of 2013 compared to the first quarter of 2012. Approximately 30% of the Company’s oil and natural gas production for the three months ended March 31, 2013 was from production in the Gulf of Mexico which is not subject to production tax. In addition, wells drilled in the Mississippian formation in Oklahoma benefit from a tax credit incentive program that reduces the combined statutory rates applicable to the first four years of production from such wells.

Depreciation and depletion for the Company’s oil and natural gas properties increased $70.5 million, or 80.9%, for the first quarter of 2013 compared to the first quarter of 2012. The increase was due to a 48.7% increase in the Company’s combined production volume as well as an increase in the depreciation and depletion rate per Boe to $17.51 for the three months ended March 31, 2013 from $14.39 per Boe for the comparable period in 2012. The increase in the depreciation and depletion rate primarily resulted from the acquisition of properties located in the Gulf of Mexico during 2012.

Accretion on asset retirement obligations increased $7.2 million for the first quarter of 2013 compared to the first quarter of 2012 as a result of the increase in future plugging and abandonment obligations associated with the oil and natural gas properties located in the Gulf of Mexico that were acquired during the second quarter of 2012.

Loss on sale of assets increased $395.7 million for the first quarter of 2013 compared to the first quarter of 2012 primarily as a result of the $399.1 million loss on the sale of the Permian Properties in February 2013.

The following table summarizes the cash settlements and valuation gain and loss on the Company’s commodity derivative contracts, which are included in loss from operations for the exploration and production segment for the three months ended March 31, 2013 and 2012 (in thousands):



	Three Months Ended March 31,
	2013			2012
Realized (gain) loss
Realized loss on early settlements	$	29,623		$	—
Realized loss on amended contracts	—			117,108
Realized (gain) loss on settlements at contractual maturity	(13,538		)	8,348
Total realized loss	16,085			125,456
Unrealized loss	24,812			129,190
Loss on commodity derivative contracts	$	40,897		$	254,646

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.” Early settlements are not considered in the calculation of effective prices. In conjunction with the sale of the Permian Properties, the Company settled a portion of its existing oil derivative contracts prior to their contractual maturities, resulting in a realized loss of $29.6 million. The realized gain on settlements at contractual maturity for the three months ended March 31, 2013 was due primarily to lower oil prices at the time of settlement compared to the contract price for the Company’s oil price swaps. The realized loss for the three-month period ended March 31, 2012 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.

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Unrealized gain or loss on derivative contracts represents 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 months ended March 31, 2013 and 2012 was attributable to an increase in average oil prices at the end of the period compared to the average oil prices at the beginning of the period, or the contract price for contracts entered into during the period.

See “Consolidated Results of Operations” below for a discussion of other operating expenses.

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. The primary factors affecting the results of the Company’s drilling and oil field services segment are the rates received on rigs drilling for third parties, the number of days drilling for third parties and the amount of oil field services provided to third parties.

Set forth in the table below is financial and drilling rig information regarding the drilling and oil field services segment for the three months ended March 31, 2013 and 2012.



	Three Months Ended March 31,
	2013			2012
Results (in thousands)
Revenues	$	49,737		$	98,332
Inter-segment revenue	(32,367		)	(69,023		)
Total revenues	17,370			29,309
Operating expenses	26,335			25,830
(Loss) income from operations	$	(8,965	)	$	3,479

Drilling rig statistics
Average number of operational rigs owned during the period	30.0			30.0
Average number of rigs working for third parties	3.5			9.4
Number of days drilling for third parties	319			867
Average drilling revenue per day per rig drilling for third parties(1)	$	15,051		$	15,747

Rig status - end of period
Working for SandRidge	15			20
Working for third parties	3			10
Idle(2)	9			—
Total operational	27			30
Non-operational	4			1
Total rigs	31			31

____________________


(1)	Represents revenues from rigs working for third parties, excluding stand-by revenue, divided by the total number of days such drilling rigs were used by third parties during the period, excluding revenues for related rental equipment.


(2)	The Company’s rigs are primarily intended to drill for its own account; as such, the number of idle rigs does not significantly impact the consolidated results of operations.

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Drilling and oil field services segment revenues decreased $11.9 million to $17.4 million in the three-month period ended March 31, 2013 from the same period in 2012, due to a decrease in the number of rigs working for third parties and a decrease in supplies sold to and oil field services work performed for wells that had been operated by the Company in the Permian Basin prior to their sale. Decreases in drilling and oil field expenses due to the decrease in work performed in the Permian Basin were more than offset by costs associated with maintenance performed on rigs that were stacked as a result of the sale of the Permian Properties, resulting in an overall increase in drilling and oil field services segment expenses of $0.5 million during the three months ended March 31, 2013 compared to the same period in 2012. The decrease in revenue and slight increase in expenses resulted in a loss from operations of $9.0 million in the three-month period ended March 31, 2013 compared to income from operations of $3.5 million in the 2012 period.

Midstream Services Segment

Midstream services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business, and revenues from the distribution of electricity to the Company’s exploration and production operations in the Mississippian formation. On a consolidated basis, midstream and marketing revenues include 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 services segment is priced at a published daily or monthly index price. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead and to provide value-added services to customers. The Company has constructed an electrical transmission system in the Mid-Continent area to distribute electricity for use in the Mississippian formation at a lower cost than electricity provided by on-site generation. On a consolidated basis, revenues from the electrical transmission system represent the sale of electricity to third-party working interest owners in Company operated wells in the Mississippian formation. Electrical transmission system operating expenses represent the cost to purchase the electricity and other operating costs of the infrastructure. The primary factors affecting the results of the Company’s midstream services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas as well as the rates charged and volumes distributed by the electrical transmission system.

Set forth in the table below is financial information regarding the midstream services segment for the three months ended March 31, 2013 and 2012.



	Three Months Ended March 31,
	2013			2012
Results (in thousands)
Revenues	$	36,834		$	26,162
Inter-segment revenue	(24,696		)	(18,295		)
Total revenues	12,138			7,867
Operating expenses	14,597			10,594
Loss from operations	$	(2,459	)	$	(2,727	)

Gas Marketed
Volumes (MMcf)	2,048			2,397
Price	$	3.35		$	2.29

Midstream services segment total revenues and operating expenses for the three-month period ended March 31, 2013 increased $4.3 million and $4.0 million, respectively, from the same period in 2012. The increases in revenue and operating expenses were due to an increase of $1.06 per Mcf in the average price received for natural gas purchased and marketed in west Texas and an increase in revenue from and expenses related to electrical transmission services provided by the Company’s expanded electrical infrastructure in the Mid-Continent to third-party working interest owners. These increases were slightly offset by a 349 MMcf decrease in third-party volumes processed and marketed as a result of decreased natural gas production in west Texas.

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Consolidated Results of Operations

Revenues

The Company’s consolidated revenues for the three months ended March 31, 2013 and 2012 are presented in the table below.



	Three Months Ended March 31,
	2013		2012
	(in thousands)
Revenues
Oil and natural gas	$	478,017	$	341,365
Drilling and services	17,370		29,309
Midstream and marketing	13,032		8,306
Other	3,271		2,655
Total revenues(1)	$	511,690	$	381,635

___________________


(1)	Includes $45.7 million and $35.4 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three months ended March 31, 2013 and 2012, respectively.

The Company’s primary sources of revenue are discussed in “Results by Segment.” See discussion of oil and natural gas revenues under “Results by Segment—Exploration and Production Segment,” discussion of drilling and services revenues under “Results by Segment—Drilling and Oil Field Services Segment” and discussion of significant midstream and marketing revenues under “Results by Segment—Midstream Services Segment.”

Other revenues increased slightly for the three months ended March 31, 2013 compared to the same period in 2012 as revenues from the Bullwinkle and other offshore platforms, which were acquired as part of the Dynamic Acquisition, essentially offset a decrease in CO₂ volumes sold to third parties from the Company’s natural gas treating plants and CO₂ compression facilities. The Bullwinkle platform serves as a processing hub for deepwater production for third-party fields for which it receives production handling revenue. The decrease in CO₂ volumes sold to third parties was due primarily to decreased natural gas production in west Texas and the diversion of natural gas from the Company’s legacy natural gas treating plants to the Century Plant during the 2013 period.

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Expenses

The Company’s expenses for the three months ended March 31, 2013 and 2012 are presented below.



	Three Months Ended March 31,
	2013		2012
	(In thousands)
Expenses
Production	$	132,501	$	83,310
Production taxes	9,439		12,254
Cost of sales	16,317		17,560
Midstream and marketing	11,803		7,954
Depreciation and depletion—oil and natural gas	157,526		87,066
Depreciation and amortization—other	15,336		14,513
Accretion of asset retirement obligations	9,779		2,607
General and administrative	79,444		50,301
Loss on derivative contracts	40,897		254,646
Loss on sale of assets	398,174		3,080
Total expenses(1)	$	871,216	$	533,291

___________________

(1)

Includes $97.0 million and $33.3 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three months ended March 31, 2013 and 2012, respectively. The expenses attributable to noncontrolling interests in consolidated VIEs for the three months ended March 31, 2013 includes $71.7 million of allocated loss on sale of assets associated with the sale of the Permian Properties.

See discussion of production expenses, production taxes, depreciation and depletion—oil and natural gas, accretion of asset retirement obligations, loss on derivative contracts and loss on sale of assets under “Results by Segment—Exploration and Production Segment,” discussion of cost of sales under “Results by Segment—Drilling and Oil Field Services Segment” and discussion of significant midstream and marketing expenses under “Results by Segment—Midstream Services Segment.”

General and administrative expenses increased $29.1 million, or 57.9% for the three months ended March 31, 2013 from 2012. This increase is due primarily to an $8.8 million increase in compensation costs as a result of an increase in the number of Company employees, $13.0 million in severance costs primarily associated with a severance agreement with the Company’s former President and Chief Operating Officer, and $13.5 million in costs related to the TPG-Axon consent solicitation.

Other Income (Expense), Taxes and Net Income Attributable to Noncontrolling Interest

The Company’s other income (expense), taxes and net income attributable to noncontrolling interest for the three months ended March 31, 2013 and 2012 are presented in the table below.



	Three Months Ended March 31,
	2013			2012
	(In thousands)
Other income (expense)
Interest expense	$	(85,910	)	$	(66,965	)
Loss on extinguishment of debt	(82,005		)	—
Other income, net	611			2,468
Total other expense	(167,304		)	(64,497		)
Loss before income taxes	(526,830		)	(216,153		)
Income tax expense	4,429			71
Net loss	(531,259		)	(216,224		)
Less: net (loss) income attributable to noncontrolling interest	(51,919		)	1,954
Net loss attributable to SandRidge Energy, Inc.	$	(479,340	)	$	(218,178	)

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Interest expense for the three months ended March 31, 2013 and 2012 consisted of the following:



	Three Months Ended March 31,
	2013			2012
	(In thousands)
Interest expense
Interest expense on debt	$	86,236		$	55,544
Amortization of debt issuance costs, discounts and premium	3,680			3,173
Dynamic Acquisition committed financing fee	—			10,875
Interest rate swap loss	14			846
Capitalized interest	(4,020		)	(3,473		)
Total interest expense	$	85,910		$	66,965

Interest expense increased $18.9 million for the three months ended March 31, 2013 compared to 2012, primarily as a result of issuances of senior notes in 2012, partially offset by a reduction in interest expense associated with senior notes repurchased and redeemed in 2012. In addition, as a result of the Company’s election to issue senior notes to fund the cash portion of the Dynamic Acquisition rather than utilize previously secured committed financing, fees associated with the committed financing of $10.9 million were fully expensed during the three months ended March 31, 2012. See “Note 8—Long-Term Debt” to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of the Company’s long-term debt transactions in 2013 and 2012.

In connection with the March 2013 redemption of the Company’s 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018, the Company recognized a loss on extinguishment of debt of $82.0 million for the three months ended March 31, 2013. This loss represents the premium paid to redeem these notes and the unamortized debt issuance costs associated with the notes.

The Company's income tax expense of $4.4 million for the three-month period ending March 31, 2013 is primarily related to federal alternative minimum tax associated with the tax year ending December 31, 2013. The Company recorded a current liability and a corresponding deferred tax asset each in the amount of $4.4 million for the three-month period ended March 31, 2013. As a result of recording a deferred tax asset, the Company increased its valuation allowance against its net deferred tax asset by $4.4 million. Despite incurring federal alternative minimum tax, the Company's effective tax rate remains low as a result of having a valuation allowance on its net deferred tax asset.

Net income attributable to noncontrolling interest represents the portion of net income attributable to third-party ownership in the Company’s consolidated VIEs and subsidiaries. Net (loss) income attributable to noncontrolling interest decreased to a net loss of $51.9 million for the three-month period ended March 31, 2013 from net income of $2.0 million during the same period in 2012. The decrease was due primarily to the $71.7 million loss on the sale of the Permian Properties attributable to noncontrolling interest during the three-month period ended March 31, 2013, partially offset by net income from the Mississippian Trust II, which completed its initial public offering in April 2012.

Liquidity and Capital Resources

The Company’s primary sources of liquidity and capital resources are cash flows from operating activities, existing cash balances, funding commitments from third parties for drilling carries, the availability of borrowings under the senior credit facility, the issuance of equity and debt securities in the capital markets and proceeds from sales or other monetizations of assets. As described in “First Quarter 2013 Developments and Outlook,” the Company received approximately $2.6 billion, subject to post-closing adjustments, in February 2013 for the sale of its Permian Properties.

The Company’s primary uses of capital are expenditures related to its oil and natural gas properties, such as costs related to the drilling and completion of wells, including to fulfill its drilling commitments to the Royalty Trusts, the acquisition of oil and natural gas properties and other fixed assets, the payment of dividends on outstanding convertible perpetual preferred stock, interest payments on its outstanding debt and, from time to time, the redemption or repurchase of senior notes. The Company maintains access to funds that may be needed to meet capital funding requirements through its senior credit facility.

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The Company’s 2013 budget for capital expenditures, including expenditures related to the Company’s drilling programs for the Royalty Trusts, was revised in May 2013 to approximately $1.45 billion. The majority of the Company’s capital expenditures are discretionary and could be curtailed if the Company’s cash flows are less than expected 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, production targets contained in certain gathering and treating arrangements require the Company to incur capital expenditures or make associated shortfall payments.

Based on current cash balances, anticipated oil and natural gas prices and production, commodity derivative contracts in place, and funding commitments from third parties for drilling carries, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2013. 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 borrowings. The Company may increase or decrease planned capital expenditures depending on oil and natural gas prices, the availability of capital through asset sales and the issuance of additional equity or long-term debt.

The Company’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 2013, fixed price swap contracts are in place for only a portion of expected oil production for 2014 and 2015. No fixed price swap contracts are in place for any of the Company’s future natural gas production or for its oil production beyond 2015.

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 debt 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, 2013, the Company’s cash and cash equivalents were $1.3 billion, including $7.2 million attributable to the Company’s consolidated VIEs that is available only to satisfy obligations of the VIEs. The Company had approximately $3.2 billion in total debt outstanding and $30.2 million in outstanding letters of credit with no amount outstanding under its senior credit facility at March 31, 2013. As of and for the three-month period ended March 31, 2013, the Company was in compliance with applicable covenants under all of its senior notes and senior credit facility. As of May 1, 2013, the Company’s cash and cash equivalents were approximately $1.3 billion, including $6.5 million attributable to the Company’s consolidated VIEs. Additionally, there was no amount outstanding under the Company’s senior credit facility and $28.6 million in outstanding letters of credit.

Working Capital

The Company’s working capital balance fluctuates as a result of changes in the fair value of its outstanding commodity derivative instruments and due to fluctuations in the timing and amount of its collection of receivables and payment of expenditures related to its exploration and production operations. Absent any significant effects from its commodity derivative instruments, the Company historically has maintained 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.

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At March 31, 2013, the Company had a working capital surplus of $1.0 billion compared to a deficit of $27.6 million at December 31, 2012. Current assets and current liabilities at December 31, 2012 each included a $255.0 million escrow deposit received in conjunction with the agreement to sell the Permian Properties. This deposit had no impact on working capital at December 31, 2012. Excluding the change in current assets attributable to the escrow deposit, current assets increased $901.3 million at March 31, 2013, compared to current assets at December 31, 2012, primarily due to a $1.0 billion increase in cash and cash equivalents due to net proceeds received from the sale of the Permian Properties after funding the March 2013 redemption of the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018. This increase was slightly offset by a $56.1 million decrease in accounts receivable and amounts due from working interest partners as a result of a decrease in drilling activity due to the sale of the Permian Properties, and a $45.3 million decrease in the net asset position of the Company’s current derivative contracts due to an increase in oil prices since December 31, 2012. Excluding the change in current liabilities due to the escrow deposit, current liabilities decreased $133.2 million, primarily due to a $94.2 million decrease in accounts payable and accrued expenses as a result of a decrease in drilling activity due to the sale of the Permian Properties and a $27.4 million decrease in the Company’s current asset retirement obligation due to Gulf of Mexico plugging and abandonment obligations settled during the three-month period ended March 31, 2013.

A significant portion of the Company’s 2013 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, 2013 and 2012 are presented in the following table and discussed below:



	Three Months Ended March 31,
	2013			2012
	(In thousands)
Cash flows provided by operating activities	$	121,457		$	230,910
Cash flows provided by (used in) investing activities	2,132,450			(343,344		)
Cash flows (used in) provided by financing activities	(1,254,940		)	32,595
Net increase (decrease) in cash and cash equivalents	$	998,967		$	(79,839	)

Cash Flows from Operating Activities

The Company’s operating cash flow is primarily 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, and third-party demand for its drilling rigs and oil field services and the rates it is able to charge for these services.

Net cash provided by operating activities for the three-month period ended March 31, 2013 decreased from the comparable period in 2012 primarily due to an increase in cash paid during the three-month period ended March 31, 2013 to settle the Company’s outstanding accounts payable and plugging and abandonment obligations, primarily on Gulf of Mexico properties acquired during the second quarter of 2012.

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 provided by investing activities were $2.1 billion for the three-month period ended March 31, 2013 compared to cash flows used by investing activities of $343.3 million for the same period in 2012. The change was due primarily to proceeds received from the sale of the Permian Properties and a decrease in capital expenditures in the three-month period ended March 31, 2013. Proceeds from the sale of assets totaled $2.6 billion in the three-month period ended March 31, 2013 compared to $269.0 million in the same period in 2012.

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Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the three-month periods ended March 31, 2013 and 2012 are summarized below:



	Three Months Ended March 31,
	2013		2012
	(In thousands)
Capital Expenditures
Exploration and production	$	357,591	$	491,905
Drilling and oil field services	632		7,916
Midstream services	15,221		23,975
Other	15,268		45,862
Capital expenditures, excluding acquisitions	388,712		569,658
Acquisitions	5,048		10,511
Total	$	393,760	$	580,169

Cash Flows from Financing Activities

The Company’s financing activities used $1.3 billion of cash for the three-month period ended March 31, 2013 compared to providing $32.6 million of cash in the same period in 2012. Cash used in financing activities during the 2013 period was primarily comprised of the redemption of $1.1 billion aggregate principal amount of the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018 as well as the premium paid of $62.0 million in connection with the redemption of these notes, $51.3 million in distributions to royalty trust unitholders and $17.3 million in dividends paid on the Company’s convertible perpetual preferred stock.

Cash provided by financing activities during the three months ended March 31, 2012 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.

Indebtedness

Long-term debt consists of the following at March 31, 2013 (in thousands):



8.75% Senior Notes due 2020, net of $5,725 discount	$	444,275
7.5% Senior Notes due 2021, including premium of $4,230	1,179,230
8.125% Senior Notes due 2022	750,000
7.5% Senior Notes due 2023, net of $3,962 discount	821,038
Total debt	$	3,194,543

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. As of and during the three-month period ended March 31, 2013, the Company was in compliance with all of the covenants contained in the indentures governing its senior notes.

Maturities of Long-Term Debt. As of March 31, 2013, the aggregate maturities of long-term debt, excluding discounts and premiums, are all in years after 2017, with the earliest maturity in January 2020.

2013 Redemption of Senior Notes. In March 2013, the Company redeemed the outstanding $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and the outstanding $750.0 million aggregate principal amount of its 8.0% Senior Notes due 2018 for total consideration of $1,061.34 per $1,000 principal amount and $1,052.77 per $1,000 principal amount, respectively. The premium paid to redeem these notes and the associated unamortized debt issuance costs resulted in a loss on extinguishment of debt of $82.0 million for the three-month period ended March 31, 2013. The redemption was funded by a portion of the proceeds received from the sale of the Permian Properties. As of March 31, 2013, the Company was no longer obligated for future interest payments totaling $423.6 million on the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018 as a result of their redemption.

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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’s borrowing base is generally redetermined in April and October of each year, and was reaffirmed at $775.0 million in March 2013. The next redetermination is scheduled to take place in October 2013. Quarterly, the Company pays a commitment fee assessed at an annual rate of 0.5% on any available portion of the senior credit facility. 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.

As of March 31, 2013, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total 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 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 periods ended March 31, 2013, the Company was in compliance with all applicable financial covenants under the senior credit facility.

At March 31, 2013, the Company had no amount outstanding under the senior credit facility and $30.2 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $744.8 million at March 31, 2013. The senior credit facility matures in March 2017.

For more information about the senior credit facility and the senior notes, see Note 8 - Long-Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report.

Critical Accounting Policies and Estimates

For a description of the Company’s critical accounting policies and estimates, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2012 Form 10-K. 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.

Valuation Allowance

In 2008 and 2009, the Company recorded full cost ceiling impairments totaling $3.5 billion on its oil and natural gas assets, resulting in the Company being in a net deferred tax asset position. Management considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be realized and established a valuation allowance against the Company’s net deferred tax asset in the period ending December 31, 2008. The valuation allowance has been maintained since 2008. See “Note 13 - Income Taxes” to the unaudited condensed consolidated financial statements included in this Quarterly Report for more discussion on the establishment of the valuation allowance.

Management continues to closely monitor all available evidence, including both positive and negative, in considering whether to maintain a valuation allowance on its net deferred tax asset. Factors considered include, but are not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, the historical earnings of the Company and the prospects of future earnings. The Company's earnings have been trending upward leading to the Company having cumulative positive earnings for the 36-month period ending December 31, 2012. However, as a result of the Company closing the sale of the Permian Properties on February 26, 2013, the Company has cumulative negative earnings for the 36-month period ended March 31, 2013. See “Note 2 - Acquisitions and Divestitures” to the unaudited condensed consolidated financial statements included in this Quarterly Report for discussion of the sale of the Permian Properties. Based on net book value, historical costs and proved reserves as of February 26, 2013, the Company recorded a loss on the sale of $399.1 million, which caused the Company to report a loss for the three-month period ended March 31, 2013. The resulting cumulative negative earnings are not a definitive factor in determining to maintain a valuation allowance as all available evidence should be considered, but it is a significant piece of negative evidence in management’s analysis. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.

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In recent years, the Company has experienced significant earnings volatility due to substantial changes in the market price of natural gas. In 2008, the Company’s earnings were primarily derived from natural gas sales and during 2008 and 2009 the market price of natural gas declined significantly. Since 2009, natural gas prices have remained relatively low. As a result of a shift in strategy, the Company’s revenues are now primarily derived from oil sales and the Company continues to take additional steps to further ensure stockholder value and future profitability.

The Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Relatively modest drops in prices can significantly affect the Company’s financial results and impede its growth. Changes in oil and natural gas prices have a significant impact on the value of the Company’s reserves and on its cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company’s control. Due to these factors, management has placed a lower weight on the prospects of future earnings in its overall analysis of the valuation allowance.

In determining to maintain the valuation allowance, management concluded that the objectively verifiable negative evidence of cumulative negative earnings for the 36-month period ended March 31, 2013 is difficult to overcome with any forms of positive evidence that may exist. Accordingly, management has not changed its judgment regarding the need for a full valuation allowance against its net deferred tax asset. The valuation allowance against the Company's net deferred tax asset at December 31, 2012 was $496.6 million.

Additionally, at December 31, 2012, the Company had valuation allowances totaling $60.7 million against specific deferred tax assets for which management has determined it is more likely than not that such deferred tax assets will not be realized for various reasons. The valuation allowance against these specific deferred tax assets would not be impacted by the foregoing discussion.

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

General

This discussion 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 price 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 swaps. At March 31, 2013, 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	Two-way 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.
	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract.

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 oil and natural gas from a specified delivery point.

The Company’s oil 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 oil basis swap transactions are settled based upon the differential between the NYMEX or Argus West Texas Intermediate price and the Argus Louisiana Light Sweet price. The Company’s two-way and three-way oil collars are settled based upon the arithmetic average of NYMEX oil prices during the calculation period for the relevant contract. The Company’s natural gas fixed price swap transactions are settled based upon NYMEX prices, and the Company’s natural gas basis swap transactions are settled based upon the index price of natural gas at the Waha hub, a west Texas gas marketing and delivery center, or the Houston Ship Channel. The Company’s natural gas collars are settled based upon the NYMEX prices on the penultimate commodity business day for the relevant contract. Settlement for oil derivative contracts occurs in the succeeding month or quarter and natural gas derivative contracts are settled in the production month or quarter.

At March 31, 2013, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps



	Notional (MBbls)	Weighted Average Fixed Price
April 2013 - December 2013	10,142	$	98.64
January 2014 - December 2014	7,511	$	92.43
January 2015 - December 2015	5,076	$	83.69

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Natural Gas Price Swaps

Oil Basis Swaps

Oil Collars - Two-way

Oil Collars - Three-way



	Notional (MBbls)	Sold Put	Purchased Put	Sold Call
January 2014 - December 2014	8,213	$70.00	$90.20	$100.00
January 2015 - December 2015	2,920	$73.13	$90.82	$103.13

Natural Gas Collars



	Notional (MMcf)	Collar Range
April 2013 - December 2013	5,146	$3.78	—	$6.71
January 2014 - December 2014	937	$4.00	—	$7.78
January 2015 - December 2015	1,010	$4.00	—	$8.55

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.

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, 2013 and 2012 (in thousands):



	Three Months Ended March 31,
	2013		2012
Realized loss(1)	$	16,085	$	125,456
Unrealized loss	24,812		129,190
Loss on commodity derivative contracts	$	40,897	$	254,646

____________________


(1)	The three-month period ended March 31, 2013 included $29.6 million of realized losses related to early settlements. The three-month period ended March 31, 2012 included $117.1 million of non-cash realized losses on derivative contracts amended in January 2012.

See “Note 9—Derivatives” to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding the Company’s commodity derivatives.

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Credit Risk. All of the Company’s hedging transactions have been carried out in the over-the-counter market. The use of hedging transactions in over-the-counter markets 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 ratings 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.

A default by the Company under its senior credit facility constitutes a default under its derivative contracts with counterparties that are lenders under the senior credit facility. 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 derivative 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 that is a lender under the senior credit facility can be offset against amounts owed to such counterparty under the Company’s senior credit facility. As of March 31, 2013, the Company's open derivative contracts are with counterparties that share in the collateral supporting the Company's senior credit facility. As a result, the Company is not required to post additional collateral under derivative contracts. To secure their obligations under the derivative contracts novated by the Company, the Permian Trust and Mississippian Trust II have each given the counterparties to such contracts a lien on their royalty interest. See “Note 3—Variable Interest Entities” to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on the Permian Trust’s and the Mississippian Trust II’s derivative contracts.

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% of the borrowing base.

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 had no outstanding variable rate debt as of March 31, 2013.

The Company had a $350.0 million notional interest rate swap agreement which effectively fixed the variable interest rate on the Senior Floating Rate Notes at an annual rate of 6.69% for periods prior to their repurchase and redemption in the third quarter of 2012. The interest rate swap, which was not designated as a hedge, matured on April 1, 2013.

The following table summarizes the cash settlements and valuation gains and losses, which are included in interest expense in the Company’s accompanying unaudited condensed consolidated statements of operations, on the Company’s interest rate swap for the three-month periods ended March 31, 2013 and 2012 (in thousands):



	Three Months Ended March 31,
	2013			2012
Realized loss	$	2,409		$	2,200
Unrealized gain	(2,395		)	(1,354		)
Loss on interest rate swap	$	14		$	846

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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, 2013 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, 2013 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

Between December 2012 and March 2013, seven putative shareholder derivative actions were filed in state and federal court in Oklahoma:


•	Arthur I. Levine v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on December 19, 2012 in the U.S. District Court for the Western District of Oklahoma


•	Deborah Depuy v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 22, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Paul Elliot, on Behalf of the Paul Elliot IRA R/O, v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 29, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Dale Hefner v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 4, 2013 in the District Court of Oklahoma County, Oklahoma


•	Rocky Romano v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 22, 2013 in the District Court of Oklahoma County, Oklahoma


•	Joan Brothers v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on February 15, 2013 in the U.S. District Court for the Western District of Oklahoma

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•	Lisa Ezell, Jefferson L. Mangus, and Tyler D. Mangus v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on March 22, 2013 in the U.S. District Court for the Western District of Oklahoma

On April 10, 2013, the U.S. District Court for the Western District of Oklahoma consolidated the Levine, Depuy, Elliot, Brothers, and Ezell actions (the “Federal Shareholder Derivative Litigation”) under the caption “In re SandRidge Energy, Inc. Shareholder Derivative Litigation.” appointed a lead plaintiff and lead counsel, and ordered the lead plaintiff to file a consolidated amended complaint by May 1, 2013. The Company and the individual defendants in the Romano and Hefner actions (the “State Shareholder Derivative Litigation”) have moved to stay each of those actions in favor of the Federal Shareholder Derivative Litigation, in order to avoid duplicative proceedings, and also have requested, in the alternative, the dismissal of the State Shareholder Derivative Litigation. Following the filing of the defendants' initial motion to stay in the Romano case, the plaintiff agreed to stay the proceeding pending the Federal Shareholder Derivative Litigation, and the parties filed a joint motion to stay pending the Federal Shareholder Derivative Litigation. Because the lawsuits comprising the State Shareholder Derivative Litigation and the Federal Shareholder Derivative Litigation have only been recently filed, an estimate of reasonably possible losses associated with each of them, if any, cannot be made until the facts, circumstances and legal theories relating to the claims asserted and available defenses are fully disclosed and analyzed. The Company has not established any reserves relating to these actions.

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On January 7, 2013, Gerald Kallick, on behalf of himself and all other similarly situated stockholders, filed a putative class action complaint in the Court of Chancery of the State of Delaware against SandRidge Energy, Inc., and each of the Company's current directors. On January 31, 2013, the plaintiff filed an amended class action complaint. In his amended complaint, the plaintiff seeks: (i) declaratory relief that certain change-in-control provisions in the Company's indentures and credit agreement are invalid and unenforceable, (ii) declaratory relief that the directors breached their fiduciary duties by failing to approve the slate of directors proposed by TPG-Axon in its consent solicitation in order to disable the change-in-control provisions described above, (iii) a mandatory injunction requiring the directors to approve nominees for the Board of Directors submitted by TPG-Axon, (iv) a mandatory injunction prohibiting the Company from paying the Company's CEO his change-in-control benefits under his employment agreement in the event the CEO is removed as a director, but remains employed as the Company's CEO, (v) a mandatory injunction enjoining the defendants from impeding or interfering with the dissident stockholder's consent solicitation, (vi) a mandatory injunction requiring the defendants to disclose all material information related to the change-in-control provisions in the Company's indentures and credit agreement; and (vii) an order requiring the Company's current directors to account to the plaintiff and the putative class for alleged damages. On March 8, 2013, the court granted plaintiff's motion for a preliminary injunction, enjoining the Board, unless and until it approved the TPG-Axon nominees for purposes of the change in control provisions of the Company's outstanding debt agreements, from (i) soliciting any further consent revocations in opposition to TPG-Axon's consent solicitation, (ii) relying upon or otherwise giving effect to any consent revocations received by the Company as of March 11, 2013, and (iii) impeding the dissident stockholder's consent solicitation in any way. On March 9, 2013, the Board approved TPG-Axon's nominees for purposes of the change of control provisions in the Company's debt instruments. On March 13, 2013, TPG-Axon and the Board entered into a settlement agreement under which TPG-Axon's consent solicitation was withdrawn. As a result of these actions, the Company believes that many of the claims asserted by the plaintiff in the Kallick action have been rendered moot. On April 9, 2013, however, the plaintiff filed a motion to supplement his complaint to assert a new claim. The court has not yet ruled on the motion.

In addition the litigation described above, 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 2012 Form 10-K.

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

As part of the Company’s restricted stock program, the Company makes required tax payments on behalf of employees when their stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The shares withheld are initially recorded as treasury shares, then immediately retired. During the quarter ended March 31, 2013, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1, 2013 — January 31, 2013	1,038,068	$	6.82	N/A	N/A
February 1, 2013 — February 28, 2013	170,850	$	6.05	N/A	N/A
March 1, 2013 — March 31, 2013	569,019	$	5.46	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 President and Chief Financial Officer

Date: May 8, 2013

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EXHIBIT INDEX



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
3.1	Certificate of Incorporation of SandRidge Energy, Inc.	S-1	333-148956	3.1	1/30/2008
3.2	Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated July 16, 2010	10-Q	001-33784	3.2	8/9/2010
3.3	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	3/9/2009
4.1	Amendment No. 1 to Rights Agreement, dated as of April 29, 2013, between SandRidge Energy, Inc. and American Stock Transfer & Trust Company, LLC, as Rights Agent	8-K	001-33784	4.1	4/30/2013
10.1	Settlement Agreement, dated March 13, 2013, by and among the TPG-Axon Partners, L.P., TPG-Axon Management LP, TPG-Axon Partners GP, L.P., TPG-Axon GP, LLC, TPG-Axon International, L.P., TPG-Axon International GP, LLC and Dinakar Singh LLC and SandRidge Energy, Inc.	8-K	001-33784	10.1	3/13/2013
10.2	Separation Agreement, effective March 15, 2013 between SandRidge Energy, Inc. and Matthew K. Grubb	8-K	001-33784	10.1	3/15/2013
10.3	Separation Agreement, dated April 26, 2013 between SandRidge Energy, Inc. and Todd N. Tipton	8-K	001-33784	10.1	4/26/2013
10.4	Separation Agreement, dated April 26, 2013 between SandRidge Energy, Inc. and Rodney E. Johnson	8-K	001-33784	10.2	4/26/2013
31.1	Section 302 Certification—Chief Executive Officer					*
31.2	Section 302 Certification—Chief Financial Officer					*
32.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer					*
101.INS	XBRL Instance Document					*
101.SCH	XBRL Taxonomy Extension Schema Document					*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					*
101.DEF	XBRL Taxonomy Extension Definition Document					*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					*