SANDRIDGE ENERGY INC - Quarter Report: 2012 September (Form 10-Q)

Notional (MBbl)

Weighted Avg. Fixed Price

October 2012 — December 2012

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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 September 30, 2012



£	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 November 5, 2012, was 490,475,672.

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DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) of SandRidge Energy, Inc. (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 and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy, 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, they may not have the expected consequences to or effects on the Company’s business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The forward-looking statements in this respect speak only as of the date hereof. The Company disclaims any obligation to update or revise any forward-looking statements, unless required by law, and it cautions readers not to rely on them unduly. While the Company’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Risk Factors” in Item 1A of Part II of this Quarterly Report and in “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (the “2011 Form 10-K”).

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SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended September 30, 2012

INDEX



PART I. FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Changes in Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	69
ITEM 4.	Controls and Procedures	71

PART II. OTHER INFORMATION

ITEM 1.	Legal Proceedings	72
ITEM 1A.	Risk Factors	72
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	76
ITEM 6.	Exhibits	76

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PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)



	September 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	673,680		$	207,681
Accounts receivable, net	382,094			206,336
Derivative contracts	81,127			4,066
Inventories	3,343			6,903
Costs in excess of billings and estimated contract loss	36,133			—
Prepaid expenses	37,187			14,099
Other current assets	15,623			2,755
Total current assets	1,229,187			441,840
Oil and natural gas properties, using full cost method of accounting
Proved	11,784,691			8,969,296
Unproved	939,045			689,393
Less: accumulated depreciation, depletion and impairment	(5,167,938		)	(4,791,534		)
	7,555,798			4,867,155
Other property, plant and equipment, net	638,160			522,269
Restricted deposits	27,943			27,912
Derivative contracts	36,394			26,415
Goodwill	235,396			235,396
Other assets	121,369			98,622
Total assets	$	9,844,247		$	6,219,609
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	—		$	1,051
Accounts payable and accrued expenses	779,200			506,784
Billings and estimated contract loss in excess of costs incurred	—			43,320
Derivative contracts	18,503			115,435
Asset retirement obligation	117,044			32,906
Total current liabilities	914,747			699,496
Long-term debt	4,300,431			2,813,125
Derivative contracts	53,760			49,695
Asset retirement obligation	354,479			95,210
Other long-term obligations	15,810			13,133
Total liabilities	5,639,227			3,670,659
Commitments and contingencies (Note 12)
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at September 30, 2012 and December 31, 2011; aggregate liquidation preference of $265,000	3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at September 30, 2012 and December 31, 2011; aggregate liquidation preference of $200,000	2			2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at September 30, 2012 and December 31, 2011; aggregate liquidation preference of $300,000	3			3
Common stock, $0.001 par value, 800,000 shares authorized; 491,805 issued and 490,807 outstanding at September 30, 2012 and 412,827 issued and 411,953 outstanding at December 31, 2011	476			399
Additional paid-in capital	5,209,029			4,568,856
Treasury stock, at cost	(7,038		)	(6,158		)
Accumulated deficit	(2,544,473		)	(2,937,094		)
Total SandRidge Energy, Inc. stockholders’ equity	2,658,002			1,626,011
Noncontrolling interest	1,547,018			922,939
Total equity	4,205,020			2,548,950
Total liabilities and equity	$	9,844,247		$	6,219,609

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(Unaudited)
Revenues
Oil and natural gas	$	488,252		$	318,453		$	1,259,375		$	897,506
Drilling and services	27,760			25,547			90,701			75,118
Midstream and marketing	10,708			15,092			27,866			53,663
Other	6,078			4,661			14,925			15,088
Total revenues	532,798			363,753			1,392,867			1,041,375
Expenses
Production	137,033			86,580			342,824			242,371
Production taxes	12,967			10,368			36,222			33,610
Drilling and services	15,666			16,209			52,468			49,308
Midstream and marketing	10,674			14,624			27,187			52,780
Depreciation and depletion — oil and natural gas	166,126			84,472			392,452			229,759
Depreciation and amortization — other	16,497			13,551			46,357			39,918
Accretion of asset retirement obligation	9,053			2,253			19,625			7,039
General and administrative	46,781			36,272			158,798			108,364
Loss (gain) on derivative contracts	193,497			(596,736		)	(221,707		)	(489,096		)
Loss (gain) on sale of assets	375			(422		)	3,755			(1,148		)
Total expenses	608,669			(332,829		)	857,981			272,905
(Loss) income from operations	(75,871		)	696,582			534,886			768,470
Other income (expense)
Interest expense	(81,894		)	(58,952		)	(217,428		)	(180,077		)
Bargain purchase gain	—			—			124,446			—
Loss on extinguishment of debt	(3,056		)	—			(3,056		)	(38,232		)
Other income (expense), net	1,242			(672		)	3,629			662
Total other expense	(83,708		)	(59,624		)	(92,409		)	(217,647		)
(Loss) income before income taxes	(159,579		)	636,958			442,477			550,823
Income tax expense (benefit)	173			954			(103,414		)	(6,013		)
Net (loss) income	(159,752		)	636,004			545,891			556,836
Less: net income attributable to noncontrolling interest	10,668			60,895			111,626			74,055
Net (loss) income attributable to SandRidge Energy, Inc.	(170,420		)	575,109			434,265			482,781
Preferred stock dividends	13,881			13,881			41,644			41,702
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(184,301	)	$	561,228		$	392,621		$	441,079
(Loss) earnings per share
Basic	$	(0.39	)	$	1.41		$	0.88		$	1.11
Diluted	$	(0.39	)	$	1.16		$	0.81		$	0.97
Weighted average number of common shares outstanding
Basic	476,037			399,270			445,991			398,656
Diluted	476,037			497,700			537,300			496,428

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In thousands)



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

Nine Months Ended September 30, 2012
Balance at December 31, 2011	7,650	$	8	411,953		$	399	$	4,568,856		$	(6,158	)	$	(2,937,094	)	$	922,939		$	2,548,950
Issuance of common stock in acquisition	—	—		73,962		74		542,064			—			—			—			542,138
Issuance of units by royalty trust	—	—		—		—		—			—			—			587,086			587,086
Sale of royalty trust units	—	—		—		—		71,158			—			—			52,390			123,548
Distributions to noncontrolling interest owners	—	—		—		—		—			—			—			(127,023		)	(127,023		)
Purchase of treasury stock	—	—		—		—		—			(11,079		)	—			—			(11,079		)
Retirement of treasury stock	—	—		—		—		(11,079		)	11,079			—			—			—
Stock purchases — retirement plans, net of distributions	—	—		(124	)	—		1,580			(880		)	—			—			700
Stock-based compensation	—	—		—		—		36,445			—			—			—			36,445
Stock-based compensation excess tax benefit	—	—		—		—		8			—			—			—			8
Issuance of restricted stock awards, net of cancellations	—	—		5,016		3		(3		)	—			—			—			—
Net income	—	—		—		—		—			—			434,265			111,626			545,891
Convertible perpetual preferred stock dividends	—	—		—		—		—			—			(41,644		)	—			(41,644		)
Balance at September 30, 2012	7,650	$	8	490,807		$	476	$	5,209,029		$	(7,038	)	$	(2,544,473	)	$	1,547,018		$	4,205,020

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Nine Months Ended September 30,
	2012			2011
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	545,891		$	556,836
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	438,809			269,677
Accretion of asset retirement obligation	19,625			7,039
Debt issuance costs amortization	11,348			8,624
Amortization of discount (premium) on long-term debt, net	1,940			1,766
Interest accretion on notes receivable	(495		)	—
Bargain purchase gain	(124,446		)	—
Loss on extinguishment of debt	3,056			38,232
Deferred income taxes	(103,328		)	(6,986		)
Unrealized gain on derivative contracts	(234,705		)	(527,166		)
Realized loss on amended derivative contracts	117,108			—
Realized (gain) loss on financing derivative contracts	(17,783		)	4,870
Loss (gain) on sale of assets	3,755			(1,148		)
Investment (income) loss	(784		)	653
Stock-based compensation	33,128			28,458
Changes in operating assets and liabilities	(108,889		)	(59,232		)
Net cash provided by operating activities	584,230			321,623
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(1,625,737		)	(1,300,180		)
Acquisitions, net of cash received	(837,019		)	(22,751		)
Proceeds from sale of assets	422,171			624,767
Net cash used in investing activities	(2,040,585		)	(698,164		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	1,850,344			2,033,000
Repayments of borrowings	(366,029		)	(2,130,042		)
Premium on debt redemption	(825		)	(30,338		)
Debt issuance costs	(48,220		)	(19,652		)
Proceeds from issuance of royalty trust units	587,086			917,528
Proceeds from the sale of royalty trust units	123,548			—
Noncontrolling interest distributions	(127,023		)	(21,182		)
Stock issuance expense	—			(231		)
Stock-based compensation excess tax benefit	8			52
Purchase of treasury stock	(12,807		)	(12,048		)
Dividends paid — preferred	(45,025		)	(46,243		)
Cash (paid) received on settlement of financing derivative contracts	(38,703		)	5,271
Net cash provided by financing activities	1,922,354			696,115
NET INCREASE IN CASH AND CASH EQUIVALENTS	465,999			319,574
CASH AND CASH EQUIVALENTS, beginning of year	207,681			5,863
CASH AND CASH EQUIVALENTS, end of period	$	673,680		$	325,437
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	66,033		$	22,010
Convertible perpetual preferred stock dividends payable	$	13,191		$	13,191
Adjustment to oil and natural gas properties for estimated contract loss	$	10,000		$	19,000
Common stock issued in connection with acquisition	$	542,138		$	—

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

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

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements as of December 31, 2011 have been derived from the audited financial statements contained in the Company’s 2011 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2011 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2011 Form 10-K.

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 2011 Form 10-K.

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

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

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

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Company’s control such as 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’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 10 for the Company’s open oil and natural gas commodity derivative contracts.

The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating agreements. 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 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 sales or other monetizations of assets to fund its capital expenditures. Based on current cash balances, anticipated oil and natural gas prices and production, commodity derivative contracts in place, availability under the senior credit facility, potential access to capital markets, potential sales of

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

royalty trust units and potential sales of working interests, including those with associated 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 2012 and 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. A substantial or extended decline in oil or natural gas prices could also adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. See Note 9 for discussion of the financial covenants in the senior credit facility.

Recent Accounting Pronouncements. In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”), which clarifies the FASB’s intent regarding the application of existing fair value measurements and requires additional disclosure of information regarding valuation processes and inputs used. The new disclosure requirements, which are effective for interim and annual reporting periods beginning after December 15, 2011, were implemented by the Company in the first quarter of 2012. The implementation of ASU 2011-04 had no impact on the Company’s financial position or results of operations. See Note 4 for discussion of the Company’s fair value measurements.

In September 2011, the FASB issued Accounting Standards Update 2011-08, “Testing Goodwill for Impairment” (“ASU 2011-08”), which allows an entity the option of performing a qualitative assessment to determine whether it is necessary to perform the current two-step annual impairment test. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit more-likely-than-not exceeds the carrying amount, the two-step impairment test is not required. ASU 2011-08 does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test goodwill annually for impairment or amend the requirement to test goodwill for impairment between annual tests if events or circumstances warrant. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 did not impact the carrying value of the Company’s goodwill. See Note 6 for discussion of goodwill and the Company's annual impairment assessment.

Recent Accounting Pronouncement Not Yet Adopted. In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), which requires disclosures about the nature of an entity's rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance is effective for interim and annual periods beginning on or after January 1, 2013. As the additional requirements under ASU 2011-11, which will be implemented January 1, 2013, pertain to disclosures of offsetting assets and liabilities, no effect on the Company's financial position or results of operations is expected.

2. Acquisitions and Divestitures

2011 Divestitures

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


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


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


•	In November 2011, the Company sold its east Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $225.4 million, net of fees and post-closing adjustments.

2012 Acquisitions and Divestitures

Dynamic Acquisition. The Company acquired 100% of the equity interests of Dynamic Offshore Resources, LLC (“Dynamic”) on April 17, 2012 for total consideration of approximately $1.2 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of the Company’s common stock (the “Dynamic Acquisition”). Dynamic is an oil and natural gas exploration, development and production company with operations in the Gulf of Mexico. The Dynamic 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.

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The allocation of the purchase price as of April 17, 2012, is still preliminary, primarily with respect to deferred tax amounts and certain accruals, and is based on information that was available to management at the time these unaudited condensed consolidated financial statements were prepared. 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 the Company’s 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 by the second quarter of 2013. The Company believes the estimates used in the preliminary 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 date of the acquisition. No adjustments were made to the initial purchase price allocation in the third quarter of 2012. 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	$	125,588
Asset retirement obligation(4)	315,922
Long-term deferred tax liability(5)	103,328
Other non-current liabilities	4,469
Amount attributable to liabilities assumed	549,307
Total purchase price plus liabilities assumed	1,784,536

Estimated Fair Value of Assets Acquired
Current assets	143,042
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	1,908,982
Bargain purchase gain(7)	$	(124,446	)

____________________

(1)

Consideration paid by SandRidge consisted of 73,961,554 shares of SandRidge common stock and cash of approximately $680.0 million. The value of the stock consideration is based upon the closing price of $7.33 per share of SandRidge common stock on April 17, 2012, 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 SandRidge of $13.1 million at closing.


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

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(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. The Company 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.

The market assumptions as to 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.

The following unaudited pro forma combined results of operations for the three and nine-month periods ended September 30, 2012 and September 30, 2011 are presented as though the Dynamic Acquisition had been completed as of the beginning of the earliest period presented, or January 1, 2011. The pro forma combined results of operations for the three and nine-month periods ended September 30, 2012 and 2011 have been prepared by adjusting the historical results of the Company to include the historical results of Dynamic, certain reclassifications to conform Dynamic’s presentation and accounting policies to the Company’s and the impact of the bargain purchase gain resulting from the preliminary purchase price allocation. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Dynamic Acquisition or any estimated costs that will be incurred to integrate Dynamic. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012		(1)		2011		2012		(2	)	2011		(3	)
	(In thousands, except per share data)
Revenues	$	532,798			$	484,343	$	1,570,801			$	1,390,743
Net (loss) income	$	(159,293		)	$	719,182	$	333,989			$	879,553
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(183,842		)	$	644,406	$	180,719			$	763,336
Pro forma net (loss) income per common share
Basic	$	(0.39		)	$	1.36	$	0.38			$	1.62
Diluted	$	(0.39		)	$	1.15	$	0.38			$	1.41

____________________


(1)	Pro forma net loss, loss applicable to SandRidge Energy, Inc. common stockholders and net loss per common share exclude $0.5 million of transaction costs incurred and included in general and administrative expense in the accompanying unaudited condensed consolidated statements of operations for the three-month period ended September 30, 2012.

(2)

Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and net income per common share exclude a $124.4 million bargain purchase gain, a $103.3 million partial valuation allowance release included in income tax benefit, $10.9 million of fees incurred to secure financing for the Dynamic Acquisition included in interest expense and $12.9 million of transaction costs incurred and included in general and administrative expense in the accompanying unaudited condensed consolidated statements of operations for the nine-month period ended September 30, 2012.

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(3)	Pro forma net income, income applicable to SandRidge Energy, Inc. common stockholders and net income per common share include a $124.4 million bargain purchase gain, a $103.3 million partial valuation allowance release, $10.9 million of fees incurred to secure financing for the Dynamic Acquisition and $13.0 million of estimated transaction costs.

Revenues of $123.3 million and $231.3 million and income from operations of $21.1 million and $49.6 million associated with Dynamic have been included in the accompanying unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2012, respectively. Additionally, the Company has incurred $0.5 million and $12.9 million in acquisition-related costs for the Dynamic Acquisition, which have been included in general and administrative expense in the accompanying unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2012, respectively.

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 $38.5 million, net of purchase price adjustments and subject to 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 the June 20, 2012 acquisition date, 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 as to 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.

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. Acquisition-related costs of $0.1 million and $0.2 million have been expensed as incurred in general and administrative expense in the accompanying unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2012, respectively. Revenues of $13.0 million and $13.6 million and earnings of $9.0 million and $9.1 million generated by the acquired properties have been included in the accompanying unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2012, respectively.

The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of June 20, 2012. The purchase price allocation is preliminary and subject to adjustment upon the final closing settlement to be completed during the fourth quarter of 2012.



	(In thousands)
Consideration paid
Cash, net of purchase price adjustments	$	38,458
Fair value of identifiable assets acquired and liabilities assumed
Proved developed and undeveloped properties	$	93,901
Asset retirement obligation	(55,443		)
Total identifiable net assets	$	38,458

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The following unaudited pro forma combined results of operations for the three and nine-month periods ended September 30, 2012 and September 30, 2011 are presented as though the Company acquired the Gulf of Mexico Properties as of the beginning of the earliest period presented, or January 1, 2011. The pro forma combined results of operations for the three and nine-month periods ended September 30, 2012 and 2011 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 September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
	(In thousands, except per share data)
Revenues	$	532,798		$	384,870	$	1,421,283	$	1,107,118
Net (loss) income	$	(159,702	)	$	641,447	$	548,221	$	580,591
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(184,251	)	$	566,671	$	394,951	$	464,834
Pro forma net (loss) income per common share
Basic	$	(0.39	)	$	1.42	$	0.89	$	1.17
Diluted	$	(0.39	)	$	1.17	$	0.81	$	1.02

Sale of Working Interests and Associated Drilling Carry Commitments

During 2011 and the first quarter of 2012, the Company entered into two transactions whereby the Company sold non-operated working interests in the Mississippian formation. Each of these transactions is described in more detail below. In these transactions, the Company received aggregate cash proceeds of $500.0 million for the sale of working interests and received drilling carry commitments to fund a portion of its future drilling and completion costs totaling $1.0 billion. For accounting purposes, initial cash proceeds from these transactions were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and amounts received or billed during 2011 and 2012 attributable to the drilling carry reduced the Company’s capital expenditures. These transactions and the associated drilling carries as of September 30, 2012, are as follows:



Partner	Closing Date	Proceeds Received At Closing(1)		Drilling Carry Recorded		Drilling Carry Remaining
		(In millions)
Atinum MidCon I, LLC	September 2011	$	287.0	$	115.9	$	134.1
Repsol E&P USA, Inc.	January 2012	272.5		146.1		603.9
		$	559.5	$	262.0	$	738.0

____________________

(1) Includes amounts related to the drilling carry.

In September 2011, the Company sold to Atinum MidCon I, LLC (“Atinum”) non-operated working interests equal to approximately 113,000 net acres in the Mississippian formation in northern Oklahoma and southern Kansas for approximately $250.0 million. In addition, Atinum agreed to pay the development costs related to its working interest, as well as a portion of the Company’s development costs equal to Atinum’s working interest for wells within an area of mutual interest up to $250.0 million. The Company expects Atinum’s funding of the Company’s development cost for wells within the area of mutual interest to occur over a period not to exceed three years.

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

During the nine-month period ended September 30, 2012, the Company recorded approximately $243.1 million for Atinum’s and Repsol’s drilling carries, which reduced the Company’s capital expenditures for the period.

3. Variable Interest Entities

The Company consolidates the activities of variable interest entities (“VIEs”) of which it is the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements.

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

Grey Ranch Plant, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch Plant, L.P. (“GRLP”) is a limited partnership that operates the Company’s Grey Ranch plant (the “Plant”) located in Pecos County, Texas. The Company has long-term operating and gathering agreements with GRLP and also owns a 50% interest in GRLP, which represents a variable interest. Income or losses of GRLP are allocated to the partners based on ownership percentage and any operating or cash shortfalls require contributions from the partners. The Company has determined that GRLP qualifies as a VIE 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.

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GRLP’s assets can be used to settle only its own obligations and not other obligations of the Company. GRLP’s creditors have no recourse to the general credit of the Company. Although GRLP is included in the Company’s consolidated financial statements, the Company’s legal interest in GRLP’s assets is limited to its 50% ownership. At September 30, 2012 and December 31, 2011, $7.6 million and $8.2 million, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at September 30, 2012 and December 31, 2011 consisted of the following (in thousands):



	September 30, 2012		December 31, 2011
Cash and cash equivalents	$	1,185	$	1,702
Accounts receivable, net	22		24
Inventory	109		109
Prepaid expenses	—		176
Total current assets	1,316		2,011
Other property, plant and equipment, net	14,126		14,985
Total assets	$	15,442	$	16,996
Accounts payable and accrued expenses	$	289	$	280
Total liabilities	$	289	$	280

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. Conveyance of the royalty interests was recorded at the Company’s historical cost. 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)

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 during the nine-month period ended September 30, 2012. These transactions decreased the Company’s beneficial interests in the Royalty Trusts. See further discussion of the unit sales below. In addition, the Company sold 688,000 of its Mississippian Trust I common units in October 2012. See Note 19 for further discussion of this sale.


(2)	At the time each Royalty Trust terminates, 50% of the royalty interests conveyed to the Royalty Trust will automatically revert to the Company.

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 and nine-month periods ended September 30, 2012 and 2011 as follows (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Total distributions	$	75.2	$	29.9	$	193.3	$	29.9
Distributions to third-party unitholders	$	50.2	$	18.4	$	127.0	$	18.4

There were no distributions declared and paid during the first six months of 2011. See Note 19 for discussion of the Royalty Trusts’ distribution declarations in November 2012.

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 September 30, 2012 or December 31, 2011.

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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, Permian Trust and 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 (subject to completion of an initial minimum number of wells for the Mississippian Trust II) and the total amount that may be recovered by each Royalty Trust is proportionately reduced. As of September 30, 2012, the total maximum amount recoverable by the Royalty Trusts under the liens was approximately $464.7 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. In April 2012, the Company novated certain additional derivative contracts underlying the derivatives agreement to the Permian Trust. The tables below present the open oil and natural gas commodity derivative contracts at September 30, 2012 underlying the derivatives agreements, including the contracts novated to the Permian Trust and the Mississippian Trust II. The combined volume in the tables below reflects the total volume of the Royalty Trusts’ open oil and natural gas commodity derivative contracts. See Note 10 for further discussion of the derivatives agreement between the Company and each Royalty Trust.

Oil Price Swaps Underlying the Derivatives Agreements



	Notional (MBbl)	Weighted Avg. Fixed Price
October 2012 — December 2012	307	$	104.13
January 2013 — December 2013	1,814	$	103.03
January 2014 — December 2014	2,053	$	100.78
January 2015 — December 2015	667	$	101.02

Natural Gas Collars Underlying the Derivatives Agreements



	Notional (MMBtu)	Collar Range
October 2012 — December 2012	201	$4.00 - 6.20
January 2013 — December 2013	858	$4.00 - 7.15
January 2014 — December 2014	937	$4.00 - 7.78
January 2015 — December 2015	1,010	$4.00 - 8.55

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



	Notional (MBbl)	Weighted Avg. Fixed Price
October 2012 — December 2012	327	$	104.45
January 2013 — December 2013	1,021	$	103.35
January 2014 — December 2014	799	$	100.59
January 2015 — March 2015	104	$	100.90

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The Company’s ownership interest in each Royalty Trust and its loan commitment with each Royalty Trust constitute variable interests. 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 ownership of the subordinated units and the loan commitments, 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 are limited to its ownership of the Royalty Trusts units. At September 30, 2012 and December 31, 2011, $1,539.4 million and $914.7 million, 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 September 30, 2012 and December 31, 2011 consisted of the following (in thousands):



	September 30, 2012			December 31, 2011
Cash and cash equivalents(1)	$	8,223		$	3,151
Accounts receivable	29,240			18,357
Derivative contracts	11,088			1,499
Total current assets	48,551			23,007
Investment in royalty interests(2)	1,325,942			858,795
Less: accumulated depletion	(80,386		)	(24,404		)
	1,245,556			834,391
Derivative contracts	10,629			5,668
Total assets	$	1,304,736		$	863,066

Accounts payable and accrued expenses	$	2,844		$	486
Total liabilities	$	2,844		$	486

____________________


(1)	Includes $3.0 million and $2.0 million held by the trustee at September 30, 2012 and December 31, 2011, respectively, 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 nine-month period ended September 30, 2012 for total proceeds of $123.5 million. 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 continues to consolidate the activities of the Royalty Trusts. The Company’s beneficial interests in the Royalty Trusts at September 30, 2012 and December 31, 2011 were as follows:



	Beneficial Interest Owned by Company
	September 30, 2012		December 31, 2011
Mississippian Trust I	29.3	%	38.4	%
Permian Trust	30.5	%	34.3	%
Mississippian Trust II	39.9	%	N/A

Piñon Gathering Company, LLC. The Company has a gas gathering and operations and maintenance agreement with Piñon Gathering Company, LLC (“PGC”) through June 30, 2029. Under the gas gathering agreement, the Company is required to compensate PGC for any throughput shortfalls below a required minimum volume. By guaranteeing a minimum throughput, the Company absorbs the risk that lower than projected volumes will be gathered by the gathering system. Therefore, PGC is a VIE. Other than as required under the gas gathering and operations and maintenance agreements, the Company has not provided any support to PGC. While the Company operates the assets of PGC as directed under the operations and management agreement, the member and managers of PGC have the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. As the Company does not have the ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company is not the primary beneficiary of PGC. Therefore, the results of PGC’s activities are not consolidated into the Company’s financial statements. The amounts due from and due to PGC as of September 30, 2012 and December 31, 2011, respectively, included in the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):



	September 30, 2012		December 31, 2011
Accounts receivable due from PGC	$	2,578	$	3,205
Accounts payable due to PGC	$	5,627	$	4,603

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 is deemed to approximate fair value.

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 other valuation techniques 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 values of the Company’s diesel fixed price swaps and 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 diesel fixed price swaps is the estimate of diesel prices. Significant (increases) decreases in diesel prices could result in a significantly (lower) higher fair value measurement. 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 Company’s level 3 fair value measurements at September 30, 2012 are included in the table below.



Derivative Type	Unobservable Input	Range(1)			Weighted Average(1)	Fair Value
						(in thousands)
Diesel fixed price swaps	Diesel price forward curve	$3.22	–	$3.30	$3.26	$	685
Oil basis swaps	Oil basis differential forward curve	$17.73	–	$19.95	$18.53	$	(502	)

____________________

(1)Diesel prices are per gallon and oil prices are per barrel.

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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):

September 30, 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	$	27,943	$	—	$	—	$	—		$	27,943
Commodity derivative contracts	—		165,533		685		(48,697		)	117,521
Investments	10,907		—		—		—			10,907
	$	38,850	$	165,533	$	685	$	(48,697	)	$	156,371
Liabilities
Commodity derivative contracts	$	—	$	115,642	$	502	$	(48,697	)	$	67,447
Interest rate swap	—		4,816		—		—			4,816
	$	—	$	120,458	$	502	$	(48,697	)	$	72,263

December 31, 2011



	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	$	27,912	$	—	$	—	$	—		$	27,912
Commodity derivative contracts	—		62,746		397		(32,662		)	30,481
Investments	7,138		—		—		—			7,138
	$	35,050	$	62,746	$	397	$	(32,662	)	$	65,531
Liabilities
Commodity derivative contracts	$	—	$	182,694	$	4,650	$	(32,662	)	$	154,682
Interest rate swap	—		10,448		—		—			10,448
	$	—	$	193,142	$	4,650	$	(32,662	)	$	165,130

____________________

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

Fair values related to the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap were transferred from Level 3 to Level 2 in the fourth quarter of 2011 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the three and nine-month periods ended September 30, 2012 and 2011, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

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The tables below set forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and nine-month periods ended September 30, 2012 and 2011 (in thousands):



	Three Months Ended September 30,
	2012			2011
	Commodity Derivative Contracts			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, June 30	$	5,013		$	(293,633	)	$	(15,285	)	$	(308,918	)
Total gain or losses (realized/unrealized)	(4,261		)	596,736			(555		)	596,181
Settlements	(569		)	4,688			2,520			7,208
Balance of Level 3, September 30	$	183		$	307,791		$	(13,320	)	$	294,471



	Nine Months Ended September 30,
	2012			2011
	Commodity Derivative Contracts			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, December 31	$	(4,253	)	$	(205,860	)	$	(16,694	)	$	(222,554	)
Total gain or losses (realized/unrealized)	(3,872		)	489,096			(3,631		)	485,465
Purchases	5,697			—			—			—
Settlements	2,611			24,555			7,005			31,560
Balance of Level 3, September 30	$	183		$	307,791		$	(13,320	)	$	294,471

Unrealized losses on the Company’s Level 3 commodity derivative contracts of $4.8 million and $1.3 million for the three and nine-month periods ended September 30, 2012, respectively, have been included in (loss) gain on derivative contracts in the accompanying unaudited condensed consolidated statements of operations.

See Note 10 for further discussion of the Company’s derivative contracts.

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Fair Value of Debt

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 September 30, 2012 and December 31, 2011 were as follows (in thousands):



	September 30, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	—	$	—	$	339,381	$	350,000
9.875% Senior Notes due 2016(1)	398,395		356,117		396,568		354,579
8.0% Senior Notes due 2018	787,500		750,000		765,000		750,000
8.75% Senior Notes due 2020(2)	483,750		443,984		475,875		443,568
7.5% Senior Notes due 2021(3)	1,207,313		1,179,426		909,000		900,000
8.125% Senior Notes due 2022	796,875		750,000		—		—
7.5% Senior Notes due 2023(4)	847,688		820,904		—		—

____________________

(1)Carrying value is net of $9,383 and $10,921 discount at September 30, 2012 and December 31, 2011, respectively.

(2)Carrying value is net of $6,016 and $6,432 discount at September 30, 2012 and December 31, 2011, respectively.


(3)	Carrying value includes a premium of $4,426 at September 30, 2012, applicable to notes issued in August 2012. See Note 9 for discussion of this note issuance.

(4)Carrying value is net of $4,096 discount at September 30, 2012.

The carrying values of the Company’s remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 9 for discussion of the Company’s long-term debt.

5. Property, Plant and Equipment

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



	September 30, 2012			December 31, 2011
Oil and natural gas properties
Proved	$	11,784,691		$	8,969,296
Unproved	939,045			689,393
Total oil and natural gas properties	12,723,736			9,658,689
Less accumulated depreciation, depletion and impairment	(5,167,938		)	(4,791,534		)
Net oil and natural gas properties capitalized costs	7,555,798			4,867,155
Land	17,693			14,196
Non-oil and natural gas equipment(1)	749,613			668,391
Buildings and structures	186,232			133,147
Total	953,538			815,734
Less accumulated depreciation and amortization	(315,378		)	(293,465		)
Other property, plant and equipment, net	638,160			522,269
Total property, plant and equipment, net	$	8,193,958		$	5,389,424

____________________


(1)	Includes cumulative capitalized interest of approximately $9.9 million and $6.7 million at September 30, 2012 and December 31, 2011, respectively.

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There were no full cost ceiling impairments during the three or nine-month periods ended September 30, 2012 or 2011. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both September 30, 2012 and December 31, 2011 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the accompanying unaudited condensed consolidated balance sheets.

6. Goodwill

At September 30, 2012, the Company had $235.4 million of goodwill as a result of the excess consideration over the fair value of net assets acquired in the acquisition of Arena Resources, Inc. (“Arena”) in July 2010. The Company assigned the goodwill to its exploration and production segment, which is the reporting unit for impairment testing purposes. Under the discounted cash flow approach, the reporting unit’s anticipated future cash flows, primarily based on projected oil and natural gas revenues, operating expenses and capital expenditures, are discounted using a weighted average cost of capital rate to estimate the fair value for the reporting unit. The Company’s annual evaluation of goodwill was completed during the third quarter of 2012. As the reporting unit’s anticipated future cash flows were significantly greater than the reporting unit’s carrying value, no impairment was recognized. In addition to performing an annual impairment assessment, the Company monitors potential impairment indicators throughout the year.

7. Other Assets

Other assets consist of the following (in thousands):



	September 30, 2012		December 31, 2011
Debt issuance costs, net of amortization	$	86,365	$	51,724
Notes receivable on asset retirement obligations	11,215		—
Investments	10,907		7,138
Production tax credit receivable	7,027		7,665
Lease broker advances	1,206		13,086
Development advance	—		16,777
Other	4,649		2,232
Total other assets	$	121,369	$	98,622

8. Construction Contracts

The Company accounts for its two construction contracts using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract gains or losses will be recorded as development costs within the Company’s oil and natural gas properties as part of the full cost pool. Contract losses are recorded at the time it is determined that a loss will be incurred. Contract gains, if any, are recorded at the end of the project.

Century Plant. The Company is constructing the Century Plant, a 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”). Under the terms of the agreement, the Company is constructing the Century Plant and Occidental is paying the Company a minimum of 100% of the contract price, or $800.0 million, plus any subsequently agreed upon revisions, through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Company will complete the Century Plant in two phases. During the third quarter of 2012, Phase I was completed and Occidental took ownership and began operating the Phase I assets for the purpose of separating and removing CO2 from the delivered natural gas stream. Phase II is currently undergoing performance testing with transfer to Occidental expected in the first quarter of 2013, at which time Occidental will take ownership and begin operating the Phase II related assets. The Company has recorded additions of $140.0 million (including $10.0 million during the nine-month period ended September 30, 2012 and none during the three-month period ended September 30, 2012) to its oil and natural gas properties for the estimated loss identified based on current projections of the costs to be incurred in excess of contract amounts. Costs incurred in excess of billings and estimated contract loss on the Century Plant of $14.0 million at September 30, 2012 is included in current assets in the accompanying unaudited condensed consolidated balance sheets. Billings and estimated contract loss in excess of costs incurred of $43.3 million at December 31, 2011 is reported as a current liability in the accompanying unaudited condensed consolidated balance sheets.

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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 12 for additional discussion of this requirement. The Company retains all methane gas from the natural gas it delivers to the Century Plant.

Transmission Expansion Projects. The Company entered into a construction services agreement in November 2011 to manage the design, engineering and construction of a series of transmission expansion and upgrade projects in northern Oklahoma. Under the terms of the agreement, the Company will be reimbursed for costs incurred on these projects up to approximately $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 first quarter of 2013. Costs in excess of billings on these projects of $22.1 million at September 30, 2012 is included in current assets in the accompanying unaudited condensed consolidated balance sheets. There were no amounts related to these projects included in the accompanying unaudited condensed consolidated balance sheets at December 31, 2011.

9. Long-Term Debt

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



	September 30, 2012		December 31, 2011
Senior credit facility	$	—	$	—
Senior Notes
Senior Floating Rate Notes due 2014	—		350,000
9.875% Senior Notes due 2016, net of $9,383 and $10,921 discount, respectively	356,117		354,579
8.0% Senior Notes due 2018	750,000		750,000
8.75% Senior Notes due 2020, net of $6,016 and $6,432 discount, respectively	443,984		443,568
7.5% Senior Notes due 2021, including a premium of $4,426 at September 30, 2012	1,179,426		900,000
8.125% Senior Notes due 2022	750,000		—
7.5% Senior Notes due 2023, net of $4,096 discount at September 30, 2012	820,904		—
Other notes payable	—		16,029
Total debt	4,300,431		2,814,176
Less: current maturities of long-term debt	—		1,051
Long-term debt	$	4,300,431	$	2,813,125

For the three and nine-month periods ended September 30, 2012, interest payments, excluding amounts capitalized, were approximately $60.8 million and $181.4 million, respectively. Interest payments for the nine-month period ended September 30, 2012 included $10.9 million of fees incurred to secure financing for the Dynamic Acquisition. For the three and nine-month periods ended September 30, 2011, interest payments, excluding amounts capitalized, were approximately $60.4 million and $169.9 million, respectively. Interest payments for the nine-month period ended September 30, 2011 included $25.7 million of accrued interest paid in connection with the purchase and redemption of the 8.625% Senior Notes due 2015, discussed further below.

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Senior Credit Facility

The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants. On March 29, 2012, the senior credit facility was amended and restated to, among other things, (a) increase the borrowing base to $1.0 billion from $790.0 million, (b) allow for the incurrence or issuance of additional debt (including up to $750.0 million of unsecured debt to finance the cash portion of the Dynamic purchase price and related costs and expenses), (c) permit the Company to designate certain of its subsidiaries as unrestricted subsidiaries, and (d) effective on and after June 30, 2012, establish the financial covenants as maintaining agreed upon levels for (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total funded debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded. The senior credit facility matures in March 2017.

The senior credit facility contains various covenants that limit the ability of the Company and certain of its subsidiaries to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions. As of and during the three and nine-month periods ended September 30, 2012, the Company was in compliance with all applicable financial covenants under the senior credit facility.

The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of certain of the Company’s material present and future subsidiaries; certain intercompany debt of the Company; and substantially all of the Company’s assets, including proved oil and natural gas reserves representing at least 80.0% 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. The Company made no interest payments during the three and nine-month periods ended September 30, 2012 as there have been no amounts outstanding under the senior credit facility during 2012. The average annual interest rate paid on amounts outstanding under the senior credit facility was 2.65% and 2.69%, respectively, for the three and nine-month periods ended September 30, 2011.

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 additional 7.5% Senior Notes due 2021 and the 7.5% Senior Notes due 2023, as discussed below. The Company’s borrowing base is redetermined in April and October of each year, and was reaffirmed at $775.0 million in October 2012. The next borrowing base redetermination will be in April 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. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base. During the nine-month period ended September 30, 2012, additional costs of approximately $7.5 million were incurred. These costs have been deferred, and are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the senior credit facility.

At September 30, 2012, the Company had no amount outstanding under the senior credit facility and $28.8 million in outstanding letters of credit, which reduce the availability under the senior credit facility on a dollar-for-dollar basis.

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Senior Notes

Senior Floating Rate Notes Due 2014. The Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) were issued in May 2008 and bore interest at LIBOR plus 3.625%. On August 6, 2012, the Company announced a cash tender offer to purchase any and all of the outstanding $350.0 million aggregate principal amount of its Senior Floating Rate Notes for total consideration of $1,002.50 per $1,000 principal amount of such notes tendered by August 17, 2012. Holders tendering after August 17, 2012 were eligible to receive $972.50 per $1,000 principal amount of notes tendered. The Company purchased approximately 94.3%, or $329.9 million, of the aggregate principal amount of its Senior Floating Rate Notes pursuant to the 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 at par value. 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 premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $3.1 million, were recorded as a loss on extinguishment of debt and included in the accompanying unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2012.

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 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 Note 18 for condensed financial information of the subsidiary guarantors.

Debt issuance costs incurred in connection with the Senior Fixed Rate Notes offerings 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.

2011 Activity. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were used to fund the tender offer for, and subsequent redemption of, the 8.625% Senior Notes due 2015, described below and to repay borrowings under the Company’s senior credit facility.

In March 2011, the Company purchased approximately 94.5%, or $614.2 million, of the aggregate principal amount of its 8.625% Senior Notes due 2015 pursuant to a tender offer, which expired on March 28, 2011. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes due 2015. All holders whose notes were purchased or redeemed received accrued and unpaid interest from October 1, 2010. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $38.2 million, were recorded as a loss on extinguishment of debt in the accompanying unaudited condensed consolidated statements of operations for the nine-month period ended September 30, 2011.

In November 2011, pursuant to an exchange offer, the Company replaced 99.99% of the 7.5% Senior Notes due 2021 with 7.5% Senior Notes due 2021 that are registered under the Securities Act. The exchange offer did not result in the incurrence of any additional indebtedness.

2012 Activity. In 2012, the Company completed offerings of its 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.

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 being used for general corporate purposes.

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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, which were used to fund the Company’s tender offer for, and subsequent redemption of, its Senior Floating Rate Notes, discussed under Senior Floating Rate Notes due 2014 above, and for general corporate purposes, including funding the Company’s capital expenditures.

In conjunction with the issuance of the 2012 Senior Notes, the Company entered into registration rights agreements requiring the Company to commence registered exchange offers for or register the resale of these notes within one year of the issuance date of the respective notes. The Company would be required to pay liquidated damages of additional interest at an annual rate of 0.25%, increasing each 90 days to a maximum annual rate of 0.50%, if it fails to fulfill its obligations under the applicable agreement within the specified time period. In October 2012, the Company commenced registered exchange offers for the 2012 Senior Notes. See Note 19 for further discussion.

The Company incurred $40.7 million of debt issuance costs in connection with the 2012 Senior Notes offerings. 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.

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 and nine-month periods ended September 30, 2012, the Company was in compliance with all of the covenants contained in the indentures governing its senior notes.

Other Notes Payable

The debt incurred to purchase the downtown Oklahoma City property that serves as the Company’s corporate headquarters was fully secured by a mortgage on one of the buildings located on the property. In May 2012, the Company paid the outstanding $15.8 million principal balance on the note underlying the mortgage.

10. 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 (gain) 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 sheets.

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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. Additionally, the Company uses derivative contracts to manage commodity price risk associated with diesel fuel used in its operations. None of the Company’s derivative contracts may be terminated early solely as a result of a downgrade in the credit rating of a party to the contract. At September 30, 2012, the Company’s commodity derivative contracts consisted of fixed price swaps, collars and basis swaps, which are described below:



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

Collars	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.

The Company has 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 terminates April 1, 2013 and has not been designated as a hedge.

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, Permian Trust and Mississippian Trust II, respectively, to provide each Royalty Trust with the economic effect of certain oil and natural gas derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015, March 31, 2015 and December 31, 2014 for the Mississippian Trust I, Permian Trust and Mississippian Trust II, respectively. Under these arrangements, the Company will pay the Royalty Trusts amounts it receives from its counterparties in accordance with the underlying contracts, and the Royalty Trusts will 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 agreement, the Company novated certain of the derivatives contracts underlying the derivatives agreements to the Permian Trust and Mississippian Trust II. As a party to these contracts, the Permian Trust and Mississippian Trust II will receive payment directly from the counterparty and pay any amounts owed directly to the counterparty. To secure the Permian Trust’s and Mississippian Trust II’s obligations under these novated contracts, the Permian Trust and Mississippian Trust II have given the counterparties liens on their royalty interests. Under the derivatives agreement, as development wells are drilled for the benefit of the Permian Trust and Mississippian Trust II, the Company will have the right, under certain circumstances, to assign or novate to the Permian Trust and Mississippian Trust II additional derivative contracts. In April 2012, the Company novated to the Permian Trust certain additional derivative contracts underlying the derivatives agreement.

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

Fair Value of Derivatives. The following table presents the fair value of the Company’s derivative contracts as of September 30, 2012 and December 31, 2011 on a gross basis without regard to same-counterparty netting (in thousands):



Type of Contract	Balance Sheet Classification	September 30, 2012			December 31, 2011
Derivative assets
Oil price swaps	Derivative contracts-current	$	97,237		$	6,095
Natural gas price swaps	Derivative contracts-current	1,298			6,585
Oil collars - two way	Derivative contracts-current	53			—
Natural gas collars	Derivative contracts-current	3,642			313
Diesel price swaps	Derivative contracts-current	685			397
Oil price swaps	Derivative contracts-noncurrent	61,736			48,718
Oil collars - three way	Derivative contracts-noncurrent	226			—
Natural gas collars	Derivative contracts-noncurrent	1,341			1,035
Derivative liabilities
Oil price swaps	Derivative contracts-current	(29,492		)	(116,243		)
Natural gas price swaps	Derivative contracts-current	(5,338		)	—
Oil basis swaps	Derivative contracts-current	(502		)	—
Oil collars - two way	Derivative contracts-current	(143		)	—
Diesel price swaps	Derivative contracts-current	—			(41		)
Interest rate swap	Derivative contracts-current	(4,816		)	(8,475		)
Oil price swaps	Derivative contracts-noncurrent	(71,012		)	(66,451		)
Natural gas basis swaps	Derivative contracts-noncurrent	—			(4,609		)
Oil collars - two way	Derivative contracts-noncurrent	(42		)	—
Oil collars - three way	Derivative contracts-noncurrent	(9,615		)	—
Interest rate swap	Derivative contracts-noncurrent	—			(1,973		)
Total net derivative contracts		$	45,258		$	(134,649	)

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

The following table summarizes the effect of the Company’s derivative contracts on the accompanying unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2012 and 2011 (in thousands):



Type of Contract	Location of Loss (Gain) Recognized in Income	Three Months Ended September 30,					Nine Months Ended September 30,
Type of Contract	Location of Loss (Gain) Recognized in Income	2012		2011			2012			2011
Commodity derivatives	Loss (gain) on derivative contracts	$	193,497	$	(596,736	)	$	(221,707	)	$	(489,096	)
Interest rate swap	Interest expense	297		555			1,192			3,631
Total		$	193,794	$	(596,181	)	$	(220,515	)	$	(485,465	)

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The following tables summarize the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts and interest rate swap for the three and nine-month periods ended September 30, 2012 and 2011 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Commodity Derivatives
Realized (gain) loss(1)	$	(28,970	)	$	7,814		$	7,366		$	34,696
Unrealized loss (gain)	222,467			(604,550		)	(229,073		)	(523,792		)
Loss (gain) on commodity derivative contracts	$	193,497		$	(596,736	)	$	(221,707	)	$	(489,096	)
Interest Rate Swap
Realized loss	$	2,330		$	2,520		$	6,824		$	7,005
Unrealized gain	(2,033		)	(1,965		)	(5,632		)	(3,374		)
Loss on interest rate swap	$	297		$	555		$	1,192		$	3,631

____________________

(1)

The three and nine-month periods ended September 30, 2012 included $2.1 million and $59.5 million of net realized gains related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled (“early settlements”), respectively. The nine-month period ended September 30, 2012 also included $117.1 million non-cash realized losses on derivative contracts amended in January 2012. The three and nine-month periods ended September 30, 2011 included $9.9 million and $48.1 million, respectively, of net realized gains from early settlements.

At September 30, 2012, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps



	Notional (MBbl)	Weighted Avg. Fixed Price
October 2012 — December 2012	4,204	$	100.67
January 2013 — December 2013	18,515	$	96.24
January 2014 — December 2014	7,511	$	92.43
January 2015 — December 2015	5,076	$	83.69

Oil Basis Swaps

Oil Collars - Two-way



	Notional (MBbl)	Collar Range
October 2012 — December 2012	52	$85.00 - $114.00
January 2013 — December 2013	168	$80.00 - $102.50

Oil Collars - Three-way



	Notional (MBbl)	Collar Range
January 2014 — December 2014	8,213	$70.00 - $90.20 - $100.00
January 2015 — December 2015	2,920	$73.13 - $90.82 - $103.13

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Natural Gas Price Swaps

Natural Gas Collars



	Notional (MMBtu)	Collar Range
October 2012 — December 2012	2,271	$4.09 - $6.58
January 2013 — December 2013	6,858	$3.78 - $6.71
January 2014 — December 2014	937	$4.00 - $7.78
January 2015 — December 2015	1,010	$4.00 - $8.55

Diesel Price Swaps

11. Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2011 to September 30, 2012 is as follows (in thousands):



Asset retirement obligation, December 31, 2011	$	128,116
Liability incurred upon acquiring and drilling wells	5,363
Liability assumed in acquisitions(1)	371,365
Revisions in estimated cash flows	1,308
Liability settled or disposed in current period	(54,254		)
Accretion of discount expense	19,625
Asset retirement obligation, September 30, 2012	471,523
Less: current portion	117,044
Asset retirement obligation, net of current	$	354,479

____________________


(1)	Includes amounts assumed in acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.

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12. Commitments and Contingencies

Legal Proceedings

On or about June 27, 2008 and November 6, 2008, there were fires at the Company’s Grey Ranch Plant and a nearby compressor station. The Company, as owner of the Plant and compressor station, recovered approximately $24.5 million from its insurance carriers for damages caused by the fires. At the time of the Plant fire, the Plant was operated by Southern Union Gas Services, Ltd. (“Southern Union Gas”). On June 4, 2010, November 10, 2010, and March 15, 2011, the Company’s insurance carriers filed lawsuits against Southern Union Gas and its parent, Southern Union Company (together with Southern Union Gas, “Southern Union”) seeking recovery for amounts paid under the Company’s insurance policies. Southern Union, in turn, has tendered indemnity requests to GRLP, of which the Company is a 50% owner. GRLP has not accepted or acknowledged any responsibility to indemnify Southern Union. To the extent the Company, as a 50% owner of GRLP, is required to fund any indemnification of Southern Union, it will pursue coverage for such liability under its general liability insurance policy. An estimate of reasonably possible losses associated with these claims is approximately $12.3 million. As the loss is not probable, the Company has not established any reserves relating to these claims.

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with Aspen’s construction of a natural gas pipeline in west Texas. On October 14, 2011, the complaint was amended to add Odessa Fuels, LLC, Odessa Fuels Marketing, LLC and Odessa Field Services and Compression, LLC as plaintiffs. The plaintiffs’ amended claims seek damages relating to the construction of the pipeline and performance under a related gas purchase agreement, which damages are alleged to approach $100.0 million. The Company intends to defend this lawsuit vigorously. This lawsuit is in the discovery stage 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.

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

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. filed a lawsuit against SandRidge Energy, Inc., SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain directors and senior executive officers of SandRidge Energy, Inc. (collectively, the “defendants”) in the U.S. District Court for the District of Connecticut. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and the plaintiffs prior to the entry into a participation agreement among Patriot Exploration, LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by the plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, the plaintiffs have invested approximately $15.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This 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.

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In addition, 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 CO₂ to be removed from the Company’s delivered production volumes. The Company is required to deliver a total of approximately 3,200 Bcf of CO2 during the agreement period. If the Company does not meet the CO2 volume requirements, the Company will have to pay a fee for any volume shortfalls. Based upon current natural gas production levels, the Company expects to incur between approximately $8.0 million and $9.5 million at December 31, 2012 for amounts related to the Company’s shortfall in meeting its 2012 delivery obligations based on the completion of Phase I in the third quarter of 2012.

13. Equity

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



	September 30, 2012	December 31, 2011
Shares authorized	50,000	50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock	2,650	2,650
6.0% Convertible perpetual preferred stock	2,000	2,000
7.0% Convertible perpetual preferred stock	3,000	3,000

The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 7,650,000 shares are designated as convertible perpetual preferred stock at September 30, 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. The Company’s 8.5% convertible perpetual preferred stock was issued in January 2009. Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100.00 and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of the Company’s common stock, subject to customary adjustments in certain circumstances. Each holder of the convertible perpetual preferred stock is entitled to an annual dividend of $8.50 per share to be paid semi-annually in cash, common stock or a combination thereof, at the Company’s election. The 8.5% convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.

6.0% Convertible perpetual preferred stock. The Company’s 6.0% convertible perpetual preferred stock was issued in December 2009. Each share of the 6.0% convertible perpetual preferred stock has a liquidation preference of $100.00 and is entitled to an annual dividend of $6.00 payable semi-annually in cash, common stock or any combination thereof, at the Company’s election. 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.

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7.0% Convertible perpetual preferred stock. The Company’s 7.0% convertible perpetual preferred stock was issued in November 2010. Each share of the 7.0% convertible preferred stock has a liquidation preference of $100.00 per share and became convertible at the holder’s option on February 15, 2011, initially into approximately 12.8791 shares of the Company’s common stock, subject to customary adjustments in certain circumstances. The annual dividend on each share of the 7.0% convertible preferred stock is $7.00 payable semi-annually, in cash, common stock or a combination thereof, at the Company’s election. 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 income available (loss applicable) to the Company’s common stockholders and the Company’s basic earnings per share calculation for the three and nine-month periods ended September 30, 2012 and 2011 as presented in the accompanying unaudited condensed consolidated statements of operations, are included in tables below (in thousands):



	Three Months Ended September 30,
	2012						2011
	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



	Nine Months Ended September 30,
	2012						2011
	Dividends Paid		Dividends Unpaid		Total		Dividends Paid		Dividends Unpaid		Total
8.5% Convertible perpetual preferred stock	$	14,078	$	2,816	$	16,894	$	14,078	$	2,816	$	16,894
6.0% Convertible perpetual preferred stock	6,500		2,500		9,000		6,500		2,500		9,000
7.0% Convertible perpetual preferred stock	7,875		7,875		15,750		7,933		7,875		15,808
Total	$	28,453	$	13,191	$	41,644	$	28,511	$	13,191	$	41,702

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



	September 30, 2012	December 31, 2011
Shares authorized	800,000	800,000
Shares outstanding at end of period	490,807	411,953
Shares held in treasury	998	874

On April 17, 2012, the Company issued approximately 74 million shares of SandRidge common stock to satisfy the stock portion of the consideration paid in the Dynamic Acquisition. See Note 2 for further discussion of the Dynamic Acquisition.

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 1.5 million shares having a total value of $11.1 million and approximately 1.1 million shares having a total value of $10.6 million during the nine-month periods ended September 30, 2012 and 2011, respectively. These shares were accounted for as treasury stock when withheld, and subsequently retired.

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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.

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

Equity compensation provided to employees directly involved in oil and natural gas exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is reflected in general and administrative expenses, production expenses, midstream and marketing expenses and drilling and services expenses in the consolidated statements of operations. For the three and nine-month periods ended September 30, 2012, the Company recognized equity compensation expense of $9.1 million and $30.7 million, net of $1.8 million and $5.7 million capitalized, respectively, related to restricted common stock. For the three and nine-month periods ended September 30, 2011, the Company recognized equity compensation expense of $9.4 million and $26.5 million, net of $2.0 million and $5.7 million capitalized, respectively, related to restricted common stock.

Noncontrolling Interest. Noncontrolling interests in the Company’s subsidiaries and consolidated VIEs as of and for the three and nine-month periods ended September 30, 2012 (see Note 3), represent third-party ownership interests in the consolidated entity and are included as a component of equity in the accompanying unaudited condensed consolidated balance sheets and accompanying unaudited condensed consolidated statements of changes in equity.

14. Income Taxes

The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The provision (benefit) for income taxes consisted of the following components for the three and nine-month periods ended September 30, 2012 and 2011 (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012			2011
Current
Federal	$	—	$	739	$	(72	)	$	623
State	173		215		(14		)	350
	173		954		(86		)	973
Deferred
Federal	—		—		(100,385		)	(6,447		)
State	—		—		(2,943		)	(539		)
	—		—		(103,328		)	(6,986		)
Total provision (benefit)	173		954		(103,414		)	(6,013		)
Less: income tax provision attributable to noncontrolling interest	130		103		287			104
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	43	$	851	$	(103,701	)	$	(6,117	)

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. During the nine-month period ended September 30, 2012, the Company recorded a net deferred tax liability associated with the Dynamic Acquisition which resulted in the Company releasing a portion

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

of the previously recorded valuation allowance. The partial release of the valuation allowance was based on management's assessment that it is more likely than not that the Company will realize a benefit from more of its existing deferred tax assets as the Dynamic deferred tax liabilities are available to offset the reversal of the Company's deferred tax assets. Although the Company continued to have a full valuation allowance against its net deferred tax asset at September 30, 2012, the release of a portion of the valuation allowance resulted in an income tax benefit of $103.3 million for the nine-month period ended September 30, 2012. The Company continues to closely monitor all available evidence in making its determination for the need to maintain a valuation allowance against its net deferred tax asset.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected certain of the Company’s tax attributes, including $298.4 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. The Company experienced a subsequent ownership change within the meaning of IRC Section 382 on July 16, 2010 as a result of the acquisition of Arena. 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 $619.9 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 September 30, 2012 or December 31, 2011.

At September 30, 2012, the Company had a liability of approximately $1.3 million for unrecognized tax benefits, compared to a liability of approximately $1.8 million at December 31, 2011. If recognized, approximately $0.9 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate.

Consistent with the Company’s policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included $0.03 million of accrued gross interest with respect to unrecognized tax benefits in the accompanying unaudited condensed consolidated statements of operations during the nine-month period ended September 30, 2012. The Company included $0.02 million and $0.09 million of accrued gross interest with respect to unrecognized tax benefits in the accompanying unaudited condensed consolidated statements of operations during the three and nine-month periods ended September 30, 2011, respectively. The Company had a corresponding accrued liability of $0.2 million for interest and penalties relating to uncertain tax positions at September 30, 2012 and December 31, 2011.

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 $1.1 million.

There were no income tax payments made or refunds received during the three-month period ended September 30, 2012. For the nine-month period ended September 30, 2012, income tax payments, net of refunds, were approximately $1.3 million. For the three and nine-month periods ended September 30, 2011, income tax payments, net of refunds were approximately $1.8 million and $2.7 million, respectively.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

15. 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 common shares. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the three and nine-month periods ended September 30, 2012 and 2011 (in thousands):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
Weighted average basic common shares outstanding	476,037	399,270	445,991	398,656
Effect of dilutive securities
Restricted stock	—	8,297	1,176	7,639
Convertible preferred stock	—	90,133	90,133	90,133
Weighted average diluted common and potential common shares outstanding	476,037	497,700	537,300	496,428

For the three-month period ended September 30, 2012, restricted stock awards covering 0.4 million shares 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 and nine-month periods ended September 30, 2012 and 2011. Under the if-converted method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available (loss applicable) to common stockholders. For the three-month period ended September 30, 2012, the Company determined the if-converted method was not more dilutive and included the 8.5%, 6.0% and 7.0% preferred stock dividends in the determination of loss applicable to common stockholders. For the three-month period ended September 30, 2011 and the nine-month periods ended September 30, 2012 and 2011, the Company determined the if-converted method was more dilutive and did not include the 8.5%, 6.0% and 7.0% preferred stock dividends in the determination of income available to common stockholders.

16. 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 September 30, 2012 and 2011, sales by the Company to related parties were $2.8 million and $5.7 million, respectively. During the nine-month periods ended September 30, 2012 and 2011, sales by the Company to related parties were $9.8 million and $17.5 million, respectively. Accounts receivable due from related parties totaled $0.9 million and $1.6 million at September 30, 2012 and December 31, 2011, respectively. These amounts primarily relate to sales of natural gas to Southern Union, the Company’s partner in GRLP.

Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer 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, through the 2013 season, whereby it pays approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder. Additionally, the Company entered into an agreement to license a suite at the arena where the Oklahoma City Thunder plays its home games. Under this four-year agreement, the Company pays an annual license fee of $0.2 million through 2013. At September 30, 2012 and December 31, 2011, the Company had no amounts due under these agreements.

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17. Business Segment Information

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

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



	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Three Months Ended September 30, 2012
Revenues	$	493,848		$	95,307		$	30,901		$	945		$	621,001
Inter-segment revenue	(74		)	(67,547		)	(20,582		)	—			(88,203		)
Total revenues	$	493,774		$	27,760		$	10,319		$	945		$	532,798

(Loss) income from operations(1)	$	(48,454	)	$	2,515		$	(3,434	)	$	(26,498	)	$	(75,871	)
Interest income (expense)	351			—			(136		)	(82,109		)	(81,894		)
Loss on extinguishment of debt	—			—			—			(3,056		)	(3,056		)
Other (expense) income, net	(260		)	—			—			1,502			1,242
(Loss) income before income taxes	$	(48,363	)	$	2,515		$	(3,570	)	$	(110,161	)	$	(159,579	)
Capital expenditures(2)	$	500,366		$	14,571		$	20,229		$	24,892		$	560,058
Depreciation, depletion, amortization and accretion	$	175,393		$	8,706		$	2,042		$	5,535		$	191,676
Three Months Ended September 30, 2011
Revenues	$	321,456		$	108,595		$	44,111		$	2,420		$	476,582
Inter-segment revenue	(67		)	(83,048		)	(29,457		)	(257		)	(112,829		)
Total revenues	$	321,389		$	25,547		$	14,654		$	2,163		$	363,753

Income (loss) from operations(1)	$	717,327		$	2,507		$	(2,016	)	$	(21,236	)	$	696,582
Interest income (expense)	163			7			(144		)	(58,978		)	(58,952		)
Other income (expense), net	11			—			—			(683		)	(672		)
Income (loss) before income taxes	$	717,501		$	2,514		$	(2,160	)	$	(80,897	)	$	636,958
Capital expenditures(2)	$	435,662		$	5,898		$	6,757		$	13,808		$	462,125
Depreciation, depletion, amortization and accretion	$	87,236		$	8,250		$	1,202		$	3,588		$	100,276

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	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Nine Months Ended September 30, 2012
Revenues	$	1,271,803		$	297,715		$	81,861		$	3,904		$	1,655,283
Inter-segment revenue	(229		)	(207,014		)	(55,173		)	—			(262,416		)
Total revenues	$	1,271,574		$	90,701		$	26,688		$	3,904		$	1,392,867

Income (loss) from operations(3)	$	614,045		$	10,672		$	(9,792	)	$	(80,039	)	$	534,886
Interest income (expense)	910			—			(429		)	(217,909		)	(217,428		)
Bargain purchase gain	124,446			—			—			—			124,446
Loss on extinguishment of debt	—			—			—			(3,056		)	(3,056		)
Other income, net	1,750			—			—			1,879			3,629
Income (loss) before income taxes	$	741,151		$	10,672		$	(10,221	)	$	(299,125	)	$	442,477
Capital expenditures(2)	$	1,510,614		$	28,323		$	61,958		$	90,875		$	1,691,770
Depreciation, depletion, amortization and accretion	$	412,924		$	25,880		$	5,170		$	14,460		$	458,434
At September 30, 2012
Total assets	$	8,328,674		$	217,907		$	206,211		$	1,091,455		$	9,844,247
Nine Months Ended September 30, 2011
Revenues	$	906,461		$	272,587		$	148,367		$	8,525		$	1,335,940
Inter-segment revenue	(200		)	(197,469		)	(95,968		)	(928		)	(294,565		)
Total revenues	$	906,261		$	75,118		$	52,399		$	7,597		$	1,041,375

Income (loss) from operations(3)	$	834,317		$	6,496		$	(7,115	)	$	(65,228	)	$	768,470
Interest income (expense)	283			(94		)	(456		)	(179,810		)	(180,077		)
Loss on extinguishment of debt	—			—			—			(38,232		)	(38,232		)
Other income (expense), net	1,690			—			(485		)	(543		)	662
Income (loss) before income taxes	$	836,290		$	6,402		$	(8,056	)	$	(283,813	)	$	550,823
Capital expenditures(2)	$	1,248,288		$	20,692		$	15,392		$	37,818		$	1,322,190
Depreciation, depletion, amortization and accretion	$	238,442		$	23,977		$	3,589		$	10,708		$	276,716
At December 31, 2011
Total assets	$	5,345,527		$	219,101		$	138,844		$	516,137		$	6,219,609

____________________


(1)	Exploration and production segment income from operations includes a net loss of $193.5 million and a net gain of $596.7 million on commodity derivative contracts for the three-month periods ended September 30, 2012 and 2011, respectively.


(2)	On an accrual basis.


(3)	Exploration and production segment income from operations includes net gains of $221.7 million and $489.1 million on commodity derivative contracts for the nine-month periods ended September 30, 2012 and 2011, respectively.

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18. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. The subsidiary guarantors are wholly owned and, as of September 30, 2012, jointly and severally guaranteed, on a full, unconditional and unsecured basis, the Company’s 8.75% Senior Notes due 2020 and 7.5% Senior Notes due 2021 issued in March 2011. The 8.625% Senior Notes due 2015 and Senior Floating Rate Notes, prior to their purchase and redemption in 2011 and the third quarter of 2012, respectively, were also jointly and severally guaranteed, on a full, unconditional and unsecured basis by the wholly owned subsidiary guarantors. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors; and (v) are only released under certain customary circumstances. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes.

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

Condensed Consolidating Balance Sheets



	September 30, 2012
	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	663,359	$	824		$	9,497	$	—		$	673,680
Accounts receivable, net	1,886,525		756,879			705,185		(2,966,495		)	382,094
Derivative contracts	—		70,039			27,193		(16,105		)	81,127
Prepaid expenses	—		37,075			112		—			37,187
Other current assets	1,375		49,029			4,695		—			55,099
Total current assets	2,551,259		913,846			746,682		(2,982,600		)	1,229,187
Property, plant and equipment, net	—		6,891,521			1,358,022		(55,585		)	8,193,958
Investment in subsidiaries	5,622,220		(66,333		)	—		(5,555,887		)	—
Derivative contracts	—		25,765			42,362		(31,733		)	36,394
Goodwill	—		235,396			—		—			235,396
Other assets	86,365		62,947			—		—			149,312
Total assets	$	8,259,844	$	8,063,142		$	2,147,066	$	(8,625,805	)	$	9,844,247
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	1,231,329	$	1,839,436		$	666,189	$	(2,957,754	)	$	779,200
Derivative contracts	4,816		29,792			—		(16,105		)	18,503
Asset retirement obligation	—		117,044			—		—			117,044
Total current liabilities	1,236,145		1,986,272			666,189		(2,973,859		)	914,747
Long-term debt	4,306,333		—			—		(5,902		)	4,300,431
Derivative contracts	—		85,493			—		(31,733		)	53,760
Asset retirement obligation	—		354,286			193		—			354,479
Other long-term obligations	1,336		14,474			—		—			15,810
Total liabilities	5,543,814		2,440,525			666,382		(3,011,494		)	5,639,227
Equity
SandRidge Energy, Inc. stockholders’ equity	2,716,030		5,622,617			1,480,684		(7,161,329		)	2,658,002
Noncontrolling interest	—		—			—		1,547,018			1,547,018
Total equity	2,716,030		5,622,617			1,480,684		(5,614,311		)	4,205,020
Total liabilities and equity	$	8,259,844	$	8,063,142		$	2,147,066	$	(8,625,805	)	$	9,844,247

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	December 31, 2011
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	204,015	$	437	$	3,229	—			$	207,681
Accounts receivable, net	1,217,096		247,824		602,541		(1,861,125		)	206,336
Derivative contracts	—		2,567		10,368		(8,869		)	4,066
Prepaid expenses	—		13,442		657		—			14,099
Other current assets	—		2,621		7,037		—			9,658
Total current assets	1,421,111		266,891		623,832		(1,869,994		)	441,840
Property, plant and equipment, net	—		4,462,846		926,578		—			5,389,424
Investment in subsidiaries	3,609,244		90,920		—		(3,700,164		)	—
Derivative contracts	—		20,746		35,774		(30,105		)	26,415
Goodwill	—		235,396		—		—			235,396
Other assets	51,724		74,760		50		—			126,534
Total assets	$	5,082,079	$	5,151,559	$	1,586,234	$	(5,600,263	)	$	6,219,609
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	643,376	$	1,166,029	$	556,165	$	(1,858,786	)	$	506,784
Derivative contracts	8,475		115,829		—		(8,869		)	115,435
Asset retirement obligation	—		32,906		—		—			32,906
Other current liabilities	—		43,320		1,051		—			44,371
Total current liabilities	651,851		1,358,084		557,216		(1,867,655		)	699,496
Long-term debt	2,798,147		—		14,978		—			2,813,125
Derivative contracts	1,973		77,827		—		(30,105		)	49,695
Asset retirement obligation	—		95,029		181		—			95,210
Other long-term obligations	1,758		11,375		—		—			13,133
Total liabilities	3,453,729		1,542,315		572,375		(1,897,760		)	3,670,659
Equity
SandRidge Energy, Inc. stockholders’ equity	1,628,350		3,609,244		1,013,859		(4,625,442		)	1,626,011
Noncontrolling interest	—		—		—		922,939			922,939
Total equity	1,628,350		3,609,244		1,013,859		(3,702,503		)	2,548,950
Total liabilities and equity	$	5,082,079	$	5,151,559	$	1,586,234	$	(5,600,263	)	$	6,219,609

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Condensed Consolidating Statements of Operations



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended September 30, 2012
Total revenues	$	—		$	447,391		$	112,501		$	(27,094	)	$	532,798
Expenses
Direct operating expenses	—			167,014			36,369			(26,668		)	176,715
General and administrative	244			45,600			1,354			(417		)	46,781
Depreciation, depletion, amortization and accretion	—			165,269			26,407			—			191,676
Loss on derivative contracts	—			159,757			33,740			—			193,497
Total expenses	244			537,640			97,870			(27,085		)	608,669
(Loss) income from operations	(244		)	(90,249		)	14,631			(9		)	(75,871		)
Equity earnings from subsidiaries	(84,956		)	3,836			—			81,120			—
Interest (expense) income	(82,110		)	215			1			—			(81,894		)
Loss on extinguishment of debt	(3,056		)	—			—			—			(3,056		)
Other income, net	—			1,242			—			—			1,242
(Loss) income before income taxes	(170,366		)	(84,956		)	14,632			81,111			(159,579		)
Income tax expense	42			—			131			—			173
Net (loss) income	(170,408		)	(84,956		)	14,501			81,111			(159,752		)
Less: net income attributable to noncontrolling interest	—			—			—			10,668			10,668
Net (loss) income attributable to SandRidge Energy, Inc.	$	(170,408	)	$	(84,956	)	$	14,501		$	70,443		$	(170,420	)

Three Months Ended September 30, 2011
Total revenues	$	—		$	320,816		$	87,056		$	(44,119	)	$	363,753
Expenses
Direct operating expenses	—			120,367			50,848			(43,856		)	127,359
General and administrative	84			35,153			1,298			(263		)	36,272
Depreciation, depletion, amortization and accretion	—			89,832			10,444			—			100,276
Gain on derivative contracts	—			(527,744		)	(68,992		)	—			(596,736		)
Total expenses	84			(282,392		)	(6,402		)	(44,119		)	(332,829		)
(Loss) income from operations	(84		)	603,208			93,458			—			696,582
Equity earnings from subsidiaries	634,712			32,150			—			(666,862		)	—
Interest (expense) income	(58,721		)	26			(257		)	—			(58,952		)
Other expense, net	—			(672		)	—			—			(672		)
Income before income taxes	575,907			634,712			93,201			(666,862		)	636,958
Income tax expense	798			—			156			—			954
Net income	575,109			634,712			93,045			(666,862		)	636,004
Less: net income attributable to noncontrolling interest	—			—			—			60,895			60,895
Net income attributable to SandRidge Energy, Inc.	$	575,109		$	634,712		$	93,045		$	(727,757	)	$	575,109

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	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2012
Total revenues	$	—		$	1,172,206		$	313,872		$	(93,211	)	$	1,392,867
Expenses
Direct operating expenses	—			430,621			123,450			(91,615		)	462,456
General and administrative	429			153,665			5,801			(1,097		)	158,798
Depreciation, depletion, amortization and accretion	—			396,524			61,910			—			458,434
Gain on derivative contracts	—			(181,389		)	(40,318		)	—			(221,707		)
Total expenses	429			799,421			150,843			(92,712		)	857,981
(Loss) income from operations	(429		)	372,785			163,029			(499		)	534,886
Equity earnings from subsidiaries	622,974			50,476			—			(673,450		)	—
Interest (expense) income	(217,343		)	480			(565		)	—			(217,428		)
Gain on sale of investment in subsidiary	55,585			—			—			(55,585		)	—
Bargain purchase gain	—			124,446			—			—			124,446
Loss on extinguishment of debt	(3,056		)	—			—			—			(3,056		)
Other income, net	—			74,787			—			(71,158		)	3,629
Income before income taxes	457,731			622,974			162,464			(800,692		)	442,477
Income tax (benefit) expense	(103,779		)	—			365			—			(103,414		)
Net income	561,510			622,974			162,099			(800,692		)	545,891
Less: net income attributable to noncontrolling interest	—			—			—			111,626			111,626
Net income attributable to SandRidge Energy, Inc.	$	561,510		$	622,974		$	162,099		$	(912,318	)	$	434,265
Nine Months Ended September 30, 2011
Total revenues	$	—		$	971,595		$	157,826		$	(88,046	)	$	1,041,375
Expenses
Direct operating expenses	—			361,984			102,320			(87,383		)	376,921
General and administrative	273			105,495			3,259			(663		)	108,364
Depreciation, depletion, amortization and accretion	—			258,485			18,231			—			276,716
Gain on derivative contracts	—			(410,503		)	(78,593		)	—			(489,096		)
Total expenses	273			315,461			45,217			(88,046		)	272,905
(Loss) income from operations	(273		)	656,134			112,609			—			768,470
Equity earnings from subsidiaries	694,149			37,862			—			(732,011		)	—
Interest expense	(179,036		)	(267		)	(774		)	—			(180,077		)
Loss on extinguishment of debt	(38,232		)	—			—			—			(38,232		)
Other income, net	—			420			242			—			662
Income before income taxes	476,608			694,149			112,077			(732,011		)	550,823
Income tax (benefit) expense	(6,173		)	—			160			—			(6,013		)
Net income	482,781			694,149			111,917			(732,011		)	556,836
Less: net income attributable to noncontrolling interest	—			—			—			74,055			74,055
Net income attributable to SandRidge Energy, Inc.	$	482,781		$	694,149		$	111,917		$	(806,066	)	$	482,781

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Condensed Consolidating Statements of Cash Flows



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2012
Net cash (used in) provided by operating activities	$	(309,498	)	$	602,080		$	227,732		$	63,916		$	584,230
Net cash used in investing activities	(624,631		)	(756,255		)	(619,191		)	(40,508		)	(2,040,585		)
Net cash provided by financing activities	1,393,473			154,562			397,727			(23,408		)	1,922,354
Net increase in cash and cash equivalents	459,344			387			6,268			—			465,999
Cash and cash equivalents at beginning of year	204,015			437			3,229			—			207,681
Cash and cash equivalents at end of period	$	663,359		$	824		$	9,497		$	—		$	673,680
Nine Months Ended September 30, 2011
Net cash provided by (used in) operating activities	$	519,941		$	(233,573	)	$	33,747		$	1,508		$	321,623
Net cash provided by (used in) investing activities	—			241,317			(953,717		)	14,236			(698,164		)
Net cash (used in) provided by financing activities	(198,460		)	(7,977		)	918,296			(15,744		)	696,115
Net increase (decrease) in cash and cash equivalents	321,481			(233		)	(1,674		)	—			319,574
Cash and cash equivalents at beginning of year	1,441			564			3,858			—			5,863
Cash and cash equivalents at end of period	$	322,922		$	331		$	2,184		$	—		$	325,437

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19. Subsequent Events

Events occurring after September 30, 2012 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this Quarterly Report have been included.

Sale of Royalty Trust Units. On October 2, 2012, the Company sold approximately 688,000 of its Mississippian Trust I common units in a transaction exempt from registration under Rule 144 under the Securities Act for proceeds of approximately $15.8 million. As a result of the sale, the Company's beneficial interest in the Mississippian Trust I decreased to 26.9%.

Senior Notes Registered Exchange Offers. On October 11, 2012, the Company commenced registered exchange offers for the 2012 Senior Notes. The terms of each series of senior notes to be issued in the exchange offers will be identical to the terms of the respective series of 2012 Senior Notes to be exchanged, except that the transfer restrictions, registration rights and provisions for additional interest relating to the exchanged notes will not apply to the senior notes to be issued in the exchange offers. The exchange offers are expected to close in November 2012.

Royalty Trust Distributions. On November 1, 2012, the Royalty Trusts announced quarterly distributions for the three-month period ended September 30, 2012. The following distributions are expected to be paid on November 29, 2012 to holders of record as of the close of business on November 14, 2012 (in thousands):



Royalty Trust	Total Distribution		Amount to be Distributed to Third-Party Unitholders
Mississippian Trust I	$	19,126	$	13,984
Mississippian Trust II	29,767		17,899
Permian Trust	32,823		22,820
Total	$	81,716	$	54,703

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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 2011 Form 10-K. The Company’s discussion and analysis includes the following subjects:


•	Overview of the Company;


•	Recent Developments;


•	Recent Accounting Pronouncements;


•	Results by Segment;


•	Consolidated Results of Operations; and


•	Liquidity and Capital Resources.

The financial information with respect to the three and nine-month periods ended September 30, 2012 and 2011, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Overview of the Company

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

In April 2012, the Company completed the Dynamic Acquisition for total consideration of approximately $1.2 billion. Dynamic is an oil and natural gas exploration, development and production company with operations in the Gulf of Mexico. In June 2012, the Company acquired the Gulf of Mexico Properties which consisted of approximately 184,000 gross (103,000 net) acres of oil and natural gas properties in the Gulf of Mexico for approximately $38.5 million, net of purchase price adjustments and subject to post-closing adjustments. These acquisitions 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.

The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and gas marketing business and an oil field services business, including 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.

Recent Developments

August 2012 Debt Offering. In August 2012, the Company issued $825.0 million of unsecured 7.5% Senior Notes due 2023 and $275.0 million of additional unsecured 7.5% Senior Notes due 2021. Net proceeds from this offering were approximately $1.1 billion, after deducting offering expenses and excluding accrued interest funded through the offering, and were used to fund the Company’s tender offer for, and subsequent redemption of, its Senior Floating Rate Notes, as described below, and for general corporate purposes, including to fund the Company’s capital expenditures.

Tender Offer and Redemption of Senior Floating Rate Notes. In August 2012, the Company announced a cash tender offer to purchase any and all of the outstanding $350.0 million aggregate principal amount of its Senior Floating Rate Notes for total consideration of $1,002.50 per $1,000 principal amount of such notes tendered by August 17, 2012. Holders tendering after August 17, 2012 were eligible to receive $972.50 per $1,000 principal amount of notes tendered. The Company purchased approximately 94.3%, or $329.9 million, of the aggregate principal amount of its Senior Floating Rate Notes pursuant to the tender

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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 at par value, plus accrued interest. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $3.1 million, were recorded as a loss on extinguishment of debt for the three and nine-month periods ended September 30, 2012.

Senior Notes Exchange Offers. On October 11, 2012, the Company commenced registered exchange offers for the 7.5% Senior Notes due 2023, the additional 7.5% Senior Notes due 2021 and the 8.125% Senior Notes due 2022. The terms of each series of senior notes to be issued in these exchange offers will be identical to the terms of the respective series of senior notes to be exchanged, except that the transfer restrictions, registration rights and provisions for additional interest relating to the exchanged notes will not apply to the senior notes to be issued in the exchange offers. The exchange offers are expected to close in November 2012.

Recent Accounting Pronouncements

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

Results by Segment

The Company operates in three business segments: exploration and production, drilling and oil field services and midstream gas services. 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. The midstream gas services segment is engaged in the purchasing, gathering, treating and selling of natural gas. The All Other column in the tables below includes items not related to the Company’s reportable segments, including its CO2 gathering and sales and corporate operations.

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 and profitability of the Company’s lines of business.

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The following table sets forth financial information regarding each of the Company’s business segments for the three and nine-month periods ended September 30, 2012 and 2011 (in thousands).



	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Three Months Ended September 30, 2012
Revenues	$	493,848		$	95,307		$	30,901		$	945		$	621,001
Inter-segment revenue	(74		)	(67,547		)	(20,582		)	—			(88,203		)
Total revenues	$	493,774		$	27,760		$	10,319		$	945		$	532,798

(Loss) income from operations(1)	$	(48,454	)	$	2,515		$	(3,434	)	$	(26,498	)	$	(75,871	)
Interest income (expense)	351			—			(136		)	(82,109		)	(81,894		)
Loss on extinguishment of debt	—			—			—			(3,056		)	(3,056		)
Other (expense) income, net	(260		)	—			—			1,502			1,242
(Loss) income before income taxes	$	(48,363	)	$	2,515		$	(3,570	)	$	(110,161	)	$	(159,579	)
Three Months Ended September 30, 2011
Revenues	$	321,456		$	108,595		$	44,111		$	2,420		$	476,582
Inter-segment revenue	(67		)	(83,048		)	(29,457		)	(257		)	(112,829		)
Total revenues	$	321,389		$	25,547		$	14,654		$	2,163		$	363,753

Income (loss) from operations(1)	$	717,327		$	2,507		$	(2,016	)	$	(21,236	)	$	696,582
Interest income (expense)	163			7			(144		)	(58,978		)	(58,952		)
Other income (expense), net	11			—			—			(683		)	(672		)
Income (loss) before income taxes	$	717,501		$	2,514		$	(2,160	)	$	(80,897	)	$	636,958

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	Exploration and Production			Drilling and Oil Field Services			Midstream Gas Services			All Other			Consolidated Total
Nine Months Ended September 30, 2012
Revenues	$	1,271,803		$	297,715		$	81,861		$	3,904		$	1,655,283
Inter-segment revenue	(229		)	(207,014		)	(55,173		)	—			(262,416		)
Total revenues	$	1,271,574		$	90,701		$	26,688		$	3,904		$	1,392,867

Income (loss) from operations(2)	$	614,045		$	10,672		$	(9,792	)	$	(80,039	)	$	534,886
Interest income (expense)	910			—			(429		)	(217,909		)	(217,428		)
Bargain purchase gain	124,446			—			—			—			124,446
Loss on extinguishment of debt	—			—			—			(3,056		)	(3,056		)
Other income, net	1,750			—			—			1,879			3,629
Income (loss) before income taxes	$	741,151		$	10,672		$	(10,221	)	$	(299,125	)	$	442,477
Nine Months Ended September 30, 2011
Revenues	$	906,461		$	272,587		$	148,367		$	8,525		$	1,335,940
Inter-segment revenue	(200		)	(197,469		)	(95,968		)	(928		)	(294,565		)
Total revenues	$	906,261		$	75,118		$	52,399		$	7,597		$	1,041,375

Income (loss) from operations(2)	$	834,317		$	6,496		$	(7,115	)	$	(65,228	)	$	768,470
Interest income (expense)	283			(94		)	(456		)	(179,810		)	(180,077		)
Loss on extinguishment of debt	—			—			—			(38,232		)	(38,232		)
Other income (expense), net	1,690			—			(485		)	(543		)	662
Income (loss) before income taxes	$	836,290		$	6,402		$	(8,056	)	$	(283,813	)	$	550,823

___________________


(1)	Exploration and production segment income from operations includes a net loss of $193.5 million and a net gain of $596.7 million on commodity derivative contracts for the three-month periods ended September 30, 2012 and 2011, respectively.


(2)	Exploration and production segment income from operations includes net gains of $221.7 million and $489.1 million on commodity derivative contracts for the nine-month periods ended September 30, 2012 and 2011, respectively.

Exploration and Production Segment

The Company currently generates the majority of its consolidated revenues and cash flow from the production and sale of oil and natural gas. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on the Company’s ability to find and economically develop and produce oil and natural gas reserves. Prices for oil and natural gas fluctuate widely. In order to reduce the Company’s exposure to these fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production. Reducing the Company’s exposure to price volatility mitigates the risk that it will not have adequate funds available for its capital expenditure programs.

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The primary factors affecting the financial results of the Company’s exploration and production segment are the prices the Company receives for its oil and natural gas production, the quantity of oil and natural gas it produces and changes in the fair value of commodity derivative contracts. Comparisons of production and price data are presented in the tables below. Changes from the 2011 periods to the 2012 periods reflect increased oil production throughout 2011 and continuing in 2012 due to the Company’s focus on the development of its oil properties located in the Mid-Continent and Permian Basin and the acquisition of oil and natural gas properties located in the Gulf of Mexico during the second quarter of 2012.



	Three Months Ended September 30,				Change
	2012		2011		Amount			Percent
Production data
Oil (MBbls)(1)	4,943		3,192		1,751			54.9	%
Natural gas (MMcf)	27,184		17,935		9,249			51.6	%
Total volumes (MBoe)	9,473		6,181		3,292			53.3	%
Average daily total volumes (MBoe/d)	103		67		36			53.7	%
Average prices — as reported(2)
Oil (per Bbl)(1)	$	84.50	$	79.31	$	5.19		6.5	%
Natural gas (per Mcf)	$	2.60	$	3.64	$	(1.04	)	(28.6	)%
Total (per Boe)	$	51.54	$	51.52	$	0.02		0.0	%
Average prices — including impact of derivative contract settlements
Oil (per Bbl)(1)	$	91.84	$	76.94	$	14.90		19.4	%
Natural gas (per Mcf)	$	2.23	$	3.08	$	(0.85	)	(27.6	)%
Total (per Boe)	$	54.32	$	48.66	$	5.66		11.6	%



	Nine Months Ended September 30,				Change
	2012		2011		Amount			Percent
Production data
Oil (MBbls)(1)	12,925		8,540		4,385			51.3	%
Natural gas (MMcf)	64,832		52,440		12,392			23.6	%
Total volumes (MBoe)	23,730		17,280		6,450			37.3	%
Average daily total volumes (MBoe/d)	87		63		24			38.1	%
Average prices — as reported(2)
Oil (per Bbl)(1)	$	86.25	$	82.61	$	3.64		4.4	%
Natural gas (per Mcf)	$	2.23	$	3.66	$	(1.43	)	(39.1	)%
Total (per Boe)	$	53.07	$	51.94	$	1.13		2.2	%
Average prices — including impact of derivative contract settlements
Oil (per Bbl)(1)	$	89.63	$	75.30	$	14.33		19.0	%
Natural gas (per Mcf)	$	2.31	$	3.41	$	(1.10	)	(32.3	)%
Total (per Boe)	$	55.14	$	47.56	$	7.58		15.9	%

__________________


(1)	Includes natural gas liquids.


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

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Exploration and Production Segment — Three months ended September 30, 2012 compared to the three months ended September 30, 2011

Exploration and production segment revenues increased $172.4 million, or 53.6%, to $493.8 million in the three-month period ended September 30, 2012 from the same period in 2011, as a result of a 1,751 MBbl, or 54.9%, increase in oil production, a $5.19 per Bbl, or 6.5%, increase in the average price received for oil production and a 9,249 MMcf, or 51.6%, increase in natural gas production. These increases were slightly offset by a $1.04 per Mcf, or 28.6%, decrease in the average price received for natural gas production. The increase in oil production was due to the continued focus on increased oil drilling throughout 2011 and continuing in 2012 in the Mid-Continent and Permian Basin. Additionally, the acquisition of oil and natural gas properties located in the Gulf of Mexico during the second quarter of 2012 contributed 1,148 MBbl in oil production and 8,505 MMcf in natural gas production during the three-month period ended September 30, 2012.

Due to the long-term nature of the Company’s investment in the development of its properties, the Company enters into oil and natural gas swaps and collars for a portion of its production in order to stabilize future cash inflows for planning purposes. The Company’s derivative contracts are not designated as accounting hedges and, as a result, realized and unrealized gains or losses on commodity derivative contracts are recorded as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Realized gains or losses related to settlements of derivative contracts prior to their respective contractual maturities (“early settlements”) are not considered in the calculation of effective prices. The effective price received for oil for the three-month period ended September 30, 2012 was $91.84 per Bbl compared to $76.94 per Bbl during the same period in 2011. The effective price received for natural gas for the three-month period ended September 30, 2012 was $2.23 per Mcf compared to $3.08 per Mcf during the same period in 2011.

During the three-month period ended September 30, 2012, the exploration and production segment reported a $193.5 million net loss on its commodity derivative positions ($29.0 million realized gain and $222.5 million unrealized loss) compared to a $596.7 million net gain on its commodity derivative positions ($7.8 million realized loss and $604.5 million unrealized gain) in the same period in 2011. The realized gain for the three-month period ended September 30, 2012 was due 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 September 30, 2011 was due to higher oil prices at the time of settlement compared to the contract price for the Company’s oil price swaps. Realized gains of $2.1 million resulting from early settlements were included in the realized gain for the three-month period ended September 30, 2012. Realized gains totaling $9.9 million resulting from early settlements were included in the net realized loss for the three-month period ended September 30, 2011. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized loss on the Company’s commodity contracts recorded during the three-month period ended September 30, 2012 was attributable to an increase in average oil prices at September 30, 2012 compared to the average oil prices at June 30, 2012 or the contract price for contracts entered into during the third quarter of 2012. The unrealized gain on the Company’s commodity contracts recorded during the three months ended September 30, 2011 was attributable to a decrease in average oil prices at September 30, 2011 compared to the average oil prices at June 30, 2011 or the contract price for contracts entered into during the third quarter of 2011.

For the three-month period ended September 30, 2012, the Company had a loss from operations of $48.5 million in its exploration and production segment compared to income from operations of $717.3 million in the same period in 2011. An increase of $169.8 million in oil and natural gas revenues was partially offset by increases of $50.5 million in production expense and $81.7 million in depreciation and depletion on oil and natural gas properties during the three-month period ended September 30, 2012. Additionally, the Company recorded a $193.5 million net loss on derivative contracts for the three months ended September 30, 2012 compared to a $596.7 million net gain for the same period in 2011. See further discussion of these changes under “Consolidated Results of Operations” below.

Exploration and Production Segment — Nine months ended September 30, 2012 compared to the nine months ended September 30, 2011

Exploration and production segment revenues increased $365.3 million, or 40.3%, to $1,271.6 million in the nine-month period ended September 30, 2012 from the same period in 2011, as a result of a 4,385 MBbl, or 51.3%, increase in oil production, a $3.64 per Bbl, or 4.4%, increase in the average price received for oil production and a 12,392 MMcf, or 23.6%, increase in natural gas production. These increases were slightly offset by a $1.43 per Mcf, or 39.1%, decrease in the average price received for natural gas production. The increase in oil production was due to the continued focus on increased oil drilling throughout 2011 and continuing in 2012 in the Mid-Continent and Permian Basin. Additionally, the acquisition of oil and natural gas properties located in the Gulf of Mexico during the second quarter of 2012 contributed 2,068 MBbl in oil production and 13,830 MMcf in natural gas production during the nine-month period ended September 30, 2012.

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The effective price received for oil for the nine-month period ended September 30, 2012 was $89.63 per Bbl compared to $75.30 per Bbl during the same period in 2011. The effective price received for natural gas for the nine-month period ended September 30, 2012 was $2.31 per Mcf compared to $3.41 per Mcf during the same period in 2011.

During the nine-month period ended September 30, 2012, the exploration and production segment reported a $221.7 million net gain on its commodity derivative positions ($7.4 million realized loss and $229.1 million unrealized gain) compared to a $489.1 million net gain on its commodity derivative positions ($34.7 million realized loss and $523.8 million unrealized gain) in the same period in 2011. The realized loss for the nine-month period ended September 30, 2012 was due primarily to non-cash realized losses of $117.1 million resulting from the amendment of certain 2012 derivative contracts to contracts maturing in 2014 and 2015 for the nine-month period ended September 30, 2012. These losses were partially offset by realized gains for the nine-month period ended September 30, 2012 on the Company's oil and natural gas swaps due to lower oil and natural gas prices at the time of settlement compared to the contract price. The realized loss for the nine-month period ended September 30, 2011 was due to higher oil prices at the time of settlement compared to the contract price for the Company’s oil price swaps. The unrealized gains on the Company’s commodity contracts recorded during the nine-month periods ended September 30, 2012 and 2011 were attributable to a decrease in average oil prices at the end of the period compared to the average oil prices at beginning of the period, or the contract price for contracts entered into during the period. Realized gains of $59.5 million and $48.1 million resulting from early settlements were included in the net realized losses for the nine-month periods ended September 30, 2012 and 2011, respectively.

For the nine-month period ended September 30, 2012, the Company had income from operations of $614.0 million in its exploration and production segment compared to income from operations of $834.3 million in the same period in 2011. An increase of $361.9 million in oil and natural gas revenues was offset by a decrease of $267.4 million in gain on derivative contracts and increases of $100.5 million in production expense and $162.7 million in depreciation and depletion on oil and natural gas properties during the nine-month period ended September 30, 2012. See further discussion of these changes under “Consolidated Results of Operations” below.

Drilling and Oil Field Services Segment

The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third-party working interests in wells the Company operates, are included in drilling and services revenues and expenses. Drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation.

As of September 30, 2012, the Company owned 31 drilling rigs. The table below presents a summary of the Company’s rigs as of September 30, 2012 and 2011:



	September 30,
	2012	2011
Rigs
Working for SandRidge	21	21
Working for third parties	9	10
Total operational	30	31
Non-operational	1	—
Total rigs	31	31

Drilling and Oil Field Services Segment — Three months ended September 30, 2012 compared to the three months ended September 30, 2011

Drilling and oil field services segment revenues increased $2.2 million to $27.8 million in the three-month period ended September 30, 2012 from the same period in 2011, and drilling and oil field services segment expenses also increased $2.2 million during the same period to $25.2 million. The increase in revenues and expenses was primarily attributable to an increase in oil field services work performed for third parties, including an increase in third-party working interest owners as a result of higher third-party working interests in wells operated by the Company in the Mid-Continent, during the three-month period ended September 30, 2012. This increase was partially offset by a decrease in the average number of rigs working for third parties during the three-month period ended September 30, 2012 compared to the same period in 2011. Income from operations of $2.5 million in the three-month period ended September 30, 2012 was consistent with income from operations in the 2011 period.

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Drilling and Oil Field Services Segment — Nine months ended September 30, 2012 compared to the nine months ended September 30, 2011

Drilling and oil field services segment revenues increased $15.6 million to $90.7 million in the nine-month period ended September 30, 2012 from the same period in 2011, and drilling and oil field services segment expenses increased $11.4 million during the same period to $80.0 million. The increase in revenues and expenses was primarily attributable to an increase in supplies sold and oil field services work performed for third parties, including an increase in third-party working interest owners as a result of higher third-party working interests in wells operated by the Company in the Mid-Continent, during the nine-month period ended September 30, 2012. This increase was partially offset by a decrease in the average number of rigs working for third parties during the nine-month period ended September 30, 2012 compared to the same period in 2011. This overall increase resulted in income from operations of $10.7 million in the nine-month period ended September 30, 2012 compared to income from operations of $6.5 million in the 2011 period.

Midstream Gas Services Segment

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

The Company owns and operates two gas treating plants in west Texas, which remove CO2 from natural gas production and deliver residue gas to nearby pipelines. During the operational assessments of Phase I and Phase II of the Century Plant, in Pecos County, Texas, the Company has diverted some of its natural gas from the Company’s two existing gas treating plants for processing at the Century Plant. As a result of these assessments, the Century Plant had been taken off line from time to time to resolve certain operational issues. During the third quarter of 2012, Phase I was completed and Occidental took ownership and began operating the Phase I assets for the purpose of separating and removing CO2 from the delivered natural gas stream. The Company is currently in the process of diverting its high CO2 natural gas production through the Century Plant and conducting performance testing for Phase II of the Century Plant. Phase II is expected to be completed by the end of the first quarter of 2013, at which time Occidental will take ownership and begin operating the Phase II related assets. With the completion of Phase I and upon successful completion of the performance testing of Phase II, the use of the Company’s two gas treating plants in west Texas may be limited, the extent of which depends on certain variables, including natural gas prices and the expected need for such plants to supplement treating capacity at the Century Plant in the future. In 2011, the Company evaluated its existing gas treating plants for impairment in connection with the operational phase of Phase I of the Century Plant and concluded no impairment was necessary. The Company continues to monitor the status of the Century Plant, the related impact on its gas treating plants and CO2 compression facilities and natural gas prices. As of September 30, 2012, no impairment of these plants or facilities was deemed necessary.

Midstream Gas Services Segment — Three months ended September 30, 2012 compared to the three months ended September 30, 2011

Midstream gas services segment revenues for the three-month period ended September 30, 2012 were $10.3 million compared to $14.7 million in the same period in 2011. The decrease in revenue was due to a decrease in third-party volumes the Company marketed of approximately 0.7 Bcf as a result of a decrease in volumes processed by the Company's gas treating plants in west Texas and a decrease in natural gas prices. The decrease in revenue resulted in a loss from operations of $3.4 million for the three-month period ended September 30, 2012 compared to a loss from operations of $2.0 million in the same period in 2011.

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Midstream Gas Services Segment — Nine months ended September 30, 2012 compared to the nine months ended September 30, 2011

Midstream gas services segment revenues for the nine-month period ended September 30, 2012 were $26.7 million compared to $52.4 million in the same period in 2011. The decrease in revenue was due to a decrease in third-party volumes the Company marketed of approximately 4.5 Bcf as a result of a decrease in volumes processed by the Company's gas treating plants in west Texas and a decrease in natural gas prices. The decrease in revenue resulted in a loss from operations of $9.8 million for the nine-month period ended September 30, 2012 compared to a loss from operations of $7.1 million in the same period in 2011.

Consolidated Results of Operations

Three months ended September 30, 2012 compared to the three months ended September 30, 2011

Revenues. Total revenues increased 46.5% for the three months ended September 30, 2012 from the same period in 2011. This increase was primarily due to the increase in oil and natural gas sales.



	Three Months Ended September 30,
	2012		2011		$ Change			% Change
	(In thousands)
Revenues
Oil and natural gas	$	488,252	$	318,453	$	169,799		53.3	%
Drilling and services	27,760		25,547		2,213			8.7	%
Midstream and marketing	10,708		15,092		(4,384		)	(29.0	)%
Other	6,078		4,661		1,417			30.4	%
Total revenues	$	532,798	$	363,753	$	169,045		46.5	%

Oil and natural gas revenues increased $169.8 million for the three-month period ended September 30, 2012 compared to the same period in 2011, as a result of an increase in the amount of oil and natural gas produced and an increase in the average price received for oil production. This increase was slightly offset by a decrease in the average price received for natural gas production. See further discussion of oil and natural gas production and prices received during the three-month period ended September 30, 2012 under “Results by Segment—Exploration and Production Segment.”

Midstream and marketing revenues decreased $4.4 million, or 29.0%, in the three-month period ended September 30, 2012 compared to the same period in 2011. The decrease was attributable to a decrease in third-party volumes the Company marketed in west Texas and a decrease in natural gas prices for the three-month period ended September 30, 2012 compared to the same period in 2011.

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Expenses. Total expenses increased to $608.7 million for the three months ended September 30, 2012 compared to $(332.8) million for the same period in 2011. The increase was due, in part, to the increases in production expense, depreciation and depletion on oil and natural gas properties and general and administrative expense. Additionally, expenses for the three months ended September 30, 2012 included a $193.5 million loss on derivative contracts compared to a $596.7 million gain on derivative contracts in the three months ended September 30, 2011.



	Three Months Ended September 30,
	2012		2011			$ Change			% Change
	(In thousands)
Expenses
Production	$	137,033	$	86,580		$	50,453		58.3	%
Production taxes	12,967		10,368			2,599			25.1	%
Drilling and services	15,666		16,209			(543		)	(3.3	)%
Midstream and marketing	10,674		14,624			(3,950		)	(27.0	)%
Depreciation and depletion — oil and natural gas	166,126		84,472			81,654			96.7	%
Depreciation and amortization — other	16,497		13,551			2,946			21.7	%
Accretion on asset retirement obligation	9,053		2,253			6,800			301.8	%
General and administrative	46,781		36,272			10,509			29.0	%
Loss (gain) on derivative contracts	193,497		(596,736		)	790,233			(132.4	)%
Loss (gain) on sale of assets	375		(422		)	797			(188.9	)%
Total expenses	$	608,669	$	(332,829	)	$	941,498		(282.9	)%

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 $50.5 million primarily due to operating expenses associated with additional oil wells that began producing during 2011 and 2012 and oil and natural gas properties located in the Gulf of Mexico that were acquired during the second quarter of 2012. Total combined production increased 53.3%, with oil production increasing 54.9% and natural gas production increasing 51.6% for the three-month period ended September 30, 2012 compared to the same period in 2011.

Production taxes increased for the three-month period ended September 30, 2012 compared to the 2011 period. Approximately 27% of the Company’s oil and natural gas production for the three-month period ended September 30, 2012 was from production in the Gulf of Mexico, including from properties that were acquired during the second quarter of 2012. This production is not subject to production tax. Excluding Gulf of Mexico oil and natural gas production, the increase in production taxes is consistent with the increase in the oil and natural gas production in the Mid-Continent and Permian Basin.

Midstream and marketing expenses decreased $4.0 million, or 27.0%, due to decreased natural gas volumes purchased from third parties as a result of decreased natural gas production in west Texas and a decrease in natural gas volumes processed at the Company’s gas treating plants during the three-month period ended September 30, 2012.

Depreciation and depletion for the Company’s oil and natural gas properties increased $81.7 million for the three-month period ended September 30, 2012 from the same period in 2011. The increase was due to an increase of 53.3% in the Company’s combined production volume as well as an increase in the depreciation and depletion per Boe to $17.54 in the three-month period ended September 30, 2012 from $13.67 per Boe in the same period in 2011 primarily as a result of oil and natural gas properties located in the Gulf of Mexico that were acquired during the second quarter of 2012.

Depreciation and amortization - other increased $2.9 million or 21.7% for the three-month period ended September 30, 2012 due primarily to an increase in other depreciable fixed assets, including drilling equipment, electrical infrastructure projects and renovations to the Company's corporate headquarters.

Accretion on asset retirement obligation increased $6.8 million as a result of the 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.

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General and administrative expenses increased $10.5 million, or 29.0%, to $46.8 million for the three-month period ended September 30, 2012 from the same period in 2011, due primarily to an increase in compensation costs as a result of an increase in the number of employees.

The Company recorded a net loss of $193.5 million ($29.0 million realized gain and $222.5 million unrealized loss) on its commodity derivative contracts for the three-month period ended September 30, 2012 compared to a net gain of $596.7 million ($7.8 million realized loss and $604.5 million unrealized gain) in the same period in 2011. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment—Exploration and Production Segment.”

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



	Three Months Ended September 30,
	2012			2011			$ Change			% Change
	(In thousands)
Other income (expense)
Interest expense	$	(81,894	)	$	(58,952	)	$	(22,942	)	38.9	%
Loss on extinguishment of debt	(3,056		)	—			(3,056		)	(100.0	)%
Other income (expense), net	1,242			(672		)	1,914			(284.8	)%
Total other expense	(83,708		)	(59,624		)	(24,084		)	40.4	%
(Loss) income before income taxes	(159,579		)	636,958			(796,537		)	(125.1	)%
Income tax expense	173			954			(781		)	(81.9	)%
Net (loss) income	(159,752		)	636,004			(795,756		)	(125.1	)%
Less: net income attributable to noncontrolling interest	10,668			60,895			(50,227		)	(82.5	)%
Net (loss) income attributable to SandRidge Energy, Inc.	$	(170,420	)	$	575,109		$	(745,529	)	(129.6	)%

Interest expense increased $22.9 million for the three-month period ended September 30, 2012 compared to the same period in 2011, due primarily to interest expense on the 8.125% Senior Notes due 2022 issued in April 2012, additional 7.5% Senior Notes due 2021 issued in August 2012 and 7.5% Senior Notes due 2023 issued in August 2012.

In connection with the tender offer to repurchase the Company’s Senior Floating Rate Notes, the Company recognized a loss on extinguishment of debt of $3.1 million for the three months ended September 30, 2012. This loss represents the premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes.

For the three-month periods ended September 30, 2012 and 2011, the Company had a relatively low effective tax rate due to a full valuation allowance against its net deferred tax asset.

Net income attributable to noncontrolling interest decreased to $10.7 million for the three-month period ended September 30, 2012 from $60.9 million during the same period in 2011 due to the unrealized losses on the Royalty Trusts' open derivative contracts during the three-month period ended September 30, 2012.

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Nine months ended September 30, 2012 compared to the nine months ended September 30, 2011

Revenues. Total revenues increased 33.8% for the nine months ended September 30, 2012 from the same period in 2011. This increase was primarily due to the increase in oil and natural gas sales.



	Nine Months Ended September 30,
	2012		2011		$ Change			% Change
	(In thousands)
Revenues
Oil and natural gas	$	1,259,375	$	897,506	$	361,869		40.3	%
Drilling and services	90,701		75,118		15,583			20.7	%
Midstream and marketing	27,866		53,663		(25,797		)	(48.1	)%
Other	14,925		15,088		(163		)	(1.1	)%
Total revenues	$	1,392,867	$	1,041,375	$	351,492		33.8	%

Oil and natural gas revenues increased $361.9 million for the nine-month period ended September 30, 2012 compared to the same period in 2011, as a result of an increase in the amount of oil and natural gas produced and an increase in the average price received for oil production. These increases were slightly offset by a decrease in the average price received for natural gas production. See further discussion of oil and natural gas production and prices received during the nine-month period ended September 30, 2012 under “Results by Segment - Exploration and Production Segment.”

Drilling and services revenues increased $15.6 million for the nine-month period ended September 30, 2012 compared to the same period in 2011 due to an increase in supplies sold and oil field services work performed for third parties, including third-party working interest owners as a result of higher third-party working interests in wells operated by the Company in the Mid-Continent, during the nine-month period ended September 30, 2012.

Midstream and marketing revenues decreased $25.8 million, or 48.1%, in the nine-month period ended September 30, 2012 compared to the same period in 2011. The decrease was attributable to a decrease in third-party volumes the Company marketed due to decreased natural gas production in west Texas and a decrease in natural gas prices during the nine-month period ended September 30, 2012 compared to the same period in 2011.

Expenses. Total expenses increased to $858.0 million for the nine months ended September 30, 2012 compared to $272.9 million for the same period in 2011. The increase was due, in part, to the increases in production expense, depreciation and depletion on oil and natural gas properties and general and administrative expense. Additionally, expenses for the nine months ended September 30, 2012 reflect a $221.7 million gain on derivative contracts, compared to a $489.1 million gain on derivative contracts in the nine months ended September 30, 2011.



	Nine Months Ended September 30,
	2012			2011			$ Change			% Change
	(In thousands)
Expenses
Production	$	342,824		$	242,371		$	100,453		41.4	%
Production taxes	36,222			33,610			2,612			7.8	%
Drilling and services	52,468			49,308			3,160			6.4	%
Midstream and marketing	27,187			52,780			(25,593		)	(48.5	)%
Depreciation and depletion — oil and natural gas	392,452			229,759			162,693			70.8	%
Depreciation and amortization — other	46,357			39,918			6,439			16.1	%
Accretion on asset retirement obligation	19,625			7,039			12,586			178.8	%
General and administrative	158,798			108,364			50,434			46.5	%
Gain on derivative contracts	(221,707		)	(489,096		)	267,389			(54.7	)%
Loss (gain) on sale of assets	3,755			(1,148		)	4,903			(427.1	)%
Total expenses	$	857,981		$	272,905		$	585,076		214.4	%

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Production expenses increased $100.5 million primarily due to operating expenses associated with additional oil wells that began producing during 2011 and the first nine months of 2012, and from oil and natural gas properties located in the Gulf of Mexico that were acquired during the second quarter of 2012. Total production increased 37.3% with oil production increasing 51.3% for the nine-month period ended September 30, 2012 compared to the same period in 2011.

Production taxes increased slightly for the nine-month period ended September 30, 2012 compared to the 2011 period. Approximately 20% of the Company’s oil and natural gas production for the nine-month period ended September 30, 2012 was from production in the Gulf of Mexico, including from properties acquired during the second quarter of 2012. This production is not subject to production tax. Excluding Gulf of Mexico oil and natural gas production, the increase in production taxes is consistent with the increase in the oil and natural gas production in the Mid-Continent and Permian Basin.

Midstream and marketing expenses decreased $25.6 million, or 48.5%, due to decreased natural gas volumes purchased from third parties and a decrease in natural gas volumes processed at the Company’s gas treating plants in west Texas during the nine-month period ended September 30, 2012.

Depreciation and depletion for the Company’s oil and natural gas properties increased $162.7 million for the nine-month period ended September 30, 2012 from the same period in 2011. The increase was due to an increase of 37.3% in the Company’s combined production volume as well as an increase in the depreciation and depletion per Boe to $16.54 in the nine-month period ended September 30, 2012 from $13.30 per Boe in the same period in 2011 primarily as a result of oil and natural gas properties located in the Gulf of Mexico that were acquired during the second quarter of 2012.

Depreciation and amortization - other increased $6.4 million or 16.1% for the nine-month period ended September 30, 2012 due to an increase in other depreciable fixed assets, including drilling equipment, electrical infrastructure projects and renovations to the Company's corporate headquarters.

Accretion on asset retirement obligation increased $12.6 million as a result of the 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.

General and administrative expenses increased $50.4 million, or 46.5%, to $158.8 million for the nine-month period ended September 30, 2012 from the same period in 2011. This increase is due primarily to $13.1 million in costs associated with the acquisition of oil and natural gas properties located in the Gulf of Mexico during the second quarter of 2012, a $24.8 million increase in compensation costs as a result of an increase in the number of employees, a $6.6 million increase in legal and consulting fees and a $3.9 million increase in advertising expense.

The Company recorded a net gain of $221.7 million ($7.4 million realized loss and $229.1 million unrealized gain) on its commodity derivative contracts for the nine-month period ended September 30, 2012 compared to a net gain of $489.1 million ($34.7 million realized loss and $523.8 million unrealized gain) in the same period in 2011. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment—Exploration and Production Segment.”

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	Nine Months Ended September 30,
	2012			2011			$ Change			% Change
	(In thousands)
Other income (expense)
Interest expense	$	(217,428	)	$	(180,077	)	$	(37,351	)	20.7	%
Bargain purchase gain	124,446			—			124,446			100.0	%
Loss on extinguishment of debt	(3,056		)	(38,232		)	35,176			(92.0	)%
Other income, net	3,629			662			2,967			448.2	%
Total other expense	(92,409		)	(217,647		)	125,238			(57.5	)%
Income before income taxes	442,477			550,823			(108,346		)	(19.7	)%
Income tax benefit	(103,414		)	(6,013		)	(97,401		)	1,619.8	%
Net income	545,891			556,836			(10,945		)	(2.0	)%
Less: net income attributable to noncontrolling interest	111,626			74,055			37,571			50.7	%
Net income attributable to SandRidge Energy, Inc.	$	434,265		$	482,781		$	(48,516	)	(10.0	)%

Interest expense increased $37.4 million for the nine-month period ended September 30, 2012 compared to the same period in 2011. The increase was a result of the 7.5% Senior Notes due 2021 issued in March 2011, 8.125% Senior Notes due 2022 issued in April 2012, additional 7.5% Senior Notes due 2021 issued in August 2012 and 7.5% Senior Notes due 2023 issued in August 2012. In addition, the Company elected to issue senior notes to fund the cash portion of the Dynamic Acquisition rather than utilize previously secured committed financing. As a result, the fees associated with the committed financing of $10.9 million were fully expensed during the nine-month period ended September 30, 2012. These increases were partially offset by a decrease in interest expense as a result of the tender offer for, and subsequent redemption of, the 8.625% Senior Notes due 2015 in 2011 and a decrease in interest expense on the senior credit facility as there were no amounts outstanding during the nine-month period ended September 30, 2012.

The bargain purchase gain recorded during the nine-month period ended September 30, 2012 resulted from the excess of net assets acquired over consideration paid in the Dynamic Acquisition in April 2012. The Company 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.

In connection with the tender offer to repurchase the Company’s Senior Floating Rate Notes in August 2012, the Company recognized a loss on extinguishment of debt of $3.1 million for the nine-month period ended September 30, 2012. This loss represents the premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes. In connection with the tender offer to repurchase and the redemption of the 8.625% Senior Notes due 2015 in March 2011, the Company recognized a loss on extinguishment of debt of $38.2 million for the nine-month period ended September 30, 2011. The loss represents the premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes.

The Company reported an income tax benefit of $103.4 million for the nine-month period ended September 30, 2012. The benefit was primarily attributable to the release of a portion of the Company’s valuation allowance against its net deferred tax asset during the period. Net deferred tax liabilities recorded as a result of the Dynamic Acquisition reduced the Company’s existing net deferred tax asset position, allowing a corresponding reduction in the valuation allowance against the net deferred tax asset. In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the acquisition of Arena in order to finalize the purchase price allocation. In connection therewith, the Company recorded an additional net deferred tax liability of $7.0 million. The tax benefit of $6.0 million for the nine-month period ended September 30, 2011 is primarily comprised of the partial release of the Company’s previously recorded valuation allowance against its net deferred tax asset.

Net income attributable to noncontrolling interest increased to $111.6 million for the nine-month period ended September 30, 2012 from $74.1 million during the same period in 2011 due to the completion of the Mississippian Trust I, Permian Trust and Mississippian Trust II initial public offerings in April 2011, August 2011 and April 2012, respectively, as it reflects the portion of net income attributable to beneficial interests of the Royalty Trusts held by third parties.

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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 issuance of equity and debt securities in the capital markets, availability of borrowings under the senior credit facility and proceeds from sales or other monetizations of assets, recent examples of which are described below.


•	In January 2012, the Company received approximately $272.5 million from the sale of working interests in the Mississippian formation and related drilling carry.


•	In April 2012, the Company received proceeds of approximately $730.1 million after deducting offering expenses, from the issuance of the 8.125% Senior Notes due 2022. Proceeds were primarily used to finance the cash portion of the Dynamic Acquisition purchase price and to pay related fees and expenses


•	In April 2012, the Company received net proceeds of approximately $587.1 million as partial consideration for the conveyance of royalty interests in certain of the Company’s oil and natural gas properties to the Mississippian Trust II.


•	In June 2012, the Company received approximately $130.8 million for the sale of its tertiary recovery properties.


•	In August 2012, as described in “Recent Developments,” the Company received proceeds of approximately $1.1 billion, net of underwriting fees, from the issuance of 7.5% Senior Notes due 2023 and additional 7.5% Senior Notes due 2021.


•	During the nine-month period ended September 30, 2012, the Company sold a portion of its Mississippian Trust I and Permian Trust common units in transactions exempt from registration pursuant to Rule 144 under the Securities Act for total proceeds of approximately $123.5 million.

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 repayment of amounts outstanding under its senior credit facility, the payment of dividends on its outstanding convertible perpetual preferred stock, interest payments on its outstanding debt and from time to time, the redemption of senior notes. The Company maintains access to funds that may be needed to meet capital funding requirements through its senior credit facility.

Working Capital

The Company’s working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under its senior credit facility and changes in the fair value of its outstanding commodity derivative instruments. Absent any significant effects from its commodity derivative instruments, the Company 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 and it historically has used excess cash to pay down borrowings outstanding, if any, under its credit arrangements.

At September 30, 2012, the Company had a working capital surplus of $314.4 million compared to a deficit of $257.7 million at December 31, 2011. Current assets increased $787.3 million at September 30, 2012, compared to current assets at December 31, 2011, primarily due to a $466.0 million increase in cash and cash equivalents, a $175.8 million increase in accounts receivable and a $77.1 million increase in the net asset positions on the Company’s current derivative contracts. The increase in cash and cash equivalents is primarily due to net proceeds received from the issuance of the 7.5% Senior Notes due 2023 and the additional 7.5% Senior Notes due 2021 after funding the tender offer for, and subsequent redemption of, the Senior Floating Rate Notes due 2014. The increase in accounts receivable is due to an increase in amounts due from working interest partners, as a result of higher third-party working interests in the Mid-Continent, increased drilling activity and oil and natural gas sales in the Mid-Continent and Permian Basin and increased oil and natural gas sales in the Gulf of Mexico as a result of the Dynamic Acquisition in April 2012. The increase in the Company’s asset positions on its current derivative contracts is due to a decrease in oil prices from December 31, 2011. Current liabilities increased $215.3 million, primarily due to a $272.4 million increase in accounts payable and accrued expenses as a result of increased drilling activity and an increase in payables as a result of the Dynamic Acquisition and an $84.1 million increase in the Company’s current asset retirement obligation due to future plugging and abandonment obligations assumed from Dynamic. These increases were partially offset by a $96.9 million decrease in the Company’s current liability positions on derivative contracts as a result of decreased oil prices from December 31, 2011 and a $43.3 million decrease in billings and estimated contract loss in excess of costs incurred as a result of additional costs incurred on the Century Plant construction project.

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The Company expects to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2012 and 2013 with cash flows from operating activities, its existing cash balances, funding commitments from third parties for drilling carries, potential sales of royalty trust units, potential sales of working interests, potential access to capital markets and the availability under the senior credit facility. A significant portion of the Company’s 2012 and 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 nine-month periods ended September 30, 2012 and 2011 are presented in the following table and discussed below:



	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Cash flows provided by operating activities	$	584,230		$	321,623
Cash flows used in investing activities	(2,040,585		)	(698,164		)
Cash flows provided by financing activities	1,922,354			696,115
Net increase in cash and cash equivalents	$	465,999		$	319,574

Cash Flows from Operating Activities

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

Net cash provided by operating activities for the nine-month periods ended September 30, 2012 and 2011 was $584.2 million and $321.6 million, respectively. The increase in cash provided by operating activities in the 2012 period compared to the 2011 period was primarily due to an increase in oil and natural gas sales, partially offset by an increase in related operating costs, as a result of increased oil and natural gas production and prices received for oil production.

Cash Flows from Investing Activities

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

Cash flows used in investing activities increased to $2.0 billion in the nine-month period ended September 30, 2012 from $698.2 million in the same period in 2011 due to the acquisition of oil and natural gas properties located in the Gulf of Mexico during the second quarter of 2012, and an increase in capital expenditures as a result of the continued development of the Company’s oil properties in the Mid-Continent and Permian Basin. These amounts were partially offset by proceeds from the sale of assets, including the sale of working interests to Repsol, and the sale of the Company’s tertiary recovery properties during the nine-month period ended September 30, 2012. Proceeds from the sale of assets totaled $422.2 million in the nine-month period ended September 30, 2012 compared to $624.8 million in the same period in 2011.

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Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the nine-month periods ended September 30, 2012 and 2011 are summarized below:



	Nine Months Ended September 30,
	2012		2011
	(In thousands)
Capital Expenditures
Exploration and production	$	1,510,614	$	1,248,288
Drilling and oil field services	28,323		20,692
Midstream gas services	61,958		15,392
Other	90,875		37,818
Capital expenditures, excluding acquisitions	1,691,770		1,322,190
Acquisitions	837,019		22,751
Total	$	2,528,789	$	1,344,941

Cash Flows from Financing Activities

The Company’s financing activities provided $1.9 billion in cash for the nine-month period ended September 30, 2012 compared to $696.1 million in the same period in 2011. Cash provided by financing activities during the 2012 period was primarily comprised of $1.1 billion from the issuance of the 7.5% Senior Notes due 2023 and additional 7.5% Senior Notes due 2021, $750.0 million from the issuance of the 8.125% Senior Notes due 2022, $587.1 million from the issuance of common units by the Mississippian Trust II and $123.5 million of proceeds from the sale of Mississippian Trust I and Permian Trust common units owned by the Company. These proceeds were offset by the $350.0 million purchase of the Senior Floating Rate Notes, $127.0 million in distributions to royalty trust unitholders, $48.2 million in debt issuance costs, $45.0 million in dividends paid on the Company’s convertible perpetual preferred stock and $38.7 million in payments to settle financing derivatives.

Cash provided by financing activities during the nine months ended September 30, 2011 was primarily comprised of $880.7 million of net proceeds from the issuance of the 7.5% Senior Notes due 2021, $336.9 million of net proceeds from the issuance of common units by the Mississippian Trust I and $580.6 million of net proceeds from the issuance of common units by the Permian Trust. These amounts were offset by the purchase and redemption of $650.0 million aggregate principal amount of the 8.625% Senior Notes due 2015 and the related premium paid of $30.3 million, $340.0 million of net repayments under the senior credit facility and $46.2 million of dividends paid on the Company’s convertible perpetual preferred stock.

Indebtedness

Long-term debt consists of the following at September 30, 2012 (in thousands):



9.875% Senior Notes due 2016, net of $9,383 discount	$	356,117
8.0% Senior Notes due 2018	750,000
8.75% Senior Notes due 2020, net of $6,016 discount	443,984
7.5% Senior Notes due 2021, including premium of $4,426	1,179,426
8.125% Senior Notes due 2022	750,000
7.5% Senior Notes due 2023, net of $4,096 discount	820,904
Total debt	$	4,300,431

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.

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Maturities of Long-Term Debt. As of September 30, 2012, aggregate maturities of long-term debt, excluding discounts and premiums, for the next five fiscal years are as follows (in thousands):



2012	$	—
2013	—
2014	—
2015	—
2016	365,500
Thereafter	3,950,000
Total debt	$	4,315,500

Senior Credit Facility. The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. The Company pays a 0.5% commitment fee on any available portion of the senior credit facility. 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.

On March 29, 2012, the senior credit facility was amended and restated to, among other things, (a) increase the borrowing base to $1.0 billion from $790.0 million, (b) allow for the incurrence or issuance of additional debt (including up to $750.0 million of unsecured debt to finance the cash portion of the Dynamic purchase price and the related costs and expenses), (c) permit the Company to designate certain of its subsidiaries as unrestricted subsidiaries, and (d) effective on and after June 30, 2012, establish the financial covenants as maintaining agreed upon levels for (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total funded debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded. As of and during the three and nine-month periods ended September 30, 2012, the Company was in compliance with all applicable financial covenants under the senior credit facility.

In August 2012, the borrowing base was reduced to $775.0 million from $1.0 billion as a result of the issuance of 7.5% Senior Notes due 2023 and additional 7.5% Senior Notes due 2021, as described below.

At September 30, 2012, the Company had no amount outstanding under the senior credit facility and $28.8 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $746.2 million at September 30, 2012. The senior credit facility matures in March 2017.

Senior Notes. In April 2012, concurrent with the closing of the Dynamic Acquisition, the Company issued $750.0 million of unsecured 8.125% Senior Notes due 2022 to finance the cash portion of the consideration paid in the Dynamic Acquisition.

In August 2012, the Company issued $275.0 million of additional unsecured 7.5% Senior Notes due 2021 and $825.0 million of unsecured 7.5% Senior Notes due 2023. Net proceeds from this offering were used to fund the Company’s tender offer for, and subsequent redemption of, its Senior Floating Rate Notes and for general corporate purposes, including to fund the Company’s capital expenditures.

On October 11, 2012, the Company commenced registered exchange offers for the 2012 Senior Notes. The terms of the senior notes to be issued in the exchange offers will be identical to the terms of the respective series of 2012 Senior Notes to be exchanged, except that the transfer restrictions, registration rights and provisions for additional interest relating to the exchanged notes will not apply to the senior notes to be issued in the exchange offers. The exchange offers are expected to close in November 2012.

For more information about the senior credit facility and the senior notes, see Note 9 to the unaudited condensed consolidated financial statements included in this Quarterly Report.

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Outlook

The Company’s 2012 and 2013 budget for capital expenditures, including expenditures related to the Company’s drilling programs for the Royalty Trusts, is approximately $2.15 billion and $1.75 billion, respectively. The majority of the Company’s capital expenditures is discretionary and could be curtailed if the Company’s cash flows decline from expected levels or if the Company is unable to obtain capital on attractive terms. The Company and one of its wholly owned subsidiaries have entered into development agreements with the Mississippian Trust I, the Permian Trust and the Mississippian Trust II that obligate the Company to drill, or cause to be drilled, a specified number of wells within specific areas of mutual interest for each trust by December 31, 2015, March 31, 2016 and December 31, 2016, respectively. Additionally, the Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements.

The Company depends on cash flows from operating activities, funding commitments from third parties for drilling carries and the availability of borrowings under its 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 sales or other monetizations of assets to fund its capital expenditures. Based on current cash balances, anticipated oil and natural gas prices and production, commodity derivative contracts in place, availability under the senior credit facility, potential access to capital markets, potential sales of royalty trust units owned by the Company and potential sales of working interests, including those with associated 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 2012 and 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 further borrowings to fund capital expenditures.

On November 8, 2012, the Company announced that it is exploring the sale of its oil and natural gas properties in the Permian Basin other than those associated with the Permian Trust. The oil and natural gas properties contemplated to be sold produce approximately 24,500 Boe per day. Proceeds from any potential sale would be used to fund the Company's capital expenditure program in the Mississippian Play and to repay debt. If an agreement is entered into, the Company will evaluate the impact of the transaction on its existing assets including goodwill.

The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depend on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows, and while fixed price swap contracts are in place for the majority of expected oil production for 2012 and 2013, fixed price swap contracts are in place for only a portion of expected oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. The Company may increase or decrease planned capital expenditures depending on oil and natural gas prices, the availability of capital through asset sales and the issuance of additional equity or long-term debt.

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

As of September 30, 2012, the Company’s cash and cash equivalents were $673.7 million, including $9.4 million attributable to the Company’s consolidated VIEs which is available to satisfy only obligations of the VIEs. The Company had approximately $4.3 billion in total debt outstanding and $28.8 million in outstanding letters of credit with no amount outstanding under its senior credit facility at September 30, 2012. As of and for the three and nine-month periods ended September 30, 2012, the Company was in compliance with applicable covenants under all of its senior notes and senior credit facility. As of November 5, 2012, the Company’s cash and cash equivalents were approximately $534.1 million, including $8.7 million attributable to the Company’s consolidated VIEs. Additionally, there was no amount outstanding under the Company’s senior credit facility and $28.8 million in outstanding letters of credit.

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Contractual Obligations

From time to time, the Company enters into transactions that significantly change its contractual obligations. Since December 31, 2011 the Company issued new senior notes, completed the Dynamic Acquisition and the Mississippian Trust II public offering in April 2012, completed the acquisition of the Gulf of Mexico Properties and sale of tertiary recovery properties in June 2012, issued new senior notes in August 2012 and retired the Company’s Senior Floating Rate Notes in September 2012. These transactions resulted in the following significant changes to the Company’s contractual obligations from those presented in the 2011 Form 10-K:


•	8.125% Senior Notes Issued in Conjunction with Dynamic Acquisition. The principal amount due of $750.0 million in October 2022 is included in the maturities of long term debt table under Indebtedness above. Interest payments due on the 8.125% Senior Notes as of September 30, 2012 are $15.2 million for 2012, $60.9 million per year for 2013 through 2016 and $353.3 million thereafter.


•	Asset Retirement Obligation Resulting from Acquisition of Properties Located in the Gulf of Mexico. As of September 30, 2012, amounts associated with acquired properties are approximately $16.5 million, $67.2 million, $42.9 million, $30.1 million, $42.8 million and $135.5 million due in 2012, 2013, 2014, 2015, 2016 and thereafter, respectively.


•	Drilling Contracts with Third Parties Resulting from Dynamic Acquisition. As of September 30, 2012, future commitments to third-party rig operators on the properties obtained in the Dynamic Acquisition are approximately $13.4 million and $20.0 million in 2012 and 2013, respectively.

•

Development Agreements with Royalty Trusts. The estimated cost at September 30, 2012 to fulfill the drilling obligations to the Royalty Trusts, including obligations to the Mississippian Trust II, was approximately $500.0 million. See Note 3 to the unaudited condensed consolidated financial statements included in this Quarterly Report for discussion of the drilling obligations to the Royalty Trusts.


•	CO₂ Purchase Commitment. As a result of the sale of the Company’s tertiary recovery properties in June 2012, the Company was relieved of its commitment to purchase CO₂for use in these operations. As of December 31, 2011, the Company’s obligation under this commitment was $22.8 million


•	Additional 7.5% Senior Notes due 2021 Issued in August 2012. The principal amount due of $275.0 million in March 2021 is included in the maturities of long-term debt table under Indebtedness above. Interest payments due on the additional 7.5% Senior Notes as of September 30, 2012 are $5.2 million for 2012, $20.6 million per year for 2013 through 2016 and $86.7 million thereafter.


•	7.5% Senior Notes due 2023 Issued in August 2012. The principal amount due of $825.0 million in February 2023 is included in the maturities of long-term debt table under Indebtedness above. Interest payments due on the 7.5% Senior Notes due 2023 as of September 30, 2012 are $15.5 million for 2012, $61.9 million per year for 2013 through 2016 and $379.2 million thereafter.

•

Tender Offer and Redemption of Senior Floating Rate Notes in August 2012. The $350.0 million of Senior Floating Rate Notes are no longer included in the maturities of long-term debt table under Indebtedness above as a result of the Company's tender offer for, and subsequent redemption of, these notes. Estimated future interest payments no longer due on the Senior Floating Rate Notes using interest rates at December 31, 2011 are $3.5 million for 2012, $14.0 million for 2013 and $3.5 million for 2014.

•

Treating Agreement Commitment. Under a 30-year treating agreement with Occidental, the Company is required to deliver a total of approximately 3,200 Bcf of CO2 during the agreement period. If the Company does not meet the CO2 volume requirements, the Company will have to pay a fee for any volume shortfalls. Based upon current natural gas production levels and the completion of Phase I in the third quarter of 2012, the Company expects to incur between approximately $8.0 million and $9.5 million at December 31, 2012 for amounts related to the Company’s shortfall in meeting its 2012 delivery obligations. The Company expects to incur 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.

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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 2011 Form 10-K.

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 14 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 in considering whether to maintain a valuation allowance on its net deferred tax asset. Factors considered are, but 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. While the Company's earnings are trending upward and prospects of future earnings may exist, the Company's 36-month cumulative earnings at September 30, 2012 remained at a loss. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.

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 substantially. Since 2009, natural gas prices have remained relatively low. In 2008, the Company engaged in a strategy to change its focus from the exploration and production of natural gas to that of oil based on the view that natural gas prices would remain under long-term pressure due to the continued drilling in gas focused plays and that oil would provide a more stable revenue stream for the Company over the long-term. As a result of this strategy, the Company's revenues are now primarily derived from oil sales and the Company continues to take additional steps to further ensure shareholder 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 evaluating whether to release all or a portion of the valuation allowance, the Company concluded that the objectively verifiable negative evidence of cumulative losses in the recent years outweighs the subjective positive evidence of the upward trend in recent earnings continuing through the prospects of future earnings. Accordingly, the Company has not changed its judgment regarding the need for a full valuation allowance against its net deferred tax asset. However, a continued and sustained increase in the Company's profitability resulting from its shift in focus from natural gas production to oil production could lead to the reversal of its valuation allowance in the near future. The valuation allowance at December 31, 2011 was $725.9 million and has been reduced during the nine-month period ended September 30, 2012 by $103.3 million as a result of the net deferred tax liability recorded as part of the Dynamic Acquisition. See Note 2 to the unaudited condensed consolidated financial statements included in this Quarterly Report for further information on the Dynamic Acquisition. The amount of the potential release of the valuation allowance and corresponding income tax benefit depend on many factors including, but not limited to, purchase accounting entries related to the Dynamic Acquisition, future potential acquisitions and divestitures, the results of current year operations, and the prospects of future earnings.

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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. The Company’s oil and diesel fixed price swap transactions are settled based upon the average daily prices for the calendar month or quarter of the contract period. The Company’s natural gas fixed price swap transactions are settled based upon New York Mercantile Exchange (“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, and the Houston Ship Channel. The Company’s oil basis swap transactions are settled based upon the spread between the NYMEX or Argus West Texas Intermediate price and the Argus Louisiana Light Sweet price. The Company’s natural gas collars are settled based upon the NYMEX prices on the penultimate commodity business day for the relevant contract. 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. Two-way oil and natural gas collars only result in a cash settlement when the settlement price exceeds the fixed-price ceiling or falls below the fixed-price floor. Three-way oil collars only result in cash settlements when the settlement price exceeds the fixed-price ceiling on the bought call, falls below the fixed-price floor on the bought put, or falls below the fixed-price floor on the sold put. Settlement for oil and diesel derivative contracts occurs in the succeeding month or quarter and natural gas derivative contracts are settled in the production month.

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

See Note 10 to the Company’s unaudited condensed consolidated financial statements included in this Quarterly Report for a summary of the Company’s open commodity derivative contracts.

The following table summarizes the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts for the three and nine-month periods ended September 30, 2012 and 2011(in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Realized (gain) loss(1)	$	(28,970	)	$	7,814		$	7,366		$	34,696
Unrealized loss (gain)	222,467			(604,550		)	(229,073		)	(523,792		)
Loss (gain) on commodity derivative contracts	$	193,497		$	(596,736	)	$	(221,707	)	$	(489,096	)

____________________

(1)

The three and nine-month periods ended September 30, 2012 included $2.1 million and $59.5 million of net realized gains on early settlements. The nine-month period ended September 30, 2012 also included $117.1 million non-cash realized losses on derivative contracts amended in January 2012. The three and nine-month periods ended September 30, 2011 included $9.9 million and $48.1 million of net realized gains on early settlements, respectively.

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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 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. Additionally, the majority of the Company’s counterparties are lenders under its senior credit facility.

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 September 30, 2012, the counterparties to the Company’s open derivative contracts consisted of 19 financial institutions, 16 of which are also lenders under the Company’s senior credit facility. As a result, the Company is not required to post additional collateral under derivative contracts as the majority of the counterparties to the Company’s derivative contracts share in the collateral supporting the Company’s senior credit facility. 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 their royalty interest. See Note 3 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 has 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 tender and redemption in the third quarter of 2012. The interest rate swap terminates April 1, 2013 and has not been designated as a hedge.

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 and nine-month periods ended September 30, 2012 and 2011 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Realized loss	$	2,330		$	2,520		$	6,824		$	7,005
Unrealized gain	(2,033		)	(1,965		)	(5,632		)	(3,374		)
Loss on interest rate swap	$	297		$	555		$	1,192		$	3,631

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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 September 30, 2012 to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

There was no change in the Company’s internal control over financial reporting during the quarter ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. Other Information

ITEM 1. Legal Proceedings

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”), filed a complaint in the District Court of Harris County, Texas, against Arena and SandRidge claiming damages based upon alleged representations by Arena in connection with Aspen’s construction of a natural gas pipeline in west Texas. On October 14, 2011, the complaint was amended to add Odessa Fuels, LLC, Odessa Fuels Marketing, LLC and Odessa Field Services and Compression, LLC as plaintiffs. The plaintiffs’ amended claims seek damages relating to the construction of the pipeline and performance under a related gas purchase agreement, which damages are alleged to approach $100.0 million. The Company intends to defend this lawsuit vigorously. This lawsuit is in the discovery stage.

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

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. filed a lawsuit against SandRidge Energy, Inc., SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain directors and senior executive officers of SandRidge Energy, Inc. (collectively, the “defendants”), in the U.S. District Court for the District of Connecticut. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and the plaintiffs prior to the entry into a participation agreement among Patriot Exploration LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by the plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, the plaintiffs have invested approximately $15.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This lawsuit remains in its early stages pending the Court’s ruling on the Company’s motion to dismiss all of the plaintiffs’ claims.

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

ITEM 1A. Risk Factors

The risk factors below update the Company's risk factors previously disclosed in Item 1A – Risk Factors in the Company’s 2011 Form 10-K.

Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the Company's level of production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations, such as shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. Certain states in which the Company operates, including Texas and Oklahoma, and municipalities have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas finalized

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regulations requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted, such legal requirements could cause project delays and make it more difficult or costly for the Company to perform fracturing to stimulate production from a formation. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce in commercial quantities.

In addition, a number of federal entities are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In April 2012, President Obama issued an executive order that established a working group for the purpose of coordinating policy, information sharing, and planning among federal agencies and offices regarding “unconventional natural gas production,” including hydraulic fracturing. In April 2012, the Environmental Protection Agency ("EPA") issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing that will take effect in 2015. The EPA also has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014, and a study regarding wastewater resulting from hydraulic fracturing activities. Moreover, the EPA plans to propose by 2014 standards that such wastewater must meet before being transported to a treatment plant. In May 2012, the U.S. Department of the Interior issued a proposed rule addressing disclosure of chemicals used, flowback fluid management requirements and other mandates for hydraulic fracturing on federal lands. Additionally, a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices, and certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the U.S. Securities and Exchange Commission ("SEC") to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Bills introduced in both the Senate and the House of Representatives in 2011 would, among other things, amend the federal Safe Drinking Water Act to repeal provisions that currently exempt hydraulic fracturing operations from restrictions that otherwise would apply to underground injection of fluids or propping agents. The studies and initiatives described above, depending on their degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

The cost to construct the Century Plant may exceed estimated costs.

The Company is constructing the Century Plant, a CO₂ treatment plant in Pecos County, Texas, and associated compression and pipeline facilities pursuant to an agreement with Occidental. The Century Plant will be owned and operated by Occidental for the purpose of separating and removing CO₂ from the natural gas stream delivered by the Company. The cost to construct the Century Plant may exceed current estimated costs, which as of September 30, 2012 were expected to exceed the contract amount by approximately $140.0 million. In addition, there are significant risks associated with the operation and performance of a facility such as the Century Plant, and no guarantee that the Century Plant will operate at its designed capacity or otherwise perform as anticipated.

Significant or prolonged decreases in natural gas production in the WTO, due to declines in production from existing wells, depressed commodity prices or otherwise, adversely affect the Company's ability to satisfy certain contractual obligations and revenues and cash flow from the Company's midstream gas services segment.

The Company has entered into a 20-year gas gathering agreement with PGC and a 30-year gas treating agreement with Occidental. These agreements require the Company annually to deliver certain minimum volumes of natural gas to PGC and CO₂ to Occidental and to compensate PGC and Occidental to the extent it does not satisfy the contractual delivery requirements. A material decrease in production in the WTO, where the applicable natural gas assets are located, would result in a decline in the volume of natural gas and CO₂ delivered to PGC and Occidental, respectively, and to the Company's own pipelines and facilities for gathering, transporting and treating. The Company has no control over many factors affecting production activity in the WTO, including prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. As a consequence of these factors, the Company may not be able to find, produce and deliver sufficient quantities of natural gas or CO₂ to meet the Company's contractual delivery obligations. In addition, if the Company fails to connect new wells to its gathering systems, the amount of natural gas it gathers, transports and treats will decline substantially over time and could, upon exhaustion of the current wells, cause the Company to abandon its gathering systems and, possibly cease gathering, transporting and treating operations.

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New derivatives legislation and regulation could adversely affect the Company's ability to hedge risks associated with its business.

The Dodd-Frank Act creates a new regulatory framework for oversight of derivatives transactions by the Commodity Futures Trading Commission (the “CFTC”) and the SEC. Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-Frank Act contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. The Dodd-Frank Act also establishes a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets and also expands the CFTC's power to impose position limits on specific categories of swaps (excluding swaps entered into for bona fide hedging purposes).

There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. However, although the Company may qualify for exceptions, its derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the new legislation, which may increase the Company's transaction costs or make it more difficult for the Company to enter into hedging transactions on favorable terms. The Company's inability to enter into hedging transactions on favorable terms, or at all, could increase its operating expenses and put it at increased exposure to risks of adverse changes in oil and natural gas prices, which could adversely affect the predictability of cash flows from sales of oil and natural gas.

In November 2011, the CFTC finalized rules to establish a position limits regime on certain “core” physical-delivery contracts and their economically equivalent derivatives, some of which reference major energy commodities, including oil and natural gas. The final rules became effective on January 17, 2012 and compliance with the rules was to have become mandatory on October 12, 2012. However, on September 28, 2012 the District Court of the District of Columbia vacated the CFTC's rulemaking and remanded to the CFTC for further proceedings. It is not clear what action if any the CFTC will take in response to the court's decision. However, regulations that subject the Company or its derivatives counterparties to limits on commodity positions could have an adverse effect on its ability to hedge risks associated with its business or on the cost of its hedging activity.

The Company has a substantial amount of indebtedness and other obligations and commitments, which may adversely affect its cash flow and its ability to operate its business.

As of September 30, 2012, the Company's total indebtedness was $4.3 billion, and the Company had preferred stock outstanding with an aggregate liquidation preference of $765.0 million. The Company's substantial level of indebtedness and the dividends payable on its preferred stock outstanding increases the possibility that the Company may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of its indebtedness and/or the preferred stock dividends. The Company's indebtedness and outstanding preferred stock, combined with its lease and other financial obligations and contractual commitments, such as the Company's obligations to drill development wells for multiple royalty trusts, could have other important consequences to the Company. For example, it could:


•	make the Company more vulnerable to adverse changes in general economic, industry and competitive conditions and adverse changes in government regulation;


•	require the Company to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of its cash flows to fund working capital, capital expenditures, acquisitions and other general corporate purposes;


•	limit the Company's flexibility in planning for, or reacting to, changes in its business and the industry in which it operates;


•	place the Company at a disadvantage compared to its competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that the Company's indebtedness prevents it from pursuing; and


•	limit the Company's ability to borrow additional amounts for working capital, capital expenditures, acquisitions, debt service requirements, execution of its business strategy or other purposes.

Any of the foregoing factors could have a material adverse effect on the Company's business, financial condition and results of operations.

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A significant portion of the Company's operations are located in northwest Oklahoma, Kansas, west Texas and the Gulf of Mexico, making it vulnerable to risks associated with operating in a limited number of major geographic areas.

As of September 30, 2012, approximately 97% of the Company's production was located in the Mid-Continent, Permian Basin and Gulf of Mexico. This concentration could disproportionately expose the Company to operational and regulatory risk in these areas. This relative lack of diversification in location of the Company's key operations could expose it to adverse developments in these areas or the oil and natural gas markets, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance. These factors could have a significantly greater impact on the Company's financial condition, results of operations and cash flows than if its properties were more diversified.

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

As part of the Company’s restricted stock program, the Company makes required tax payments on behalf of employees when their stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The shares withheld are initially recorded as treasury shares, then immediately retired. During the quarter ended September 30, 2012, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2012 — July 31, 2012	673,832	$	6.35	N/A	N/A
August 1, 2012 — August 31, 2012	413	$	6.74	N/A	N/A
September 1, 2012 — September 30, 2012	14,645	$	6.58	N/A	N/A

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

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SIGNATURE

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



	SandRidge Energy, Inc.

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

Date: November 9, 2012

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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	Indenture, dated as of August 20, 2012, among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee	8-K	001-33784	4.4	8/21/2012
4.2	Supplemental Indenture, dated August 20, 2012, among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee	8-K	001-33784	4.7	8/21/2012
10.1	Purchase Agreement, dated August 6, 2012, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Barclays Capital Inc., Citigroup Global Markets Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as representatives of the several initial purchasers	8-K	001-33784	10.1	8/10/2012
10.2	Registration Rights Agreement, dated August 20, 2012, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Barclays Capital Inc., Citigroup Global Markets Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC, relating to the 7.5% Senior Notes due 2021 that were issued on August 20, 2012	8-K	001-33784	4.5	8/21/2012
10.3	Registration Rights Agreement, dated August 20, 2012, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Barclays Capital Inc., Citigroup Global Markets Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC, relating to the 7.5% Senior Notes due 2023	8-K	001-33784	4.6	8/21/2012
31.1	Section 302 Certification — Chief Executive Officer					*
31.2	Section 302 Certification — Chief Financial Officer					*
32.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer					*
101.INS	XBRL Instance Document					*
101.SCH	XBRL Taxonomy Extension Schema Document					*
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					*