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 June 30, 2012

OR

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

For the transition period from              to             

Commission File Number: 001-33784

__________________________

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

__________________________

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

Registrant’s telephone number, including area code:

(405) 429-5500

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

__________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes RNo £

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 RNo £

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 July 31, 2012, was491,077,348.

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, the effects of the acquisition of Dynamic Offshore Resources, LLC 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 the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (the “2011 Form 10-K”).

SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended June 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	44
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	61
ITEM 4.	Controls and Procedures	63
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	64
ITEM 1A.	Risk Factors	64
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64
ITEM 6.	Exhibits	65

PART I. Financial Information

ITEM 1.Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

	June 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	421,073		$	207,681
Accounts receivable, net	288,332			206,336
Derivative contracts	204,202			4,066
Inventories	4,055			6,903
Costs in excess of billings	14,768			—
Prepaid expenses	33,648			14,099
Other current assets	14,707			2,755
Total current assets	980,785			441,840
Oil and natural gas properties, using full cost method of accounting
Proved	11,197,054			8,969,296
Unproved	948,369			689,393
Less: accumulated depreciation, depletion and impairment	(5,011,661		)	(4,791,534		)
	7,133,762			4,867,155
Other property, plant and equipment, net	595,250			522,269
Restricted deposits	27,941			27,912
Derivative contracts	98,237			26,415
Goodwill	235,396			235,396
Other assets	107,164			98,622
Total assets	$	9,178,535		$	6,219,609
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	—		$	1,051
Accounts payable and accrued expenses	669,362			506,784
Billings and estimated contract loss in excess of costs incurred	6,321			43,320
Derivative contracts	6,962			115,435
Asset retirement obligation	140,789			32,906
Total current liabilities	823,434			699,496
Long-term debt	3,549,432			2,813,125
Derivative contracts	19,833			49,695
Asset retirement obligation	349,192			95,210
Other long-term obligations	14,566			13,133
Total liabilities	4,756,457			3,670,659
Commitments and contingencies (Note 11)
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at June 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 June 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 June 30, 2012 and December 31, 2011; aggregate liquidation preference of $300,000	3			3
Common stock, $0.001 par value, 800,000 shares authorized; 490,161 issued and 489,191 outstanding at June 30, 2012 and 412,827 issued and 411,953 outstanding at December 31, 2011	475			399
Additional paid-in capital	5,202,119			4,568,856
Treasury stock, at cost	(6,925		)	(6,158		)
Accumulated deficit	(2,360,172		)	(2,937,094		)
Total SandRidge Energy, Inc. stockholders’ equity	2,835,505			1,626,011
Noncontrolling interest	1,586,573			922,939
Total equity	4,422,078			2,548,950
Total liabilities and equity	$	9,178,535		$	6,219,609

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

4

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(Unaudited)
Revenues
Oil and natural gas	$	429,758		$	312,111		$	771,123		$	579,053
Drilling and services	33,632			28,537			62,941			49,571
Midstream and marketing	8,852			16,313			17,158			38,570
Other	6,192			7,813			8,847			10,427
Total revenues	478,434			364,774			860,069			677,621
Expenses
Production	122,481			81,834			205,791			155,791
Production taxes	11,001			12,666			23,255			23,242
Drilling and services	19,241			18,058			36,802			33,099
Midstream and marketing	8,559			15,873			16,513			38,156
Depreciation and depletion — oil and natural gas	139,260			73,826			226,326			145,286
Depreciation and amortization — other	15,348			13,275			29,860			26,368
Accretion of asset retirement obligation	7,965			2,360			10,572			4,786
General and administrative	61,716			37,678			112,017			72,091
(Gain) loss on derivative contracts	(669,850		)	(169,988		)	(415,204		)	107,640
Loss (gain) on sale of assets	300			(524		)	3,380			(725		)
Total expenses	(283,979		)	85,058			249,312			605,734
Income from operations	762,413			279,716			610,757			71,887
Other income (expense)
Interest expense	(68,569		)	(61,687		)	(135,534		)	(121,124		)
Bargain purchase gain	124,446			—			124,446			—
Loss on extinguishment of debt	—			(2,051		)	—			(38,232		)
Other (expense) income, net	(81		)	138			2,387			1,335
Total other income (expense)	55,796			(63,600		)	(8,701		)	(158,021		)
Income (loss) before income taxes	818,209			216,116			602,056			(86,134		)
Income tax benefit	(103,658		)	(7,054		)	(103,587		)	(6,967		)
Net income (loss)	921,867			223,170			705,643			(79,167		)
Less: net income attributable to noncontrolling interest	99,004			13,154			100,958			13,161
Net income (loss) attributable to SandRidge Energy, Inc.	822,863			210,016			604,685			(92,328		)
Preferred stock dividends	13,881			13,881			27,763			27,821
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$	808,982		$	196,135		$	576,922		$	(120,149	)
Earnings (loss) per share
Basic	$	1.75		$	0.49		$	1.34		$	(0.30	)
Diluted	$	1.47		$	0.42		$	1.14		$	(0.30	)
Weighted average number of common shares outstanding
Basic	461,008			398,435			430,802			398,343
Diluted	560,640			495,982			530,378			398,343

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

5

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In thousands)

	SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock			Common Stock				Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	Shares	Amount		Shares		Amount
	(Unaudited)
Six Months Ended June 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	—	—		—		—		—			—			—			336,892			336,892
Distributions to noncontrolling interest owners	—	—		—		—		—			—			—			(1,501		)	(1,501		)
Stock issuance expense	—	—		—		—		(231		)	—			—			—			(231		)
Purchase of treasury stock	—	—		—		—		—			(4,984		)	—			—			(4,984		)
Retirement of treasury stock	—	—		—		—		(4,984		)	4,984			—			—			—
Stock purchases — retirement plans, net of distributions	—	—		(110	)	—		1,998			(978		)	—			—			1,020
Stock-based compensation	—	—		—		—		24,987			—			—			—			24,987
Stock-based compensation excess tax benefit	—	—		—		—		7			—			—			—			7
Issuance of restricted stock awards, net of cancellations	—	—		3,668		—		—			—			—			—			—
Net (loss) income	—	—		—		—		—			—			(92,328		)	13,161			(79,167		)
Convertible perpetual preferred stock dividends	—	—		—		—		—			—			(27,821		)	—			(27,821		)
Balance at June 30, 2011	7,650	$	8	409,918		$	398	$	4,550,689		$	(4,525	)	$	(3,109,725	)	$	359,840		$	1,796,685
Six Months Ended June 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			—			—			52,391			123,549
Distributions to royalty trust unitholders	—	—		—		—		—			—			—			(76,801		)	(76,801		)
Purchase of treasury stock	—	—		—		—		—			(6,704		)	—			—			(6,704		)
Retirement of treasury stock	—	—		—		—		(6,704		)	6,704			—			—			—
Stock purchases — retirement plans, net of distributions	—	—		(96	)	—		1,193			(767		)	—			—			426
Stock-based compensation	—	—		—		—		25,546			—			—			—			25,546
Stock-based compensation excess tax benefit	—	—		—		—		8			—			—			—			8
Issuance of restricted stock awards, net of cancellations	—	—		3,372		2		(2		)	—			—			—			—
Net income	—	—		—		—		—			—			604,685			100,958			705,643
Convertible perpetual preferred stock dividends	—	—		—		—		—			—			(27,763		)	—			(27,763		)
Balance at June 30, 2012	7,650	$	8	489,191		$	475	$	5,202,119		$	(6,925	)	$	(2,360,172	)	$	1,586,573		$	4,422,078

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

6

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Six Months Ended June 30,
	2012			2011
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	705,643		$	(79,167	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	256,186			171,654
Accretion of asset retirement obligation	10,572			4,786
Debt issuance costs amortization	5,401			5,748
Discount amortization on long-term debt	1,285			1,162
Bargain purchase gain	(124,446		)	—
Loss on extinguishment of debt	—			38,232
Deferred income taxes	(103,328		)	(6,986		)
Unrealized (gain) loss on derivative contracts	(455,138		)	79,350
Realized loss on amended derivative contracts	117,108			—
Realized (gain) loss on financing derivatives	(21,125		)	1,576
Loss (gain) on sale of assets	3,380			(725		)
Investment income	(97		)	(67		)
Stock-based compensation	23,277			18,301
Changes in operating assets and liabilities	(1,012		)	23,678
Net cash provided by operating activities	417,706			257,542
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(1,123,040		)	(857,714		)
Acquisitions, net of cash received	(761,575		)	(9,149		)
Proceeds from sale of assets	420,859			369,251
Net cash used in investing activities	(1,463,756		)	(497,612		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	750,000			1,725,000
Repayments of borrowings	(16,029		)	(1,741,795		)
Premium on debt redemption	—			(30,338		)
Debt issuance costs	(27,316		)	(19,640		)
Proceeds from issuance of royalty trust units	587,086			336,892
Proceeds from the sale of royalty trust units	123,549			—
Distributions to royalty trust unitholders	(76,801		)	—
Noncontrolling interest distributions	—			(1,501		)
Stock issuance expense	—			(231		)
Stock-based compensation excess tax benefit	8			7
Purchase of treasury stock	(7,980		)	(6,030		)
Dividends paid — preferred	(27,763		)	(28,980		)
Cash (paid) received on settlement of financing derivatives	(45,312		)	5,438
Net cash provided by financing activities	1,259,442			238,822
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	213,392			(1,248		)
CASH AND CASH EQUIVALENTS, beginning of year	207,681			5,863
CASH AND CASH EQUIVALENTS, end of period	$	421,073		$	4,615
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	8,672		$	2,351
Convertible perpetual preferred stock dividends payable	$	16,572		$	16,572
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.

7

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Business. SandRidge Energy, Inc. (the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on development and production activities 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 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 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 9 for the Company’s open oil and natural gas commodity derivative contracts.

The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating 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 for drilling carry, the sale of non-core assets and the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Based on current cash balances, anticipated oil and natural gas prices and production, availability under the senior credit facility, potential access to capital markets, potential sales of 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

8

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

capital needs for 2012. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced. 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 8 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, with early adoption permitted. The Company will implement ASU 2011-08 for its 2012 goodwill impairment test and does not expect this pronouncement to have any impact on the value of its goodwill.

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. On April 18, 2012, the Company filed a registration statement with the Securities and Exchange Commission that registers under the Securities Act the resale of the shares of common stock issued as consideration in the Dynamic Acquisition.

9

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

The purchase price allocation presented below is preliminary and includes the use of estimates. This preliminary allocation is based on information that was available to management at the time these unaudited condensed consolidated financial statements were prepared. The Company believes the estimates used 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. 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. Changes to the purchase price allocation may result in a corresponding change to the bargain purchase gain in the period of change. The following table summarizes the estimated values of assets acquired and liabilities assumed in the accompanying unaudited condensed consolidated balance sheets and the resulting bargain purchase gain recognized in the accompanying unaudited condensed consolidated statements of operations (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 (the “8.125% Senior Notes”).

(3) In accordance with the Equity Purchase Agreement dated February 1, 2012, 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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

(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 less competition to acquire Dynamic's properties due to their offshore location.

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 are provided for the three and six-month periods ended June 30, 2012 and June 30, 2011 as though the Dynamic Acquisition had been completed as of the beginning of the earliest period presented, or January 1, 2011. The pro forma combined results of operations for the three and six-month periods ended June 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 June 30,					Six Months Ended June 30,
	2012		(1)	2011		2012		(1)	2011		(2)
	(In thousands, except per share data)
Revenues	$	508,198		$	493,445	$	1,038,003		$	906,399
Net income	$	712,007		$	285,245	$	493,282		$	160,426
Income available to SandRidge Energy, Inc. common stockholders	$	599,122		$	258,217	$	364,561		$	118,984
Pro forma net income per common share
Basic	$	1.26		$	0.55	$	0.77		$	0.25
Diluted	$	1.07		$	0.48	$	0.68		$	0.25

____________________

(1) Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and net income per common share exclude $9.9 million and $12.4 million of transaction costs incurred and included in general and administrative expenses for the three and six-month periods ended June 30, 2012, respectively, a $124.4 million bargain purchase gain and a $103.3 million partial valuation allowance release, included in income tax benefit, in the accompanying unaudited condensed consolidated statements of operations for both the three and six-month periods ended June 30, 2012. Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and net income per common share exclude $10.9 million of fees to secure financing for the Dynamic Acquisition incurred and included in interest expense in the accompanying unaudited condensed consolidated statements of operations for the six-month period ended June 30, 2012.

(2) 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, $13.0 million of estimated transaction costs, $10.9 million of fees to secure financing for the Dynamic Acquisition and a partial valuation allowance release of $103.3 million.

11

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Revenues of $108.0 million and income from operations of $28.5 million associated with Dynamic for the period from April 18, 2012 through June 30, 2012 have been included in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012. Additionally, the Company has incurred $9.9 million and $12.4 million in acquisition-related costs for the Dynamic Acquisition, which have been included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 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 $130.0 million, subject to 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. As a result of the sale, the Company was relieved of its commitment to purchase CO₂ for use in these operations. The Company's obligation under this commitment was $22.8 million as of December 31, 2011.

Acquisition of Gulf of Mexico Properties. In June 2012, the Company acquired oil and natural gas properties in the Gulf of Mexico 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 qualifies 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 is 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 estimates the fair value of these properties approximates the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain has been recognized in conjunction with the purchase of these properties. Acquisition-related costs totaling $0.1 million have been expensed as incurred in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012. Revenues of $0.6 million and earnings of $0.2 million generated by the acquired properties from June 21, 2012 to June 30, 2012 have been included in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012.

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 2012.

	(in thousands)
Consideration paid
Cash, net of purchase price adjustment	$	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

12

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

The following unaudited pro forma combined results of operations are provided for the three and six-month periods ended June 30, 2012 and June 30, 2011 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 six-month periods ended June 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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands, except per share data)
Revenues	$	492,233	$	388,248	$	888,485	$	722,247
Net income (loss)	$	923,010	$	233,710	$	707,923	$	(60,835	)
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$	810,125	$	206,675	$	579,202	$	(101,817	)
Pro forma net income (loss) per common share
Basic	$	1.76	$	0.52	$	1.34	$	(0.26	)
Diluted	$	1.47	$	0.44	$	1.14	$	(0.26	)

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. 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, as well as drilling carry amounts received or billed and remaining as of June 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	$	82.8	$	167.2
Repsol E&P USA, Inc.	January 2012	272.5		78.2		671.8
		$	559.5	$	161.0	$	839.0

____________________

(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.

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

13

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

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 six-month period ended June 30, 2012, the Company recorded approximately $142.1 million of Atinum and Repsol's drilling carry, 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.

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 June 30, 2012 and December 31, 2011, $7.8 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 June 30, 2012 and December 31, 2011 consisted of the following (in thousands):

	June 30, 2012		December 31, 2011
Cash and cash equivalents	$	1,052	$	1,702
Accounts receivable, net	21		24
Inventory	109		109
Prepaid expenses	59		176
Total current assets	1,241		2,011
Other property, plant and equipment, net	14,411		14,985
Total assets	$	15,652	$	16,996
Accounts payable and accrued expenses	$	152	$	280
Total liabilities	$	152	$	280

14

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Grey Ranch Plant Genpar, LLC. The Company owns a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP. Additionally, the Company serves as Genpar’s administrative manager. Genpar’s ownership interest in GRLP is its only asset. As managing partner of GRLP, Genpar has the sole right to manage, control and conduct the business of GRLP. However, Genpar is restricted from making certain major decisions, including the decision to remove the Company as operator of the Plant. The rights afforded the Company under the Plant operating agreement and the restrictions on Genpar limit Genpar’s ability to make decisions on behalf of GRLP. Therefore, Genpar is considered a VIE. Although both the Company and Genpar’s other equity owner share equally in Genpar’s economic losses and benefits and also have agreements that may be considered variable interests, the Company determined it was the primary beneficiary of Genpar due to (i) its ability, as administrative manager and operator of the Plant, to direct the activities of Genpar that most significantly impact its economic performance and (ii) its obligation or right, as operator of the Plant, to absorb the losses of or receive benefits from Genpar that could potentially be significant to Genpar. As the primary beneficiary, the Company consolidates Genpar’s activity. However, its sole asset, the investment in GRLP, is eliminated in consolidation. Genpar has no liabilities.

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 common 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 in transactions exempt from registration under Rule 144 under the Securities Act subsequent to their initial public offerings during the three and six-month periods ended June 30, 2012. These transactions decreased the Company's beneficial interest in the Royalty Trusts. See further discussion of the unit sales below.

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

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 six-month periods ended June 30, 2012 as follows (in millions):

	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012
Total distributions	$	65.9	$	118.0
Distributions to third-party unitholders	$	44.1	$	76.8

15

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

There were no quarterly distributions declared and paid during the three or six-month periods ended June 30, 2011. See Note 18 for discussion of the Royalty Trusts' distribution declarations in July 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 June 30, 2012 or December 31, 2011.

The Company and one of its wholly owned subsidiaries entered into development agreements with the Royalty Trusts that obligate the Company to drill, or cause to be drilled, a specified number of wells within respective areas of mutual interest, which arealso subject to the royalty interests granted to the Mississippian Trust I, Permian Trust and Mississippian Trust II, by December 31, 2014, March 31, 2015 and December 31, 2016, respectively. In the event of delays, the Company will have until December 31, 2015 and March 31, 2016 to fulfill its drilling obligations to the Mississippian Trust I and Permian Trust, 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 June 30, 2012, the total maximum amount recoverable by the Royalty Trusts under the liens was approximately $508.3 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 June 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 9 for further discussion of the derivatives agreement between the Company and each Royalty Trust.

Oil Price SwapsUnderlying the Derivatives Agreements

	Notional (MBbl)	Weighted Avg. Fixed Price
July 2012 — December 2012	595	$	104.19
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
July 2012 — December 2012	402	$4.00 - 6.20
January 2013 — December 2013	858	$4.00 - 7.15
January 2014 — December 2014	937	$4.00 - 7.78
January 2015 — December 2015	1,010	$4.00 - 8.55

16

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

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

	Notional (MBbl)	Weighted Avg. Fixed Price
July 2012 — December 2012	674	$	104.39
January 2013 — December 2013	1,021	$	103.35
January 2014 — December 2014	799	$	100.59
January 2015 — March 2015	104	$	100.90

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. In consolidation, 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 June 30, 2012 and December 31, 2011, $1,578.8 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 June 30, 2012 and December 31, 2011 consisted of the following (in thousands):    

	June 30, 2012			December 31, 2011
Cash and cash equivalents(1)	$	3,844		$	3,151
Accounts receivable	26,199			18,357
Derivative contracts	19,538			1,499
Total current assets	49,581			23,007
Investment in royalty interests(2)	1,325,942			858,795
Less: accumulated depletion	(55,799		)	(24,404		)
	1,270,143			834,391
Derivative contracts	18,312			5,668
Total assets	$	1,338,036		$	863,066
Accounts payable and accrued expenses	$	2,364		$	486
Total liabilities	$	2,364		$	486

 ____________________

(1) Includes $3.0 million held by the trustee 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.

The Company sold Mississippian Trust I and Permian Trust common units in transactions exempt from registration pursuant to Rule 144 under the Securities Act during the three and six-month periods ended June 30, 2012 for total proceeds of $24.7 million and $123.5 million, respectively. The unit sales were accounted for as equity transactions with no gain or loss

17

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(Unaudited)

recognized. The Company continues to be the primary beneficiary of the Mississippian Trust I and the Permian Trust, as discussed above, and continues to consolidate the activities of the Royalty Trusts. The Company's beneficial interests in the Royalty Trusts at June 30, 2012 and December 31, 2011 were as follows:

	Beneficial Interest Owned by Company
	June 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 June 30, 2012 and December 31, 2011, respectively, included in the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):

	June 30, 2012		December 31, 2011
Accounts receivable due from PGC	$	2,621	$	3,205
Accounts payable due to PGC	$	5,861	$	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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(Unaudited)

Level 1 Fair Value Measurements

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

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

Level 2 Fair Value Measurements

Derivative contracts. The fair values of the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, interest rates and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model using the applicable inputs, discussed above. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates.

Level 3 Fair Value Measurements

Derivative contracts. The fair values of the Company’s diesel fixed price swaps and oil and natural gas basis swaps are based upon quotes obtained from counterparties to the derivative contracts. These values are reviewed internally for reasonableness through the use of a discounted cash flow model using non-exchange traded regional pricing information. Additionally, the Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit risk, as applicable, in determining the fair value of these derivative contracts. The significant unobservable input used in the fair value measurement of the Company’s diesel fixed price swaps is the estimate of diesel prices. Significant (increases) decreases in diesel prices could result in a significantly (lower) higher fair value measurement. The significant unobservable inputs used in the fair value measurement of the Company’s oil and natural gas basis swaps is the estimate of future oil and natural gas basis differentials. Significant increases (decreases) in oil and natural gas 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 three fair value measurements at June 30, 2012 are included in the table below.

Derivative Type	Unobservable Input	Range				Weighted Average		Fair Value
								(in thousands)
Diesel fixed price swaps	Diesel price forward curve inputs	$2.74	–	$2.83	per gallon	$2.78	per gallon	$	(113	)
Oil basis swaps	Oil basis differential forward curve inputs	$8.70	–	$12.57	per barrel	$10.64	per barrel	$	5,126

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(Unaudited)

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):

June 30, 2012

	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,941	$	—	$	—	$	—		$	27,941
Commodity derivative contracts	—		328,844		5,126		(31,531		)	302,439
Other assets	7,996		—		—		—			7,996
	$	35,937	$	328,844	$	5,126	$	(31,531	)	$	338,376
Liabilities
Commodity derivative contracts	$	—	$	51,364	$	113	$	(31,531	)	$	19,946
Interest rate swap	—		6,849		—		—			6,849
	$	—	$	58,213	$	113	$	(31,531	)	$	26,795

December 31, 2011

	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Restricted deposits	$	27,912	$	—	$	—	$	—		$	27,912
Commodity derivative contracts	—		62,746		397		(32,662		)	30,481
Other assets	7,138		—		—		—			7,138
	$	35,050	$	62,746	$	397	$	(32,662	)	$	65,531
Liabilities
Commodity derivative contracts	$	—	$	182,694	$	4,650	$	(32,662	)	$	154,682
Interest rate 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 six-month periods ended June 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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(Unaudited)

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 six-month periods ended June 30, 2012 and 2011 (in thousands):

	Three Months Ended June 30,
	2012			2011
	Commodity Derivative Contracts			Commodity Derivative Contracts			Interest Rate Swaps			Total
Balance of Level 3, March 31	$	(2,675	)	$	(478,541	)	$	(14,929	)	$	(493,470	)
Total gain or losses (realized/unrealized)	(1,643		)	169,988			(2,798		)	167,190
Purchases	5,697			—			—			—
Settlements	3,634			14,920			2,442			17,362
Balance of Level 3, June 30	$	5,013		$	(293,633	)	$	(15,285	)	$	(308,918	)

	Six Months Ended June 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)	389			(107,640		)	(3,076		)	(110,716		)
Purchases	5,697			—			—			—
Settlements	3,180			19,867			4,485			24,352
Balance of Level 3, June 30	$	5,013		$	(293,633	)	$	(15,285	)	$	(308,918	)

Unrealized gains on the Company's Level 3 commodity derivative contracts of $2.1 million and $3.7 million for the three and six-month periods ended June 30, 2012, respectively, have been included in (gain) loss on derivative contracts in the accompanying unaudited condensed consolidated statements of operations.

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

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

	June 30, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	346,833	$	350,000	$	339,381	$	350,000
9.875% Senior Notes due 2016(1)	400,223		355,591		396,568		354,579
8.0% Senior Notes due 2018	765,000		750,000		765,000		750,000
8.75% Senior Notes due 2020(2)	470,250		443,841		475,875		443,568
7.5% Senior Notes due 2021	893,250		900,000		909,000		900,000
8.125% Senior Notes due 2022	761,250		750,000		—		—

 ____________________

(1)Carrying value is net of $9,909 and $10,921 discount at June 30, 2012 and December 31, 2011, respectively.

(2)Carrying value is net of $6,159 and $6,432 discount at June 30, 2012 and December 31, 2011, respectively.

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(Unaudited)

The carrying values of the Company’s senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 8 for discussion of the Company’s long-term debt.

5. Property, Plant and Equipment

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

	June 30, 2012			December 31, 2011
Oil and natural gas properties
Proved	$	11,197,054		$	8,969,296
Unproved	948,369			689,393
Total oil and natural gas properties	12,145,423			9,658,689
Less accumulated depreciation, depletion and impairment	(5,011,661		)	(4,791,534		)
Net oil and natural gas properties capitalized costs	7,133,762			4,867,155
Land	15,723			14,196
Non-oil and natural gas equipment(1)	713,769			668,391
Buildings and structures	167,009			133,147
Total	896,501			815,734
Less accumulated depreciation and amortization	(301,251		)	(293,465		)
Other property, plant and equipment, net	595,250			522,269
Total property, plant and equipment, net	$	7,729,012		$	5,389,424

 ____________________

(1) Includes cumulative capitalized interest of approximately $8.7 million and $6.7 million at June 30, 2012 and December 31, 2011, respectively.

There were no full cost ceiling impairments during the three or six-month periods ended June 30, 2012 or 2011. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both June 30, 2012 and December 31, 2011 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the table above.

6. Other Assets

Other assets consist of the following (in thousands):

	June 30, 2012		December 31, 2011
Debt issuance costs, net of amortization	$	73,639	$	51,724
Notes receivable on asset retirement obligations	11,001		—
Investments	7,996		7,138
Production tax credit receivable	7,665		7,665
Lease broker advances	1,448		13,086
Development advance	—		16,777
Other	5,415		2,232
Total other assets	$	107,164	$	98,622

7. Construction Contracts

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

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(Unaudited)

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 expects to complete the Century Plant in two phases. Upon completion of each phase of the Century Plant, Occidental will take ownership of the related assets and will operate the Century Plant for the purpose of separating and removing CO2 from delivered natural gas. Phase I is in the commissioning process with completion and transfer of title to Occidental expected in the third quarter of 2012, and Phase II is under construction and expected to be completed by the end of 2012. The Company has recorded additions of $140.0 million (including $10.0 million during the six-month period ended June 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. Billings and estimated contract loss in excess of costs incurred of $6.3 million and $43.3 million at June 30, 2012 and December 31, 2011, respectively, are reported as current liabilities in the accompanying unaudited condensed consolidated balance sheets.

Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO2 from the Company’s delivered natural gas production volumes. Under this agreement, the Company will be required to deliver certain minimum CO2 volumes annually once Occidental takes title, and will have to compensate Occidental to the extent such requirements are not met. See Note 11 for additional discussion of this volume requirement. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.

Transmission Expansion Projects. The Company entered into a construction services agreement in November 2011 to manage the design, engineering and construction of a series of transmission expansion and upgrade projects in northern Oklahoma. Under the terms of the agreement, the Company will be reimbursed for costs incurred on these projects up to approximately $22.0 million. Construction on these projects began in 2012 and is expected to be completed by the end of the year. Costs in excess of billings on these projects of $14.8 million at June 30, 2012 is reported as a current asset 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.

8. Long-Term Debt

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

	June 30, 2012		December 31, 2011
Senior Floating Rate Notes due 2014	$	350,000	$	350,000
Senior credit facility	—		—
9.875% Senior Notes due 2016, net of $9,909 and $10,921 discount, respectively	355,591		354,579
8.0% Senior Notes due 2018	750,000		750,000
8.75% Senior Notes due 2020, net of $6,159 and $6,432 discount, respectively	443,841		443,568
7.5% Senior Notes due 2021	900,000		900,000
8.125% Senior Notes due 2022	750,000		—
Mortgage	—		16,029
Total debt	3,549,432		2,814,176
Less: current maturities of long-term debt	—		1,051
Long-term debt	$	3,549,432	$	2,813,125

For the three and six-month periods ended June 30, 2012, interest payments, excluding amounts capitalized, were approximately $63.4 million and $120.6 million, respectively. Interest payments for the six-month period ended June 30, 2012 included $10.9 million of fees incurred to secure financing for the Dynamic Acquisition. For the three and six-month periods ended June 30, 2011, interest payments, excluding amounts capitalized, were approximately $56.3 million and $109.5 million, respectively. Interest payments for the three and six-months ended June 30, 2011 included $1.5 million and $25.7 million, respectively, of accrued interest paid in connection with the partial redemption of the 8.625% Senior Notes due 2015, discussed further below.

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(Unaudited)

Senior Floating Rate Notes Due 2014. The Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) were issued in May 2008. The Senior Floating Rate Notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 17 for condensed financial information of the subsidiary guarantors.

The Senior Floating Rate Notes bear interest at the London Interbank Offered Rate ("LIBOR") plus 3.625%. Interest is payable quarterly with the principal due on April 1, 2014. The average interest rate paid on the outstanding Senior Floating Rate Notes for the three-month periods ended June 30, 2012 and 2011 was 4.09% and 3.93%, respectively, without consideration of the interest rate swap discussed below. The average interest rate paid on the outstanding Senior Floating Rate Notes for the six-month periods ended June 30, 2012 and 2011 was 4.15% and 3.93%, respectively, without consideration of the interest rate swap discussed below. The Company may redeem, at specified redemption prices, some or all of the Senior Floating Rate Notes at any time.

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

As of June 30, 2012, the Company had a $350.0 million notional interest rate swap agreement to effectively fix the variable interest rate on the Senior Floating Rate Notes to an annual rate of 6.69% through April 1, 2013. This swap has not been designated as a hedge.

Senior Credit Facility. The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. The senior credit facility matures on March 29, 2017, if the Company has repaid or refinanced the Senior Floating Rate Notes or the Company’s 9.875% Senior Notes due 2016 prior to September 30, 2015 with a source of funds other than the senior credit facility. If either series of notes is not repaid or refinanced prior to such date, the senior credit facility will mature on November 15, 2015.

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

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

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(Unaudited)

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 six-month periods ended June 30, 2012 as there were no amounts outstanding under the senior credit facility during the period. The average annual interest rate paid on amounts outstanding under the senior credit facility was 2.51% and 2.70%, respectively, for the three and six-month periods ended June 30, 2011.

Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. The Company’s borrowing base is redetermined in April and October of each year. The next borrowing base redetermination will be in October 2012. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base. During the six-month period ended June 30, 2012, additional costs of approximately $7.4 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 June 30, 2012, the Company had no amount outstanding under the senior credit facility and $29.5 million in outstanding letters of credit. Letters of credit, excluding a $1.5 million Dynamic letter of credit, reduce the availability under the senior credit facility on a dollar-for-dollar basis.

8.625% Senior Notes Due 2015. The Company’s 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”) were issued in May 2008. In March 2011, the Company purchased approximately 94.5%, or $614.2 million, of the aggregate principal amount of its 8.625% Senior Notes 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. 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 $2.0 million and $38.2 million, respectively, were recorded as a loss on extinguishment of debt in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011, respectively.

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

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

8.0% Senior Notes Due 2018. The Company’s unsecured 8.0% Senior Notes due 2018 (the “8.0% Senior Notes”) were issued in May 2008 and bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable.

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

8.75% Senior Notes Due 2020. The Company’s unsecured 8.75% Senior Notes due 2020 (the “8.75% Senior Notes”) were issued in December 2009 and bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due on January 15, 2020. The 8.75% Senior Notes were issued at a discount, which is being amortized to interest expense over the term of the notes. The 8.75% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption

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(Unaudited)

prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 17 for condensed financial information of the subsidiary guarantors.

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

7.5% Senior Notes Due 2021. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 (the “7.5% Senior Notes”) to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were used to fund the tender offer for the 8.625% Senior Notes, including any accrued and unpaid interest, the redemption of the 8.625% Senior Notes that remained outstanding following the conclusion of the tender offer, including accrued and unpaid interest (each as described above) and to repay borrowings under the Company’s senior credit facility. The 7.5% Senior Notes bear interest at a fixed rate of 7.5% per annum, payable semi-annually, with the principal due on March 15, 2021. Prior to March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. On or after March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, prior to their maturity at other various specified redemption prices. The notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries. See Note 17 for condensed financial information of the subsidiary guarantors.

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

Debt issuance costs of $19.4 million incurred in connection with the offering and subsequent exchange of the 7.5% Senior Notes are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the notes.

8.125% Senior Notes Due 2022. In April 2012, the Company issued $750.0 million of unsecured 8.125% Senior Notes to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were approximately $730.1 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. The 8.125% Senior Notes bear interest at a fixed rate of 8.125% per annum, payable semi-annually, with the principal due on October 15, 2022. Prior to 2017, the 8.125% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. The notes are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company's wholly owned subsidiaries.

In conjunction with the issuance of the 8.125% Senior Notes, the Company entered into a registration rights agreement requiring the Company to commence a registered exchange offer for these notes no later than April 17, 2013. Under certain circumstances, in lieu of a registered exchange offer, the Company may be required to file a shelf registration statement relating to the resale of the 8.125% Senior Notes and to use its commercially reasonable best efforts to keep such registration statement effective until two years after its effective date (or such shorter period that will terminate when all of the 8.125% Senior Notes covered thereby have been resold pursuant thereto or in certain other circumstances). The Company would be required to pay additional interest as liquidated damages of 0.25%, increasing 0.25% each 90 days to a maximum of 0.50% if it fails to fulfill its obligations under the agreement within the specified time periods.

The Company incurred $19.9 million of debt issuance costs in connection with the offering of the 8.125% Senior Notes. These costs are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the notes.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

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.

9. Derivatives

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

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its 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 June 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	Collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Basis swaps	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for 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 an interest rate swap agreement that effectively converts the variable interest rate on its Senior Floating Rate Notes to a fixed rate through April 1, 2013. See Note 8 for further discussion of the Company’s interest rate swap.

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

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

under such contracts. Substantially concurrent with the execution of the derivatives agreement, the Company novated certain of the derivatives contracts underlying the derivatives agreement to the Permian Trust. As a party to these contracts, the Permian Trust will receive payment directly from the counterparty and pay any amounts owed directly to the counterparty. To secure the Permian Trust’s obligations under these novated contracts, the Permian Trust has given the counterparty a lien on its royalty interests. Under the derivatives agreement, as development wells are drilled for the benefit of the Permian Trust, the Company will have the right, under certain circumstances, to assign or novate to the Permian Trust additional derivative contracts. In April 2012, the Company novated to the Permian Trust certain additional derivative contracts underlying the derivatives agreement with the Permian Trust.

Effective April 1, 2012, the Company entered into a derivatives agreement with the Mississippian Trust II. The agreement provides the Mississippian Trust II with the economic effect of certain oil derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil production through December 31, 2014. Under this arrangement, the Company will pay the Mississippian Trust II amounts it receives from its counterparties in accordance with the underlying contracts, and the Mississippian Trust II 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 derivatives agreement, the Company novated certain of the derivatives contracts underlying the derivatives agreement to the Mississippian Trust II. As a party to these contracts, the Mississippian Trust II will receive payment directly from the counterparty and pay any amounts owed directly to the counterparty. To secure the Mississippian Trust II’s obligations under these novated contracts, the Mississippian Trust II has given the counterparties a lien on its royalty interests. Under the derivatives agreement, as development wells are drilled for the benefit of the Mississippian Trust II, the Company will have the right, under certain circumstances, to assign or novate to the Mississippian Trust II additional derivative contracts.

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 June 30, 2012 and December 31, 2011 on a gross basis without regard to same-counterparty netting (in thousands):

Type of Contract	Balance Sheet Classification	June 30, 2012		December 31, 2011
Derivative assets
Oil price swaps	Derivative contracts-current	$	191,637	$	6,095
Natural gas price swaps