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

Notional (MMcf)

Weighted Average
Fixed Price

July 2013 - December 2013

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________

Form 10-Q

__________________________

(Mark One)



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

For the quarterly period ended June 30, 2013



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

For the transition period from to

Commission File Number: 001-33784

__________________________

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

__________________________



Delaware		20-8084793
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

123 Robert S. Kerr Avenue Oklahoma City, Oklahoma		73102
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:

(405) 429-5500

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

__________________________

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

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

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



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

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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on July 31, 2013, was 490,755,483.

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

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) of the Company includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning capital expenditures, the Company’s liquidity, capital resources, debt profile, pending acquisitions or dispositions, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the effects thereof on the Company’s financial condition and other statements concerning the Company’s operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Company’s business or results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. These forward-looking statements speak only as of the date hereof. The Company disclaims any obligation to update or revise these forward-looking statements unless required by law, and it cautions readers not to rely on them unduly. While the Company’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks and uncertainties discussed in “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (the “2012 Form 10-K”).

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SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended June 30, 2013

INDEX



PART I. FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Statement of Changes in Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements	9
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	69
ITEM 4.	Controls and Procedures	72

PART II. OTHER INFORMATION

ITEM 1.	Legal Proceedings	73
ITEM 1A.	Risk Factors	75
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	76
ITEM 6.	Exhibits	76

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PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)



	June 30, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	1,094,341		$	309,766
Accounts receivable, net	412,140			445,506
Derivative contracts	53,424			71,022
Costs in excess of billings and contract loss	5,057			11,229
Prepaid expenses	38,162			31,319
Restricted deposit	—			255,000
Other current assets	38,866			19,043
Total current assets	1,641,990			1,142,885
Oil and natural gas properties, using full cost method of accounting
Proved	10,355,137			12,262,921
Unproved	535,836			865,863
Less: accumulated depreciation, depletion and impairment	(5,515,168		)	(5,231,182		)
	5,375,805			7,897,602
Other property, plant and equipment, net	567,910			582,375
Derivative contracts	43,173			23,617
Other assets	124,758			144,252
Total assets	$	7,753,636		$	9,790,731

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS - Continued

(In thousands, except per share data)



	June 30, 2013			December 31, 2012
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	746,944		$	766,544
Accounts payable - related party (Note 15)	55,098			—
Billings and contract loss in excess of costs incurred	—			15,546
Derivative contracts	1,798			14,860
Asset retirement obligations	79,953			118,504
Deposit on pending sale	—			255,000
Total current liabilities	883,793			1,170,454
Long-term debt	3,194,660			4,301,083
Derivative contracts	11,717			59,787
Asset retirement obligations	365,397			379,906
Other long-term obligations	21,771			17,046
Total liabilities	4,477,338			5,928,276
Commitments and contingencies (Note 11)
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at June 30, 2013 and December 31, 2012; aggregate liquidation preference of $265,000	3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at June 30, 2013 and December 31, 2012; aggregate liquidation preference of $200,000	2			2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at June 30, 2013 and December 31, 2012; aggregate liquidation preference of $300,000	3			3
Common stock, $0.001 par value, 800,000 shares authorized; 490,929 issued and 489,616 outstanding at June 30, 2013 and 491,578 issued and 490,359 outstanding at December 31, 2012	483			476
Additional paid-in capital	5,280,402			5,233,019
Additional paid-in capital—stockholder receivable	(5,000		)	(5,000		)
Treasury stock, at cost	(9,096		)	(8,602		)
Accumulated deficit	(3,378,587		)	(2,851,048		)
Total SandRidge Energy, Inc. stockholders’ equity	1,888,210			2,368,853
Noncontrolling interest	1,388,088			1,493,602
Total equity	3,276,298			3,862,455
Total liabilities and equity	$	7,753,636		$	9,790,731

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(Unaudited)
Revenues
Oil and natural gas	$	454,282		$	429,758		$	932,299		$	771,123
Drilling and services	16,078			33,632			33,448			62,941
Midstream and marketing	15,198			8,852			28,230			17,158
Construction contract	23,253			—			23,253			—
Other	4,176			6,192			7,447			8,847
Total revenues	512,987			478,434			1,024,677			860,069
Expenses
Production	116,811			122,481			249,312			205,791
Production taxes	6,564			11,001			16,003			23,255
Cost of sales	15,348			19,241			31,665			36,802
Midstream and marketing	14,927			8,559			26,730			16,513
Construction contract	23,253			—			23,253			—
Depreciation and depletion—oil and natural gas	138,903			139,260			296,429			226,326
Depreciation and amortization—other	16,022			15,348			31,358			29,860
Accretion of asset retirement obligations	9,800			7,965			19,579			10,572
Impairment	15,643			—			15,643			—
General and administrative	173,261			61,716			252,705			112,017
Gain on derivative contracts	(103,654		)	(669,850		)	(62,757		)	(415,204		)
(Gain) loss on sale of assets	(349		)	300			397,825			3,380
Total expenses	426,529			(283,979		)	1,297,745			249,312
Income (loss) from operations	86,458			762,413			(273,068		)	610,757
Other income (expense)
Interest expense	(61,159		)	(68,569		)	(147,069		)	(135,534		)
Bargain purchase gain	—			122,696			—			122,696
Loss on extinguishment of debt	—			—			(82,005		)	—
Other (expense) income, net	(106		)	(81		)	505			2,387
Total other (expense) income	(61,265		)	54,046			(228,569		)	(10,451		)
Income (loss) before income taxes	25,193			816,459			(501,637		)	600,306
Income tax expense (benefit)	508			(100,617		)	4,937			(100,546		)
Net income (loss)	24,685			917,076			(506,574		)	700,852
Less: net income (loss) attributable to noncontrolling interest	45,121			99,004			(6,798		)	100,958
Net (loss) income attributable to SandRidge Energy, Inc.	(20,436		)	818,072			(499,776		)	599,894
Preferred stock dividends	13,881			13,881			27,763			27,763
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(34,317	)	$	804,191		$	(527,539	)	$	572,131
(Loss) earnings per share
Basic	$	(0.07	)	$	1.74		$	(1.10	)	$	1.33
Diluted	$	(0.07	)	$	1.46		$	(1.10	)	$	1.13
Weighted average number of common shares outstanding
Basic	479,154			461,008			478,494			430,802
Diluted	479,154			560,640			478,494			530,378

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In thousands)



	SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock			Common Stock				Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	Shares	Amount		Shares		Amount		Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	(Unaudited)
Six Months Ended June 30, 2013
Balance at December 31, 2012	7,650	$	8	490,359		$	476	$	5,228,019		$	(8,602	)	$	(2,851,048	)	$	1,493,602		$	3,862,455
Distributions to noncontrolling interest owners	—	—		—		—		—			—			—			(98,716		)	(98,716		)
Purchase of treasury stock	—	—		—		—		—			(27,196		)	—			—			(27,196		)
Retirement of treasury stock	—	—		—		—		(27,196		)	27,196			—			—			—
Stock purchase — retirement plans, net of distributions	—	—		(94	)	—		974			(494		)	—			—			480
Stock-based compensation	—	—		—		—		73,612			—			—			—			73,612
Issuance of restricted stock awards, net of cancellations	—	—		(649	)	7		(7		)	—			—			—			—
Net loss	—	—		—		—		—			—			(499,776		)	(6,798		)	(506,574		)
Convertible perpetual preferred stock dividends	—	—		—		—		—			—			(27,763		)	—			(27,763		)
Balance at June 30, 2013	7,650	$	8	489,616		$	483	$	5,275,402		$	(9,096	)	$	(3,378,587	)	$	1,388,088		$	3,276,298

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Six Months Ended June 30,
	2013			2012
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(506,574	)	$	700,852
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	327,787			256,186
Accretion of asset retirement obligations	19,579			10,572
Impairment	15,643			—
Debt issuance costs amortization	5,369			5,401
Amortization of discount, net of premium, on long-term debt	789			1,285
Bargain purchase gain	—			(122,696		)
Loss on extinguishment of debt	82,005			—
Deferred income tax provision (benefit)	4,015			(100,288		)
Unrealized gain on derivative contracts	(63,520		)	(455,138		)
Realized loss on amended derivative contracts	—			117,108
Realized gain on financing derivative contracts	(5,299		)	(21,125		)
Loss on sale of assets	397,825			3,380
Stock-based compensation	72,415			23,277
Other	2,044			504
Changes in operating assets and liabilities	32,605			(1,612		)
Net cash provided by operating activities	384,683			417,706
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(828,585		)	(1,123,040		)
Acquisition of assets	(8,602		)	(761,575		)
Proceeds from sale of assets	2,563,886			420,859
Net cash provided by (used in) investing activities	1,726,699			(1,463,756		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	—			750,000
Repayments of borrowings	(1,115,500		)	(16,029		)
Premium on debt redemption	(61,997		)	—
Debt issuance costs	(91		)	(27,316		)
Proceeds from issuance of royalty trust units	—			587,086
Proceeds from the sale of royalty trust units	—			123,549
Noncontrolling interest distributions	(98,716		)	(76,801		)
Stock-based compensation excess tax benefit	—			8
Purchase of treasury stock	(28,468		)	(7,980		)
Dividends paid — preferred	(27,763		)	(27,763		)
Cash received (paid) on settlement of financing derivative contracts	5,728			(45,312		)
Net cash (used in) provided by financing activities	(1,326,807		)	1,259,442
NET INCREASE IN CASH AND CASH EQUIVALENTS	784,575			213,392
CASH AND CASH EQUIVALENTS, beginning of year	309,766			207,681
CASH AND CASH EQUIVALENTS, end of period	$	1,094,341		$	421,073
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(156,800	)	$	(120,563	)
Cash paid for income taxes	(2,525		)	(1,324		)
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	$	(255,000	)	$	—
Change in accrued capital expenditures	$	(52,715	)	$	8,672
Adjustment to oil and natural gas properties for estimated contract loss	$	—		$	10,000
Asset retirement costs capitalized	$	2,421		$	3,232
Common stock issued in connection with acquisition	$	—		$	542,138

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

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SANDRIDGE ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

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

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

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2012 have been derived from the audited financial statements contained in the Company’s 2012 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2012 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2012 Form 10-K.

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

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

Measurement Period Adjustments. Certain prior period financial information in the accompanying unaudited condensed consolidated statements of operations and unaudited condensed consolidated statements of cash flows has been revised as a result of retrospectively adjusting provisional amounts recognized for the acquisition of Dynamic Offshore Resources, LLC (“Dynamic”) during the measurement period. See Note 2 for further discussion of these adjustments.

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

The more significant areas requiring the use of assumptions, judgments and estimates include: oil and natural gas reserves; cash flow estimates used in impairment tests of long-lived assets; depreciation, depletion and amortization; asset retirement obligations; assignments of fair value and allocations of purchase price in connection with business combinations; determinations of significant alterations to the full cost pool and related estimates of fair value for allocations of divested oil and natural gas properties that result in substantial economic differences between the properties divested and the properties remaining; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company enters into derivative arrangements in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 9 for the Company’s open oil and natural gas commodity derivative contracts.

Production targets contained in certain gathering and treating agreements require the Company to incur capital expenditures or make associated shortfall payments. Additionally, the Company has a drilling obligation to each of SandRidge Permian Trust (the “Permian Trust”) and SandRidge Mississippian Trust II (the “Mississippian Trust II”). See Note 3 for discussion of these drilling obligations. The Company depends on cash flows from operating activities, funding commitments from third parties for drilling carries and, as necessary, borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Additionally, the Company may use proceeds from the issuance of equity and debt securities in the capital markets and from the sale or other monetization of assets to fund its capital expenditures. Based on current cash balances, cash flows from operating activities and funding commitments from third parties for drilling carries, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2013. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility. See Note 8 for discussion of the financial covenants in the senior credit facility.

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

2. Acquisitions and Divestitures

2012 Acquisitions and Divestitures

Dynamic Acquisition. The Company acquired 100% of the equity interests of Dynamic in April 2012 for total consideration of approximately $1.2 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of SandRidge common stock (the “Dynamic Acquisition”). Upon completion of the initial purchase price allocation as of April 17, 2012, the Company reviewed and verified its assessment, including the identification and valuation of assets acquired and liabilities assumed. The Company recorded a net deferred tax liability associated with the Dynamic Acquisition, which resulted in the release of a portion of the previously recorded valuation allowance on the Company’s net deferred tax asset.

During the fourth quarter of 2012, the Company updated certain of the estimates used in the preliminary purchase price allocation, primarily with respect to deferred taxes and other accruals for which the Company was awaiting additional information. Changes to the purchase price allocation and the corresponding $1.8 million adjustment to the bargain purchase gain and $3.0 million adjustment to the valuation allowance, which resulted in income tax expense, were recorded retrospectively to the period of the acquisition and are included in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012. In the second quarter of 2013, the Company completed its valuation of assets acquired and liabilities assumed related to the Dynamic Acquisition with no further adjustments made to the purchase price allocation.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

The following table summarizes the assets acquired and liabilities assumed in connection with the Dynamic Acquisition (in thousands, except stock price):



Consideration(1)
Shares of SandRidge common stock issued	73,962
SandRidge common stock price	$	7.33
Fair value of common stock issued	542,138
Cash consideration(2)	680,000
Cash balance adjustment(3)	13,091
Total purchase price	$	1,235,229

Fair Value of Liabilities Assumed
Current liabilities	$	129,363
Asset retirement obligations(4)	315,922
Long-term deferred tax liability(5)	100,288
Other non-current liabilities	4,469
Amount attributable to liabilities assumed	550,042
Total purchase price plus liabilities assumed	1,785,271

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

____________________

(1)

Consideration paid by the Company consisted of 74 million shares of SandRidge common stock and cash of approximately $680.0 million. The value of the stock consideration is based upon the closing price of $7.33 per share of SandRidge common stock on April 17, 2012, which was the closing date of the Dynamic Acquisition. Under the acquisition method of accounting, the purchase price is determined based on the total cash paid and the fair value of SandRidge common stock issued on the acquisition date.


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


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


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


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

(6)

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

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(7)

The bargain purchase gain results from the excess of the fair value of net assets acquired over consideration paid. To validate the bargain purchase gain on this acquisition, the Company reviewed its initial identification and valuation of assets acquired and liabilities assumed. The Company believes it was able to acquire Dynamic for less than the estimated fair value of its net assets due to their offshore location resulting in less bidding competition.

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

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



	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012
	(in thousands, except per share data)
Revenues	$	508,198	$	1,038,003
Net income(1)	$	712,006	$	493,281
Income available to SandRidge Energy, Inc. common stockholders(1)	$	599,121	$	364,560
Earnings per common share(1)
Basic	$	1.26	$	0.77
Diluted	$	1.07	$	0.68

_________________

(1)

Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and earnings per common share exclude $9.9 million and $12.4 million of acquisition costs for the three and six-month periods ended June 30, 2012, respectively, and a $122.7 million bargain purchase gain and a $100.3 million partial valuation allowance release for both the three and six-month periods ended June 30, 2012, included in the accompanying unaudited condensed consolidated statements of operations. Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and earnings per common share exclude $10.9 million of fees to secure financing included in the accompanying unaudited condensed consolidated statement of operations for the six-month period ended June 30, 2012.

Transaction costs related to the Dynamic Acquisition of $9.9 million and $12.4 million are included in general and administrative expense in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2012, respectively. Fees incurred to secure financing for the acquisition of $10.9 million are included in interest expense in the accompanying unaudited condensed consolidated statement of operations for the six-month period ended June 30, 2012.

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

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

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

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

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




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

The following unaudited pro forma combined results of operations for the three and six-month periods ended June 30, 2012 are presented as though the Company acquired the Gulf of Mexico Properties as of January 1, 2011, which was the beginning of the earliest period presented at the time of the acquisition. The pro forma combined results of operations for the three and six-month periods ended June 30, 2012 have been prepared by adjusting the historical results of the Company to include the historical results of the acquired properties and estimates of the effect of the transaction on the combined results. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved had the transaction been in effect for the periods presented or that may be achieved by the Company in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.



	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012
	(in thousands, except per share data)
Revenues	$	492,233	$	888,485
Net income	$	918,219	$	703,199
Income available to SandRidge Energy, Inc. common stockholders	$	805,334	$	574,478
Earnings per common share
Basic	$	1.75	$	1.33
Diluted	$	1.46	$	1.14

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2013 Divestiture

Sale of Permian Properties. On February 26, 2013, the Company sold all of its oil and natural gas properties in the Permian Basin in west Texas, excluding the assets attributable to the Permian Trust’s area of mutual interest (the “Permian Properties”), for $2.6 billion, subject to certain post-closing adjustments expected to be finalized in the third quarter of 2013. This transaction resulted in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded a loss of $399.1 million on the sale, which is included in (gain) loss on sale of assets in the accompanying unaudited condensed consolidated statement of operations for the six-month period ended June 30, 2013. A portion of the loss totaling $71.7 million was allocated to noncontrolling interests and is reflected in net income (loss) attributable to noncontrolling interest in the accompanying unaudited condensed consolidated statement of operations for the six-month period ended June 30, 2013. The loss was calculated based on a comparison of proceeds received and the asset retirement obligation attributable to the Permian Properties that was assumed by the buyer to the sum of (i) an allocation of the historical net book value of the Company’s proved oil and natural gas properties attributable to the Permian Properties, (ii) the historical cost of unproved acreage sold and (iii) costs incurred by the Company to sell the properties. The allocated net book value attributable to the Permian Properties was calculated based on the relative fair value of the Permian Properties and the remaining proved oil and natural gas properties retained by the Company as of the date of sale.

The following table presents revenues and direct operating expenses of the Permian Properties included in the accompanying unaudited condensed consolidated statements of operations for the three-month period ended June 30, 2012 and six-month periods ended June 30, 2013 and 2012 (in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2012		2013(1)		2012
Revenues	$	133,630	$	68,027	$	295,395
Direct operating expenses	$	29,291	$	17,453	$	65,281

__________________

(1) Includes revenues and direct operating expenses through February 26, 2013, the date of sale.

Sale of Working Interests and Associated Drilling Carry Commitments

During 2011 and 2012, the Company completed two transactions whereby it sold non-operated working interests in the Mississippian formation. In these transactions, the Company received aggregate cash proceeds of $500.0 million for the sale of working interests and received drilling carry commitments to fund a portion of its future drilling and completion costs within areas of mutual interest totaling $1.0 billion. For accounting purposes, initial cash proceeds from these transactions were reflected as a reduction of oil and natural gas properties with no gain or loss recognized. These transactions and the associated drilling carries as of June 30, 2013 were as follows:



Partner	Closing Date	Total Drilling Carry		Drilling Carry Recorded		Drilling Carry Remaining
		(in millions)
Atinum MidCon I, LLC	September 2011	$	250.0	$	240.4	$	9.6
Repsol E&P USA, Inc.	January 2012	750.0		394.4		355.6
		$	1,000.0	$	634.8	$	365.2

During the six-month periods ended June 30, 2013 and 2012, the Company recorded approximately $248.3 million and $142.1 million, respectively, for Atinum MidCon I, LLC’s and Repsol E&P USA, Inc.’s drilling carries, which reduced the Company’s capital expenditures for the respective period.

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3. Variable Interest Entities

The Company consolidates the activities of VIEs of which it is the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE and the significance of the variable interest, 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 loss of GRLP is allocated to the partners based on ownership percentage and any operating or cash shortfalls require contributions from the partners. The Company has determined that GRLP qualifies as a VIE because certain equity holders lack the ability to participate in decisions impacting GRLP. Agreements related to the ownership and operation of GRLP provide for GRLP to pay management fees to the Company to operate the Plant and lease payments for the Plant. Under the operating agreements, lease payments are reduced if throughput volumes are below those expected. The Company determined that it is the primary beneficiary of GRLP as it has both (i) the power to direct the activities of GRLP that most significantly impact its economic performance as operator of the Plant and (ii) the obligation to absorb losses, as a result of the operating and gathering agreements, that could potentially be significant to GRLP and, therefore, consolidates the activity of GRLP in its consolidated financial statements. The 50% ownership interest not held by the Company is presented as noncontrolling interest in the consolidated financial statements.

GRLP’s assets can only be used to settle its own obligations and not other obligations of the Company. GRLP’s creditors have no recourse to the general credit of the Company. Although GRLP is included in the Company’s consolidated financial statements, the Company’s legal interest in GRLP’s assets is limited to its 50% ownership. At June 30, 2013 and December 31, 2012, $0.7 million and $1.1 million, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at June 30, 2013 and December 31, 2012 consisted of the following (in thousands):



	June 30, 2013		December 31, 2012
Cash and cash equivalents	$	226	$	1,080
Accounts receivable, net	18		20
Prepaid expenses	33		64
Other current assets	109		109
Total current assets	386		1,273
Other property, plant and equipment, net	1,205		1,246
Total assets	$	1,591	$	2,519

Accounts payable and accrued expenses	$	137	$	274
Total liabilities	$	137	$	274

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



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

____________________


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


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

The Royalty Trusts make quarterly cash distributions to unitholders based on calculated distributable income. In order to provide support for cash distributions on the common units, the Company agreed to subordinate a portion of the units it owns in each Royalty Trust (the “subordinated units”), which constitute 25% of the total outstanding units of each Royalty Trust. The subordinated units are entitled to receive pro rata distributions from the Royalty Trusts each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company. In exchange for agreeing to subordinate a portion of its Royalty Trust units, SandRidge is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Royalty Trust units exceeds the applicable quarterly incentive threshold. The Royalty Trusts declared and paid quarterly distributions during the three and six-month periods ended June 30, 2013 and 2012 as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Total distributions	$	68,449	$	65,948	$	144,810	$	118,017
Distributions to third-party unitholders	$	47,459	$	44,062	$	98,716	$	76,801

See Note 19 for discussion of the Royalty Trusts’ distributions announced in July 2013.

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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, 2013 or December 31, 2012.

The Company and one of its wholly owned subsidiaries entered into a development agreement with each Royalty Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells within respective areas of mutual interest, which are also subject to the royalty interests granted to the Mississippian Trust I, the Permian Trust and the Mississippian Trust II, by December 31, 2015, March 31, 2016 and December 31, 2016, respectively. At the end of the fourth full calendar quarter following satisfaction of the Company’s drilling obligation (the “subordination period”), the subordinated units of each Royalty Trust will automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions will terminate. One of the Company’s wholly owned subsidiaries also granted to each Royalty Trust a lien on the Company’s interests in the properties where the development wells will be drilled in order to secure the estimated amount of drilling costs for the Royalty Trust’s interests in the wells. As the Company fulfills its drilling obligation to each Royalty Trust, development wells that have been drilled and perforated for completion are released from the lien and the total amount that may be recovered by each Royalty Trust is proportionately reduced. In the second quarter of 2013, the Company fulfilled its drilling obligation to the Mississippian Trust I. As of June 30, 2013, the total maximum amount recoverable by the Permian Trust and the Mississippian Trust II under the liens was approximately $228.8 million.

Additionally, the Company and each Royalty Trust entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Royalty Trust, including hedge management services to the Permian Trust and the Mississippian Trust II. The Company also entered into derivatives agreements with each Royalty Trust, pursuant to which the Company provides to the Royalty Trust the economic effects of certain of the Company’s derivative contracts. Substantially concurrent with the execution of the derivatives agreements with the Permian Trust and the Mississippian Trust II, the Company novated certain of the derivative contracts underlying the respective derivatives agreements to the Permian Trust and the Mississippian Trust II. The Company novated certain additional derivative contracts underlying the derivatives agreements to the Permian Trust in April 2012 and to the Permian Trust and the Mississippian Trust II in March 2013. The tables below present the open oil and natural gas commodity derivative contracts at June 30, 2013 underlying the derivatives agreements. The combined volume in the tables below reflects the total volume of the Royalty Trusts’ open oil and natural gas commodity derivative contracts.

Oil Price Swaps Underlying the Derivatives Agreements



	Notional (MBbls)	Weighted Average Fixed Price
July 2013 - December 2013	803	$	103.04
January 2014 - December 2014	1,862	$	100.70
January 2015 - December 2015	630	$	101.03

Natural Gas Collars Underlying the Derivatives Agreements



	Notional (MMcf)	Collar Range
July 2013 - December 2013	432	$	4.00	—	$	7.15
January 2014 - December 2014	937	$	4.00	—	$	7.78
January 2015 - December 2015	1,010	$	4.00	—	$	8.55

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



	Notional (MBbls)	Weighted Average Fixed Price
July 2013 - December 2013	627	$	103.27
January 2014 - December 2014	991	$	100.79
January 2015 - March 2015	141	$	100.90

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

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

As noted above, the Company fulfilled its drilling obligation to the Mississippian Trust I in the second quarter of 2013. Accordingly, the Mississippian Trust I's subordinated units, all of which are held by SandRidge, will convert to common units on June 30, 2014. After this conversion, the Company will no longer have the obligation to absorb losses or right to receive residual returns through its variable interests that could be significant to the Mississippian Trust I. As a result, beginning June 30, 2014, the Company will no longer fully consolidate the activities of the Mississippian Trust I, but will proportionately consolidate its share of Mississippian Trust I assets, liabilities, income and expenses.

Each Royalty Trust’s assets can be used to settle only that Royalty Trust’s obligations and not other obligations of the Company or another Royalty Trust. The Royalty Trusts’ creditors have no contractual recourse to the general credit of the Company. Although the Royalty Trusts are included in the Company’s consolidated financial statements, the Company’s legal interest in the Royalty Trusts’ assets is limited to its ownership of the Royalty Trusts’ units. At June 30, 2013 and December 31, 2012, $1.4 billion and $1.5 billion, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets were attributable to the Royalty Trusts. The Royalty Trusts’ assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at June 30, 2013 and December 31, 2012 consisted of the following (in thousands):



	June 30, 2013			December 31, 2012
Cash and cash equivalents(1)	$	7,293		$	7,445
Accounts receivable	28,620			28,596
Derivative contracts	9,864			10,286
Total current assets	45,777			46,327
Investment in royalty interests(2)	1,325,942			1,325,942
Less: accumulated depletion	(148,009		)	(103,746		)
	1,177,933			1,222,196
Derivative contracts	7,594			7,660
Total assets	$	1,231,304		$	1,276,183
Accounts payable and accrued expenses	$	3,081		$	1,101
Total liabilities	$	3,081		$	1,101

____________________


(1)	Includes $3.0 million held by the trustee at June 30, 2013 and December 31, 2012 as reserves for future general and administrative expenses.


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

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The Company sold Mississippian Trust I and Permian Trust common units it owned in transactions exempt from registration pursuant to Rule 144 under the Securities Act during the six-month period ended June 30, 2012 for total proceeds of $123.5 million. The Company also sold Mississippian Trust I common units in the fourth quarter of 2012 for total proceeds of $15.8 million, which further reduced its beneficial interest. The unit sales were accounted for as equity transactions with no gain or loss recognized. The Company continues to be the primary beneficiary of the Royalty Trusts, after consideration of these transactions, as discussed above, and accordingly, continues to consolidate the activities of the Royalty Trusts during the subordination period. The Company’s beneficial interests in the Royalty Trusts at June 30, 2013 and December 31, 2012 were as follows:



	June 30, 2013		December 31, 2012
Mississippian Trust I	26.9	%	26.9	%
Permian Trust	30.5	%	30.5	%
Mississippian Trust II	39.9	%	39.9	%

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

Amounts due from and due to PGC as of June 30, 2013 and December 31, 2012 included in the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):



	June 30, 2013		December 31, 2012
Accounts receivable due from PGC	$	1,744	$	1,976
Accounts payable due to PGC	$	4,661	$	5,053

4. Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:



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

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

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in each level of the hierarchy, as described below.

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Level 1 Fair Value Measurements

Restricted deposits. The fair value of restricted deposits invested in mutual funds or municipal bonds is based on quoted market prices. For restricted deposits held in savings accounts, carrying value approximates fair value. Restricted deposits are included in other assets in the accompanying unaudited condensed consolidated balance sheets.

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

Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

Derivative contracts. The fair value of the Company’s oil basis swaps outstanding at December 31, 2012 was based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness through the use of a discounted cash flow model using non-exchange traded regional pricing information. Additionally, the Company applied a weighted average credit default risk rating factor for its counterparties or gave effect to its credit risk, as applicable, in determining the fair value of these derivative contracts. The significant unobservable input used in the fair value measurement of the Company’s oil basis swaps was the estimate of future oil basis differentials. Significant increases (decreases) in oil basis differentials could result in a significantly higher (lower) fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of the Company’s oil basis swaps at December 31, 2012 are included in the table below. All of the outstanding oil basis swaps at December 31, 2012 contractually matured during the six month-period ended June 30, 2013.



Unobservable Input	Range			Weighted Average	Fair Value
	(price per Bbl)			(price per Bbl)	(in thousands)
Oil basis differential forward curve	$10.00	–	$21.98	$14.74	$	(512	)

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

June 30, 2013



	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3		Netting(1)			Assets/Liabilities at Fair Value
Assets
Restricted deposits	$	27,953	$	—	$	—	$	—		$	27,953
Commodity derivative contracts	—		137,484		—		(40,887		)	96,597
Investments	11,385		—		—		—			11,385
	$	39,338	$	137,484	$	—	$	(40,887	)	$	135,935
Liabilities
Commodity derivative contracts	$	—	$	54,402	$	—	$	(40,887	)	$	13,515
	$	—	$	54,402	$	—	$	(40,887	)	$	13,515

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December 31, 2012



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

____________________

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

The table below sets forth a reconciliation of the Company’s commodity derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six-month periods ended June 30, 2013 and 2012 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012

Beginning balance of Level 3	$	(211	)	$	(2,675	)	$	(512	)	$	(4,253	)
Total realized and unrealized gains (losses)	740			(1,643		)	(133		)	389
Purchases	—			5,697			—			5,697
Settlements (received) paid	(529		)	3,634			645			3,180
Ending balance of Level 3	$	—		$	5,013		$	—		$	5,013

The Company’s policy is to recognize transfers between fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred. During the three and six-month periods ended June 30, 2013 and 2012, the Company did not have any transfers between levels.

Unrealized (gains) losses on the Company’s Level 3 commodity derivative contracts outstanding at June 30, 2012 were $(1.4) million and $0.2 million for the three and six-month periods ended June 30, 2012, respectively. These amounts have been included in gain on derivative contracts in the accompanying unaudited condensed consolidated statements of operations. There were no outstanding Level 3 commodity derivative contracts at June 30, 2013.

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

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Fair Value of Financial Instruments

The Company measures the fair value of its senior notes using pricing for the Company’s senior notes that is readily available in the public market. The Company classifies these inputs as Level 2 in the fair value hierarchy. The estimated fair values and carrying values of the Company’s senior notes at June 30, 2013 and December 31, 2012 were as follows (in thousands):



	June 30, 2013				December 31, 2012
	Fair Value		Carrying Value		Fair Value		Carrying Value
9.875% Senior Notes due 2016(1)	$	—	$	—	$	392,913	$	356,657
8.0% Senior Notes due 2018	—		—		790,313		750,000
8.75% Senior Notes due 2020(2)	457,875		444,425		490,500		444,127
7.5% Senior Notes due 2021(3)	1,116,250		1,179,128		1,257,250		1,179,328
8.125% Senior Notes due 2022	742,500		750,000		823,125		750,000
7.5% Senior Notes due 2023(4)	781,688		821,107		882,750		820,971

____________________

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

(2)Carrying value is net of $5,575 and $5,873 discount at June 30, 2013 and December 31, 2012, respectively.


(3)	Carrying value includes a premium, applicable to notes issued in August 2012, of $4,128 and $4,328 at June 30, 2013 and December 31, 2012, respectively.

(4)Carrying value is net of $3,893 and $4,029 discount at June 30, 2013 and December 31, 2012, respectively.

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

5. Property, Plant and Equipment

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



	June 30, 2013			December 31, 2012
Oil and natural gas properties
Proved(1)	$	10,355,137		$	12,262,921
Unproved	535,836			865,863
Total oil and natural gas properties	10,890,973			13,128,784
Less accumulated depreciation, depletion and impairment	(5,515,168		)	(5,231,182		)
Net oil and natural gas properties capitalized costs	5,375,805			7,897,602
Land	17,929			17,927
Non-oil and natural gas equipment(2)	607,665			643,370
Buildings and structures	221,453			205,349
Total	847,047			866,646
Less accumulated depreciation and amortization	(279,137		)	(284,271		)
Other property, plant and equipment, net	567,910			582,375
Total property, plant and equipment, net	$	5,943,715		$	8,479,977

____________________


(1)	Includes cumulative capitalized interest of approximately $17.7 million and $11.7 million at June 30, 2013 and December 31, 2012, respectively.


(2)	Includes cumulative capitalized interest of approximately $13.8 million and $11.4 million at June 30, 2013 and December 31, 2012, respectively.

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Assets held for sale. During the second quarter of 2013, the Company committed to a plan to sell various drilling and corporate assets. These assets are included in other current assets in the accompanying unaudited condensed consolidated balance sheet at June 30, 2013 as the Company intends to sell the assets within a year. The net book value of the drilling assets was adjusted to fair value, resulting in an impairment of $10.6 million and remaining net book value of $4.1 million, based upon the fair value for these assets estimated with a discounted cash flow model utilizing market assumptions of projections of future cash flows to be generated by the assets and risk-adjusted discount rates. Based on the unobservable nature of certain of these assumptions, the valuation is considered Level 3 under the fair value hierarchy, as described in Note 4. The net book value of the corporate asset to be sold was adjusted to fair value, resulting in an impairment of $2.9 million and remaining net book value of $17.0 million. The fair value of the corporate asset was based on current market value using observations of comparable assets for sale in the market.

Other Impairments. In the second quarter of 2013, the Company evaluated certain midstream pipe inventory and natural gas compressors for impairment after determining that their future use was limited. As a result of this evaluation, the Company recorded a $2.1 million impairment on these assets to reduce their carrying value to market value.

6. Other Assets

Other assets consist of the following (in thousands):



	June 30, 2013		December 31, 2012
Debt issuance costs, net of amortization	$	66,644	$	83,643
Restricted deposits	27,953		27,947
Notes receivable on asset retirement obligations	11,655		11,433
Investments	11,385		10,348
Production tax credit receivable	5,033		6,313
Other	2,088		4,568
Total other assets	$	124,758	$	144,252

7. Construction Contracts

Century Plant. As of December 31, 2012, the Company had substantially completed construction of a carbon dioxide (“CO₂”) treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). The Company constructed the Century Plant for a contract price of $796.3 million, which included agreed upon change orders and scope revisions, that Occidental paid to the Company through periodic cost reimbursements based upon the percentage of the project completed. Upon substantial completion of construction in late 2012, Occidental took ownership and began operating the Century Plant for the purpose of separating and removing CO₂ from the delivered natural gas stream. The Company recorded additions totaling $180.0 million to its oil and natural gas properties for costs incurred in excess of contract amounts during the construction period. Costs in excess of billings and contract loss of $2.8 million at June 30, 2013, representing costs incurred in the final stages of construction, are reported as a current asset in the accompanying unaudited condensed consolidated balance sheets. Billings and contract loss in excess of costs incurred of $15.5 million at December 31, 2012 are reported as a current liability in the accompanying unaudited condensed consolidated balance sheets.

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

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Transmission Expansion Projects. As of June 30, 2013, the Company had substantially completed the construction of a series of electrical transmission expansion and upgrade projects in northern Oklahoma. The Company constructed these projects for a contract price of $23.3 million, which included agreed upon change orders. With substantial completion of the contract in the second quarter of 2013, the Company recognized construction contract revenue and costs equal to the revised contract price of $23.3 million, which are included in the accompanying unaudited condensed consolidated statements of operations. Costs in excess of billings on these projects of approximately $2.3 million, representing costs incurred in the final stages of construction, and $11.2 million at June 30, 2013 and December 31, 2012, respectively, are included in current assets in the accompanying unaudited condensed consolidated balance sheets.

8. Long-Term Debt

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



	June 30, 2013		December 31, 2012
Senior credit facility	$	—	$	—
Senior notes
9.875% Senior Notes due 2016, net of $8,843 discount at December 31, 2012	—		356,657
8.0% Senior Notes due 2018	—		750,000
8.75% Senior Notes due 2020, net of $5,575 and $5,873 discount, respectively	444,425		444,127
7.5% Senior Notes due 2021, including a premium of $4,128 and $4,328, respectively	1,179,128		1,179,328
8.125% Senior Notes due 2022	750,000		750,000
7.5% Senior Notes due 2023, net of $3,893 and $4,029 discount, respectively	821,107		820,971
Total debt	3,194,660		4,301,083
Less: current maturities of long-term debt	—		—
Long-term debt	$	3,194,660	$	4,301,083

Senior Credit Facility

The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. As of June 30, 2013, the senior credit facility contained financial covenants, including maintaining agreed upon levels for the (i) ratio of total net debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total net debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded. The senior credit facility matures in March 2017.

The senior credit facility also contains various covenants that limit the ability of the Company and certain of its subsidiaries to: grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions. As of and during the three and six-month periods ended June 30, 2013, the Company was in compliance with all applicable financial covenants under the senior credit facility.

The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of certain of the Company’s material present and future subsidiaries, certain intercompany debt of the Company, and substantially all of the Company’s assets, including proved oil and natural gas reserves representing at least 80.0% of the discounted present value (as defined in the senior credit facility) of proved oil and natural gas reserves considered by the lenders in determining the borrowing base for the senior credit facility.

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At the Company’s election, interest under the senior credit facility is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 0.75% and 1.75% per annum. Interest is payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. Quarterly, the Company pays a commitment fee assessed at an annual rate of 0.5% on any available portion of the senior credit facility.

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

At June 30, 2013, the Company had no amount outstanding under the senior credit facility and $28.6 million in outstanding letters of credit, which reduce the availability under the senior credit facility on a dollar-for-dollar basis.

Senior Fixed Rate Notes

The Company’s unsecured senior fixed rate notes (“Senior Fixed Rate Notes”) bear interest at a fixed rate per annum, payable semi-annually, with the principal due upon maturity. Certain of the Senior Fixed Rate Notes were issued at a discount or a premium. The discount or premium is amortized to interest expense over the term of the respective series of Senior Fixed Rate Notes. The Senior Fixed Rate Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries. See Note 18 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $70.2 million incurred in connection with the offerings of the Senior Fixed Rate Notes, including the Senior Fixed Rate Notes issued in 2012 and excluding the Senior Fixed Rate Notes redeemed in March 2013, both as discussed below, and any subsequent registered exchange offers are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the respective series of Senior Fixed Rate Notes.

2013 Activity. In March 2013, the Company redeemed the outstanding $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and the outstanding $750.0 million aggregate principal amount of its 8.0% Senior Notes due 2018 for total consideration of $1,061.34 per $1,000 principal amount and $1,052.77 per $1,000 principal amount, respectively. The premium paid to redeem these notes and the associated unamortized debt issuance costs, totaling $82.0 million, were recorded as a loss on extinguishment of debt in the accompanying unaudited condensed consolidated statement of operations for the six-month period ended June 30, 2013.

2012 Activity. In 2012, the Company completed offerings of the 8.125% Senior Notes due 2022, additional 7.5% Senior Notes due 2021 and 7.5% Senior Notes due 2023 (collectively, the “2012 Senior Notes”) to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. The Company incurred $41.0 million of debt issuance costs in connection with the 2012 Senior Notes offerings and subsequent registered exchange offers.

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

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

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

Indentures. Each of the indentures governing the Company’s Senior Fixed Rate Notes contains covenants that 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, 2013, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Fixed Rate Notes.

Senior Floating Rate Notes Due 2014

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

9. Derivatives

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

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. None of the Company’s derivative contracts may be terminated prior to the contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. At June 30, 2013, the Company’s commodity derivative contracts consisted of fixed price swaps and collars, which are described below:



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

Collars	Two-way collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be New York Mercantile Exchange (“NYMEX”) plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract.

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

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

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

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

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Fair Value of Derivatives. The following table presents the fair value of the Company’s derivative contracts as of June 30, 2013 and December 31, 2012 on a gross basis without regard to same-counterparty netting (in thousands):



Type of Contract	Balance Sheet Classification	June 30, 2013			December 31, 2012
Derivative assets
Oil price swaps	Derivative contracts-current	$	46,648		$	88,052
Natural gas price swaps	Derivative contracts-current	13,230			—
Oil basis swaps	Derivative contracts-current	—			183
Oil collars - three way	Derivative contracts-current	8,203			—
Natural gas collars	Derivative contracts-current	1,166			3,111
Oil price swaps	Derivative contracts-noncurrent	41,167			37,983
Oil collars - three way	Derivative contracts-noncurrent	26,483			190
Natural gas collars	Derivative contracts-noncurrent	587			884
Derivative liabilities
Oil price swaps	Derivative contracts-current	(17,576		)	(31,991		)
Oil basis swaps	Derivative contracts-current	—			(695		)
Oil collars - two way	Derivative contracts-current	(45		)	(103		)
Interest rate swap	Derivative contracts-current	—			(2,395		)
Oil price swaps	Derivative contracts-noncurrent	(36,781		)	(67,900		)
Oil collars - three way	Derivative contracts-noncurrent	—			(7,327		)
Total net derivative contracts		$	83,082		$	19,992

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

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

June 30, 2013



	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	69,247	$	(15,823	)	$	53,424	$	—		$	53,424
Derivative contracts - noncurrent	68,237		(25,064		)	43,173		—			43,173
Total	$	137,484	$	(40,887	)	$	96,597	$	—		$	96,597

Liabilities
Derivative contracts - current	$	17,621	$	(15,823	)	$	1,798	$	(1,798	)	$	—
Derivative contracts - noncurrent	36,781		(25,064		)	11,717		(11,717		)	—
Total	$	54,402	$	(40,887	)	$	13,515	$	(13,515	)	$	—

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December 31, 2012



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

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

The following table summarizes the cash settlements and valuation gain and loss on the Company’s commodity derivative contracts and interest rate swap, which are included in gain on derivative contracts and interest expense, respectively, in the accompanying unaudited condensed consolidated statements of operations for the three and six-month periods ended June 30, 2013 and 2012 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Commodity Derivatives
Realized (gain) loss(1)	$	(17,717	)	$	(89,120	)	$	(1,632	)	$	36,336
Unrealized gain	(85,937		)	(580,730		)	(61,125		)	(451,540		)
Gain on commodity derivative contracts	$	(103,654	)	$	(669,850	)	$	(62,757	)	$	(415,204	)
Interest Rate Swap
Realized loss	$	—		$	2,294		$	2,409		$	4,494
Unrealized gain	—			(2,245		)	(2,395		)	(3,599		)
Loss on interest rate swap	$	—		$	49		$	14		$	895

____________________

(1)

The three-month periods ended June 30, 2013 and 2012 included $0.7 million and $57.3 million, respectively, of realized gains related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled (“early settlements”). The six-month periods ended June 30, 2013 and 2012 included $29.0 million and $(57.3) million, respectively, of realized losses (gains) related to early settlements. The six-month period ended June 30, 2012 also included $117.1 million of non-cash realized losses on derivative contracts amended in January 2012.

At June 30, 2013, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps



	Notional (MBbls)	Weighted Average Fixed Price
July 2013 - December 2013	6,211	$	99.19
January 2014 - December 2014	7,511	$	92.42
January 2015 - December 2015	5,076	$	83.69

Natural Gas Price Swaps

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Oil Collars - Two-way

Oil Collars - Three-way



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

Natural Gas Collars



	Notional (MMcf)	Collar Range
July 2013 - December 2013	3,432	$3.78	—	$6.71
January 2014 - December 2014	937	$4.00	—	$7.78
January 2015 - December 2015	1,010	$4.00	—	$8.55

10. Asset Retirement Obligations

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2012 to June 30, 2013 is as follows (in thousands):



Asset retirement obligations at December 31, 2012	$	498,410
Liability incurred upon acquiring and drilling wells	2,421
Liability settled or disposed in current period	(75,060		)
Accretion	19,579
Asset retirement obligations at June 30, 2013	445,350
Less: current portion	79,953
Asset retirement obligations, net of current	$	365,397

Liability settled or disposed during the six-month period ended June 30, 2013 includes $22.7 million for the settlement of a plugging and abandonment obligation associated with the Company’s Bullwinkle platform in the Gulf of Mexico and $15.2 million disposed in conjunction with the sale of the Permian Properties in February 2013.

11. Commitments and Contingencies

Legal Proceedings

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SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands and seeking approximately $13.0 million in actual damages, inclusive of penalties and interest. On February 5, 2013, the Company received a favorable summary judgment ruling that effectively removes a majority of the plaintiffs' and GLO's claims. On April 29, 2013, the court entered an order allowing for an interlocutory appeal of its summary judgment ruling. The Company intends to continue to defend the remaining issues in this lawsuit as well as any appellate proceedings. At the time of the ruling on summary judgment, the lawsuit was still in the discovery stage and, accordingly, an estimate of reasonably possible losses associated with the remaining causes of action, if any, cannot be made until all of the facts, circumstances and legal theories relating to such claims and the Company's defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. filed a lawsuit against the Company, SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain current and former directors and senior executive officers of the Company (collectively, the “defendants”) in the U.S. District Court for the District of Connecticut. On October 28, 2011, the plaintiffs filed an amended complaint alleging substantially the same allegations as those contained in the original complaint. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and to the plaintiffs prior to the entry into a participation agreement among Patriot Exploration, LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by the plaintiffs in certain of SandRidge E&P's oil and natural gas properties. To date, the plaintiffs have invested approximately $16.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. On November 28, 2011, the defendants filed a motion to dismiss the amended complaint, which was recently granted in part and denied in part. The Company intends to defend this lawsuit vigorously and believes the plaintiffs' claims are without merit. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the Company's defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

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


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


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


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


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


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


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


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

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

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On April 10, 2013, the U.S. District Court for the Western District of Oklahoma consolidated the Levine, Depuy, Elliot, Brothers, and Ezell actions (the “Federal Shareholder Derivative Litigation”) under the caption “In re SandRidge Energy, Inc. Shareholder Derivative Litigation,” appointed a lead plaintiff and lead counsel, and ordered the lead plaintiff to file a consolidated amended complaint by May 1, 2013. On June 3, 2013, the Company and the individual defendants filed a motion to dismiss the consolidated amended complaint, which motion is now pending before the court.

The Company and the individual defendants in the Hefner and Romano actions (the “State Shareholder Derivative Litigation”) moved to stay each of those actions in favor of the Federal Shareholder Derivative Litigation, in order to avoid duplicative proceedings, and also requested, in the alternative, the dismissal of the State Shareholder Derivative Litigation. On May 8, 2013, the court stayed the Romano action pending further order of the court. And, on June 19, 2013, the court stayed the Hefner action until at least November 29, 2013. On July 1, 2013, the plaintiff filed a motion to lift the stay in the Hefner action, which motion is still pending before the court.

Because the lawsuits comprising the State Shareholder Derivative Litigation and the Federal Shareholder Derivative Litigation have only been recently filed, an estimate of reasonably possible losses associated with each of them, if any, cannot be made until the facts, circumstances and legal theories relating to the claims asserted and available defenses are fully disclosed and analyzed. The Company has not established any reserves relating to these actions.

On December 5, 2012, James Glitz and Rodger A. Thornberry, on behalf of themselves and all other similarly situated stockholders, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and certain current and former executive officers of the Company. On January 4, 2013, Louis Carbone, on behalf of himself and all other similarly situated stockholders, filed a substantially similar putative class action complaint in the same court and against the same defendants. On March 6, 2013, the court consolidated these two actions under the caption “In re SandRidge Energy, Inc. Securities Litigation” (the “Securities Litigation”) and appointed a lead plaintiff and lead counsel. By order dated April 10, 2013, the court granted the lead plaintiff until July 23, 2013 to file a consolidated amended complaint in the action. The consolidated amended complaint asserts a variety of federal securities claims against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class of (a) purchasers of SandRidge common stock during the period from February 24, 2011 to November 8, 2012, (b) purchasers of common units of SandRidge Mississippian Trust I in or traceable to its initial public offering on or about April 12, 2011, and (c) purchasers of common units of SandRidge Mississippian Trust II in or traceable to its initial public offering on or about April 23, 2012. The claims are based on allegations that the Company and certain of its current and former officers and directors, among other defendants, are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and natural gas reserves, the Company's capital expenditures, and certain transactions entered into by companies allegedly affiliated with the Company's former CEO Tom Ward. Because the Securities Litigation has only been recently filed, an estimate of reasonably possible losses associated with it, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and available defenses are fully disclosed and analyzed. The Company has not established any reserves relating to the Securities Litigation.

On January 7, 2013, Gerald Kallick, on behalf of himself and all other similarly situated stockholders, filed a putative class action complaint in the Court of Chancery of the State of Delaware against SandRidge Energy, Inc., and certain current and former directors of the Company. On January 31, 2013, the plaintiff filed an amended class action complaint. In his amended complaint, the plaintiff seeks: (i) declaratory relief that certain change-in-control provisions in the Company's indentures and senior credit facility agreement are invalid and unenforceable, (ii) declaratory relief that the directors breached their fiduciary duties by failing to approve the slate of directors proposed by TPG-Axon in its consent solicitation in order to disable the change-in-control provisions described above, (iii) a mandatory injunction requiring the directors to approve nominees for the Board of Directors (the “Board”) submitted by TPG-Axon, (iv) a mandatory injunction prohibiting the Company from paying the then current Chairman and Chief Executive Officer (“CEO”) his change-in-control benefits under his employment agreement if the CEO were removed as a director, but remained employed as the Company’s CEO, (v) a mandatory injunction enjoining the defendants from impeding or interfering with the dissident stockholder's consent solicitation, (vi) a mandatory injunction requiring the defendants to disclose all material information related to the change-in-control provisions in the Company's indentures and senior credit facility agreement; and (vii) an order requiring the Company's current directors to account to the plaintiff and the putative class for alleged damages. On March 8, 2013, the court granted plaintiff's motion for a preliminary injunction, enjoining the Board, unless and until it approved the TPG-Axon nominees for purposes of the change-in-control provisions of the Company's outstanding debt agreements, from (i) soliciting any further consent revocations in opposition to TPG-Axon's consent solicitation, (ii) relying upon or otherwise giving effect to any consent revocations received by the Company as of March 11, 2013, and (iii) impeding the dissident stockholder's consent solicitation in any way. On March 9, 2013, the Board approved TPG-Axon's nominees

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for purposes of the change-in-control provisions in the Company's debt instruments. On March 13, 2013, TPG-Axon and the Board entered into a settlement agreement under which TPG-Axon's consent solicitation was withdrawn. As a result of these actions, the Company believes that many of the original claims asserted by the plaintiff in the Kallick action have been rendered moot. The plaintiff has asked for the court’s permission to add additional claims, which request is currently pending. Until such time as claims are known, the Company is unable to estimate if any reasonably possible losses exist.

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

Treating Agreement Commitment

In conjunction with the Century Plant construction agreement, the Company entered into a 30-year treating agreement with Occidental for the removal of CO₂ from the Company’s delivered production volumes of natural gas. Under the agreement, the Company must deliver a total of approximately 3,200 Bcf of CO₂ during the agreement period; it is expected that after 2013 approximately 3,000 Bcf of CO₂will remain to be delivered. The Company pays Occidental $0.25 per Mcf to the extent minimum annual CO₂ volume requirements are not met, and, at the end of 2042, the Company is required to pay Occidental $0.70 per Mcf for total undelivered CO₂volumes, net of any CO₂delivered in excess of any given year’s applicable minimum volumes. Based on current projected natural gas production levels, the Company expects to accrue between approximately $29.5 million and $36.0 million at December 31, 2013 for amounts related to the Company’s anticipated shortfall in meeting its 2013 annual CO₂delivery obligation. Due to the sensitivity of drilling activity to market prices for natural gas, the Company is unable to estimate additional amounts it may be required to pay under the agreement in subsequent periods; however, if natural gas prices remain low, drilling activity will likely also remain low, which would result in additional shortfall payments in future periods.

12. Equity

Preferred Stock

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



	June 30, 2013	December 31, 2012
Shares authorized	50,000	50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock	2,650	2,650
6.0% Convertible perpetual preferred stock	2,000	2,000
7.0% Convertible perpetual preferred stock	3,000	3,000

The Company is authorized to issue 50.0 million shares of preferred stock, $0.001 par value, of which approximately 7.7 million shares were designated as convertible perpetual preferred stock at June 30, 2013 and December 31, 2012. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions but are now freely tradable, to the extent not owned by affiliates.

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Each outstanding share of convertible perpetual preferred stock is convertible at the holder’s option at any time into shares of the Company’s common stock at the specified conversion rate, subject to customary adjustments in certain circumstances. Each holder is entitled to an annual dividend payable semi-annually in cash, common stock or a combination thereof, at the Company’s election. The convertible perpetual preferred stock is not redeemable by the Company at any time. After the specified conversion date, the Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met. The following table summarizes information about each series of the Company’s convertible perpetual preferred stock:



	Convertible Perpetual Preferred Stock
	8.5%		6.0%		7.0%
Liquidation preference per share	$	100.00	$	100.00	$	100.00
Annual dividend per share	$	8.50	$	6.00	$	7.00
Conversion rate per share to common stock	12.4805		9.2115		12.8791
Conversion date to common stock at Company’s option	February 20, 2014		December 21, 2014		November 20, 2015

Preferred stock dividends. All dividend payments to date on the Company’s 8.5%, 6.0% and 7.0% convertible perpetual preferred stock have been paid in cash. Paid and unpaid dividends included in the calculation of (loss applicable) income available to the Company’s common stockholders and the Company’s basic (loss) earnings per share calculation for the three and six-month periods ended June 30, 2013 and 2012 as presented in the accompanying unaudited condensed consolidated statements of operations, are included in the tables below (in thousands):



	Three Months Ended June 30,
	2013						2012
	Dividends Paid		Dividends Unpaid		Total		Dividends Paid		Dividends Unpaid		Total
8.5% Convertible perpetual preferred stock	$	—	$	5,631	$	5,631	$	—	$	5,631	$	5,631
6.0% Convertible perpetual preferred stock	—		3,000		3,000		—		3,000		3,000
7.0% Convertible perpetual preferred stock	2,625		2,625		5,250		2,625		2,625		5,250
Total	$	2,625	$	11,256	$	13,881	$	2,625	$	11,256	$	13,881

	Six Months Ended June 30,
	2013						2012
	Dividends Paid		Dividends Unpaid		Total		Dividends Paid		Dividends Unpaid		Total
8.5% Convertible perpetual preferred stock	$	2,816	$	8,447	$	11,263	$	2,816	$	8,447	$	11,263
6.0% Convertible perpetual preferred stock	500		5,500		6,000		500		5,500		6,000
7.0% Convertible perpetual preferred stock	7,875		2,625		10,500		7,875		2,625		10,500
Total	$	11,191	$	16,572	$	27,763	$	11,191	$	16,572	$	27,763

Common Stock

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



	June 30, 2013	December 31, 2012
Shares authorized	800,000	800,000
Shares outstanding	489,616	490,359
Shares held in treasury	1,313	1,219

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Stockholder Rights Plan

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

Treasury Stock

The Company makes required statutory tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately 5.1 million shares having a total value of $27.2 million and approximately 0.8 million shares having a total value of $6.7 million during the six-month periods ended June 30, 2013 and 2012, respectively. These shares were accounted for as treasury stock when withheld and then immediately retired.

Shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan are accounted for as treasury shares. These shares are not included as outstanding shares of common stock in this report. For corporate purposes, including for the purpose of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Stockholder Receivable

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

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

Equity Compensation

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

Equity compensation provided to employees directly involved in oil and natural gas exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is reflected in general and administrative expenses, production expenses, midstream and marketing expenses and cost of sales expenses in the consolidated statements of operations. For the three and six-month periods ended June 30, 2013, the Company recognized equity compensation expense of $51.7 million and $70.7 million, net of $1.3 million and $2.9 million capitalized, respectively, related to restricted common stock. The three and six-month periods ended June 30, 2013 include approximately $40.9 million and $48.5 million, respectively, of equity compensation expense recognized in connection with the separation from the Company of certain of its former executives. For the three and six-month periods ended June 30, 2012, the Company recognized equity compensation expense of $11.1 million and $21.6 million, net of $2.1 million and $4.0 million capitalized, respectively, related to restricted common stock.

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Noncontrolling Interest

Noncontrolling interest represents third-party ownership interests in the Company’s subsidiaries and consolidated VIEs (see Note 3), and is included as a component of equity in the accompanying unaudited condensed consolidated balance sheets and unaudited condensed consolidated statement of changes in equity.

13. Income Taxes

The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The provision (benefit) for income taxes consisted of the following components for the three and six-month periods ended June 30, 2013 and 2012 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013		2012
Current
Federal	$	(344	)	$	12		$	4,015	$	(71	)
State	852			(341		)	922		(187		)
	508			(329		)	4,937		(258		)
Deferred
Federal	—			(97,345		)	—		(97,345		)
State	—			(2,943		)	—		(2,943		)
	—			(100,288		)	—		(100,288		)
Total provision (benefit)	508			(100,617		)	4,937		(100,546		)
Less: income tax provision attributable to noncontrolling interest	71			67			146		157
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	437		$	(100,684	)	$	4,791	$	(100,703	)

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are reduced by a valuation allowance when a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. As of December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. The Company continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. As a result of significant weight being placed on the Company's cumulative negative earnings position, the Company continued to have a full valuation allowance against its net deferred tax asset at June 30, 2013.

The income tax expense attributable to SandRidge of $4.8 million for the six-month period ended June 30, 2013 is primarily related to federal alternative minimum tax (“AMT”) associated with the tax year ending December 31, 2013. The Company recorded a current liability and a corresponding deferred tax asset each in the amount of $4.0 million for the six-month period ended June 30, 2013. As a result of recording a deferred tax asset, the Company increased its valuation allowance against its net deferred tax asset by $4.0 million.

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Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected certain of the Company’s tax attributes, including $298.4 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. The Company experienced a subsequent ownership change within the meaning of IRC Section 382 on July 16, 2010 as a result of the acquisition of Arena Resources, Inc. (“Arena”). The subsequent ownership change resulted in a more restrictive limitation on certain of the Company’s tax attributes than with the December 31, 2008 ownership change. The more restrictive limitation applies not only to the $298.4 million of federal net operating loss carryforwards and certain other tax attributes existing at December 31, 2008, but also to net operating losses of approximately $627.8 million and certain other tax attributes generated in periods following the December 31, 2008 ownership change. The subsequent limitation could result in a material amount of existing loss carryforwards expiring unused. Arena also experienced an ownership change on July 16, 2010 as a result of its acquisition by the Company. This ownership change resulted in a limitation on Arena’s net operating loss carryforwards of $119.9 million available to the Company. None of the limitations discussed above resulted in a current federal tax liability at June 30, 2013 or December 31, 2012.

At June 30, 2013, the Company had a liability of approximately $1.9 million for unrecognized tax benefits, compared to a liability of approximately $1.3 million at December 31, 2012. If recognized, approximately $1.2 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate.

The Company’s policy is to record interest and penalties on income taxes as a component of the income tax provision. The Company had an accrued liability of $0.2 million for interest and penalties relating to uncertain tax positions at June 30, 2013 and December 31, 2012.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2009 to present remain open for federal examination. Additionally, various tax years remain open beginning with tax year 2003 due to federal net operating loss carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years. Currently, several examinations are in progress. The Company does not anticipate that any federal or state audits will have a significant impact on the Company’s results of operations or financial position. As a result of ongoing negotiations pertaining to the Company’s current state audits, it is reasonably possible that the Company’s gross unrecognized tax benefits balance may decrease within the next twelve months by approximately $1.6 million.

14. Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock, using the treasury stock method, and outstanding convertible preferred stock. Under the treasury stock method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants are assumed to be used to repurchase shares at the average market price. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the three and six-month periods ended June 30, 2013 and 2012 (in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Weighted average basic common shares outstanding	479,154	461,008	478,494	430,802
Effect of dilutive securities
Restricted stock	—	9,499	—	9,443
Convertible preferred stock	—	90,133	—	90,133
Weighted average diluted common and potential common shares outstanding	479,154	560,640	478,494	530,378

For the three and six-month periods ended June 30, 2013, restricted stock awards covering 194 and 3,585 shares, respectively, were excluded from the computation of loss per share because their effect would have been antidilutive.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding convertible perpetual preferred stock for the three and six-month periods ended June 30, 2013 and 2012. Under the if-converted method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available (loss applicable) to common stockholders. For the three and six-month periods ended June 30, 2013, the Company determined the if-converted method was antidilutive and included the 8.5%, 6.0% and 7.0% preferred stock dividends in the determination of loss applicable to common stockholders. For the three and six-month periods ended June 30, 2012, the Company determined the if-converted method was more dilutive and did not include the 8.5%, 6.0% and 7.0% preferred stock dividends in the determination of income available to common stockholders.

15. Related Party Transactions

The Company enters into transactions in the ordinary course of business with certain related parties. These transactions primarily consist of sales of oil and natural gas. There were no sales to related parties during the three-month period ended June 30, 2013 and $1.6 million of sales to related parties during the six-month period ended June 30, 2013. During the three and six-month periods ended June 30, 2012, sales to related parties were $3.2 million and $7.0 million, respectively.

Former Chairman and CEO Severance. On June 28, 2013, Tom L. Ward separated employment from the Company. Amounts to be paid under the terms of his employment agreement include approximately $58.2 million for salary and bonus, of which $4.6 million will be paid in 36 monthly installments beginning in January 2014, and approximately $36.8 million associated with the accelerated vesting of 6.3 million shares of restricted stock awards. Salary and bonus amounts due within one year, totaling $55.1 million, are reflected in accounts payable - related party with the remaining $3.1 million included in other long-term obligations in the accompanying unaudited condensed consolidated balance sheet at June 30, 2013.

Oklahoma City Thunder Agreement. The Company’s former Chairman and CEO and one of its directors own minority interests in a limited liability company that owns and operates the Oklahoma City Thunder basketball team. The Company was party to a sponsorship agreement, whereby it paid approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder, which terminated with the conclusion of the 2012-2013 season.

Office Lease. In July 2012, the Company entered into a commercial lease to rent space in a building owned by an entity that is partially owned by one of the Company’s directors. The terms provide for an initial lease term of three years with annual rent of approximately $0.5 million, and any renovation costs paid by the Company with respect to the leased space will be applied toward future rent payments. Renovation costs in excess of the total rent will be reimbursed to the Company at the end of the lease agreement. As of June 30, 2013, the Company has made renovations costing approximately $3.3 million. The terms of the lease were reviewed and approved by the disinterested members of the Board and the Company believes that the rent expense to be paid under the lease is at a fair market rate.

16. Employee Compensation Plans

Annual Incentive Plan

In June 2013, the Compensation Committee of the Company’s Board approved an annual incentive plan effective June 2013 for all employees and discontinued the Company’s then existing cash bonus program with the final payments under the program made in July 2013. The Company had accrued approximately $10.9 million as of June 30, 2013 for such payments. For certain members of management, the annual incentive plan incorporates objective performance criteria, individual performance goals and competitive target award levels for the 2013 performance year with payout percentages ranging from 0% to 200% of specified target levels based on actual performance. As of June 30, 2013, the Company had accrued approximately $11.0 million for the 2013 annual incentive for all employees, including an accrual for an annual incentive for specified members of management at 100% of the target values. As the payout for management is dependent on actual performance compared to established performance targets, the actual amount paid for 2013 performance under the annual incentive plan could differ significantly from the established target values.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Performance Units

In June 2013, the Compensation Committee of the Company’s Board approved the issuance of performance units to certain members of senior management under the Company’s existing long term incentive plan. In July 2013, the Company granted approximately 31,100 performance units that will be settled in cash at payout percentages ranging from 50% to 200% of specified target values based on the Company's relative total shareholder return compared to a predetermined peer group with graded vesting over a performance period from July 2013 to December 2015. If minimum target thresholds are not met, the payout is reduced to zero.

Because the performance units contain a market-based performance component and will be settled in cash upon vesting, the Company recognized a liability equal to the estimated fair value of the units at the time the units were granted in July 2013 and will re-measure the liability at the end of each reporting period. Changes in the fair value of the units during the vesting period will be recognized as compensation expense for the portion for which the requisite services have been rendered, net of estimated forfeitures.

17. Business Segment Information

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

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	Exploration and Production			Drilling and Oil Field Services			Midstream Services			All Other			Consolidated Total
Three Months Ended June 30, 2013
Revenues	$	458,374		$	47,100		$	64,291		$	778		$	570,543
Inter-segment revenue	(81		)	(31,011		)	(26,464		)	—			(57,556		)
Total revenues	$	458,293		$	16,089		$	37,827		$	778		$	512,987

Income (loss) from operations(1)	$	241,666		$	(19,443	)	$	(7,956	)	$	(127,809	)	$	86,458
Interest income (expense)	317			—			(84		)	(61,392		)	(61,159		)
Other (expense) income, net	(330		)	—			135			89			(106		)
Income (loss) before income taxes	$	241,653		$	(19,443	)	$	(7,905	)	$	(189,112	)	$	25,193
Capital expenditures(2)	$	358,582		$	883		$	15,111		$	12,582		$	387,158
Depreciation, depletion, amortization, accretion and impairment	$	148,884		$	19,478		$	4,017		$	7,989		$	180,368
Three Months Ended June 30, 2012
Revenues	$	434,834		$	104,076		$	24,798		$	1,543		$	565,251
Inter-segment revenue	(77		)	(70,444		)	(16,296		)	—			(86,817		)
Total revenues	$	434,757		$	33,632		$	8,502		$	1,543		$	478,434

Income (loss) from operations(1)	$	786,335		$	4,678		$	(3,631	)	$	(24,969	)	$	762,413
Interest income (expense)	416			—			(137		)	(68,848		)	(68,569		)
Bargain purchase gain	122,696			—			—			—			122,696
Other income (expense), net	242			—			—			(323		)	(81		)
Income (loss) before income taxes	$	909,689		$	4,678		$	(3,768	)	$	(94,140	)	$	816,459
Capital expenditures(2)	$	518,343		$	5,836		$	17,754		$	20,121		$	562,054
Depreciation, depletion, amortization and accretion	$	147,479		$	8,624		$	1,717		$	4,753		$	162,573

Six Months Ended June 30, 2013
Revenues	$	939,784		$	96,837		$	101,125		$	1,631		$	1,139,377
Inter-segment revenue	(162		)	(63,378		)	(51,160		)	—			(114,700		)
Total revenues	$	939,622		$	33,459		$	49,965		$	1,631		$	1,024,677

Loss from operations(3)	$	(60,042	)	$	(28,408	)	$	(10,415	)	$	(174,203	)	$	(273,068	)
Interest income (expense)	635			—			(209		)	(147,495		)	(147,069		)
Loss on extinguishment of debt	—			—			—			(82,005		)	(82,005		)
Other income (expense), net	298			—			(664		)	871			505
Loss before income taxes	$	(59,109	)	$	(28,408	)	$	(11,288	)	$	(402,832	)	$	(501,637	)
Capital expenditures(2)	$	716,173		$	1,515		$	30,332		$	27,850		$	775,870
Depreciation, depletion, amortization, accretion and impairment	$	316,397		$	28,292		$	5,705		$	12,615		$	363,009
At June 30, 2013
Total assets	$	5,923,355		$	172,329		$	171,461		$	1,486,491		$	7,753,636

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	Exploration and Production			Drilling and Oil Field Services			Midstream Services			All Other			Consolidated Total
Six Months Ended June 30, 2012
Revenues	$	777,955		$	202,408		$	50,960		$	2,959		$	1,034,282
Inter-segment revenue	(155		)	(139,467		)	(34,591		)	—			(174,213		)
Total revenues	$	777,800		$	62,941		$	16,369		$	2,959		$	860,069

Income (loss) from operations(3)	$	662,499		$	8,157		$	(6,358	)	$	(53,541	)	$	610,757
Interest income (expense)	559			—			(293		)	(135,800		)	(135,534		)
Bargain purchase gain	122,696			—			—			—			122,696
Other income, net	2,010			—			—			377			2,387
Income (loss) before income taxes	$	787,764		$	8,157		$	(6,651	)	$	(188,964	)	$	600,306
Capital expenditures(2)	$	1,010,248		$	13,752		$	41,729		$	65,983		$	1,131,712
Depreciation, depletion, amortization and accretion	$	237,531		$	17,174		$	3,128		$	8,925		$	266,758
At December 31, 2012
Total assets	$	8,681,056		$	199,523		$	151,492		$	758,660		$	9,790,731

____________________


(1)	Exploration and production segment income from operations includes unrealized gains of $85.9 million and $580.7 million on commodity derivative contracts for the three-month periods ended June 30, 2013 and 2012, respectively.


(2)	On an accrual basis.


(3)	Exploration and production segment (loss) income from operations includes unrealized gains of $61.1 million and $451.5 million on commodity derivative contracts for the six-month periods ended June 30, 2013 and 2012, respectively. Exploration and production segment also includes a loss on the sale of the Permian Properties of $399.1 million for the six-month period ended June 30, 2013.

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18. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. As of June 30, 2013, the subsidiary guarantors, which are 100% owned by the Company, have jointly and severally guaranteed, on a full, unconditional and unsecured basis, the Company’s 8.75% Senior Notes due 2020, 7.5% Senior Notes due 2021, 8.125% Senior Notes due 2022 and 7.5% Senior Notes due 2023. The Senior Floating Rate Notes, prior to their purchase and redemption in 2012, were also jointly and severally guaranteed, on a full, unconditional and unsecured basis by the subsidiary guarantors. The subsidiary guarantees: (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves subsidiary guarantors; and (v) are only released under certain customary circumstances. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes.

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

During the three-month period ended June 30, 2013, an error was identified in the Company’s presentation of changes in intercompany advances (borrowings) in the condensed consolidating statement of cash flows. The intercompany advances (borrowings) represent cash flows between the Parent and the Guarantors and Non-Guarantors and is based on the Parent’s centralized treasury activities. Previously, the Company reflected the changes in intercompany advances (borrowings) in net cash provided by (used in) operating activities and such changes should have been reflected as a separate line within net cash provided by (used in) financing activities. The Company concluded these errors were not material individually or in the aggregate to any of the historical condensed consolidating financial information. Accordingly, the Company revised its condensed consolidating statements of cash flows to reflect the changes in intercompany advances (borrowings) in cash flows from financing activities. These revisions had no impact on the Company’s consolidated financial statements or the other condensed consolidating financial information. The revisions related to each of the Parent, Guarantors and Non-Guarantors associated with cash flows from operating activities had corresponding offsetting impacts to cash flows from financing activities resulting in no impact to net increase (decrease) in cash and cash equivalents. Net cash provided by (used in) operating activities increased (decreased) and net cash provided by (used in) financing activities decreased (increased) by the same amount as shown in the table below for the historical periods.



	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012			Six Months Ended June 30, 2012			Nine Months Ended September 30, 2012			Year Ended December 31, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010
	(in thousands)
Parent	$	(2,287,259	)	$	53,386		$	268,806		$	669,502		$	945,448		$	288,415		$	286,291
Guarantors	$	2,297,970		$	(16,578	)	$	(186,706	)	$	(550,489	)	$	(809,099	)	$	(172,927	)	$	(235,352	)
Non-Guarantors	$	(10,711	)	$	(36,808	)	$	(82,100	)	$	(119,013	)	$	(136,349	)	$	(115,488	)	$	(50,939	)

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Condensed Consolidating Balance Sheets



	June 30, 2013
	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,085,423	$	1,379		$	7,539	$	—		$	1,094,341
Accounts receivable, net	—		379,252			32,888		—			412,140
Intercompany accounts receivable	—		1,045,824			76,465		(1,122,289		)	—
Derivative contracts	—		43,560			24,928		(15,064		)	53,424
Prepaid expenses	—		38,056			106		—			38,162
Other current assets	1,375		24,297			18,251		—			43,923
Total current assets	1,086,798		1,532,368			160,177		(1,137,353		)	1,641,990
Property, plant and equipment, net	—		4,769,370			1,229,930		(55,585		)	5,943,715
Investment in subsidiaries	5,160,421		(47,054		)	—		(5,113,367		)	—
Derivative contracts	—		35,579			29,060		(21,466		)	43,173
Other assets	66,644		63,987			29		(5,902		)	124,758
Total assets	$	6,313,863	$	6,354,250		$	1,419,196	$	(6,333,673	)	$	7,753,636
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	169,444	$	627,193		$	5,405	$	—		$	802,042
Intercompany accounts payable	996,617		51,548			72,552		(1,120,717		)	—
Derivative contracts	—		16,862			—		(15,064		)	1,798
Asset retirement obligations	—		79,953			—		—			79,953
Total current liabilities	1,166,061		775,556			77,957		(1,135,781		)	883,793
Long-term debt	3,200,562		—			—		(5,902		)	3,194,660
Derivative contracts	—		33,183			—		(21,466		)	11,717
Asset retirement obligations	—		365,192			205		—			365,397
Other long-term obligations	1,873		19,898			—		—			21,771
Total liabilities	4,368,496		1,193,829			78,162		(1,163,149		)	4,477,338
Equity
SandRidge Energy, Inc. stockholders’ equity	1,945,367		5,160,421			1,341,034		(6,558,612		)	1,888,210
Noncontrolling interest	—		—			—		1,388,088			1,388,088
Total equity	1,945,367		5,160,421			1,341,034		(5,170,524		)	3,276,298
Total liabilities and equity	$	6,313,863	$	6,354,250		$	1,419,196	$	(6,333,673	)	$	7,753,636

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	December 31, 2012
	Parent		Guarantors			Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	300,228	$	922		$	8,616	—			$	309,766
Accounts receivable, net	—		411,197			34,309		—			445,506
Intercompany accounts receivable	2,162,471		397,238			683,406		(3,243,115		)	—
Derivative contracts	—		60,736			28,484		(18,198		)	71,022
Prepaid expenses	—		31,135			184		—			31,319
Restricted deposit	—		255,000			—		—			255,000
Other current assets	1,375		24,188			4,709		—			30,272
Total current assets	2,464,074		1,180,416			759,708		(3,261,313		)	1,142,885
Property, plant and equipment, net	—		7,236,685			1,298,877		(55,585		)	8,479,977
Investment in subsidiaries	5,425,907		(86,235		)	—		(5,339,672		)	—
Derivative contracts	—		15,957			33,114		(25,454		)	23,617
Other assets	83,642		66,512			—		(5,902		)	144,252
Total assets	$	7,973,623	$	8,413,335		$	2,091,699	$	(8,687,926	)	$	9,790,731
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	261,215	$	492,866		$	12,463	$	—		$	766,544
Intercompany accounts payable	975,578		1,594,180			671,673		(3,241,431		)	—
Derivative contracts	2,394		30,664			—		(18,198		)	14,860
Asset retirement obligations	—		118,504			—		—			118,504
Deposit on pending sale	—		255,000			—		—			255,000
Other current liabilities	—		15,546			—		—			15,546
Total current liabilities	1,239,187		2,506,760			684,136		(3,259,629		)	1,170,454
Long-term debt	4,306,985		—			—		(5,902		)	4,301,083
Derivative contracts	—		85,241			—		(25,454		)	59,787
Asset retirement obligations	—		379,710			196		—			379,906
Other long-term obligations	1,329		15,717			—		—			17,046
Total liabilities	5,547,501		2,987,428			684,332		(3,290,985		)	5,928,276
Equity
SandRidge Energy, Inc. stockholders’ equity	2,426,122		5,425,907			1,407,367		(6,890,543		)	2,368,853
Noncontrolling interest	—		—			—		1,493,602			1,493,602
Total equity	2,426,122		5,425,907			1,407,367		(5,396,941		)	3,862,455
Total liabilities and equity	$	7,973,623	$	8,413,335		$	2,091,699	$	(8,687,926	)	$	9,790,731

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Condensed Consolidating Statements of Operations



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended June 30, 2013
Total revenues	$	—		$	425,319		$	81,956		$	5,712		$	512,987
Expenses
Direct operating expenses	—			165,518			6,156			5,229			176,903
General and administrative	88			171,652			1,089			432			173,261
Depreciation, depletion, amortization and accretion	—			141,299			23,426			—			164,725
Impairment	—			12,703			2,940			—			15,643
Gain on derivative contracts	—			(88,653		)	(15,001		)	—			(103,654		)
Gain on sale of assets	—			(340		)	(9		)	—			(349		)
Total expenses	88			402,179			18,601			5,661			426,529
(Loss) income from operations	(88		)	23,140			63,355			51			86,458
Equity earnings from subsidiaries	41,399			18,233			—			(59,632		)	—
Interest (expense) income	(61,392		)	233			—			—			(61,159		)
Other (expense) income, net	—			(207		)	101			—			(106		)
(Loss) income before income taxes	(20,081		)	41,399			63,456			(59,581		)	25,193
Income tax expense	406			—			102			—			508
Net (loss) income	(20,487		)	41,399			63,354			(59,581		)	24,685
Less: net income attributable to noncontrolling interest	—			—			—			45,121			45,121
Net (loss) income attributable to SandRidge Energy, Inc.	$	(20,487	)	$	41,399		$	63,354		$	(104,702	)	$	(20,436	)

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	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended June 30, 2012
Total revenues	$	—		$	402,589		$	110,240		$	(34,395	)	$	478,434
Expenses
Direct operating expenses	—			149,859			44,772			(33,349		)	161,282
General and administrative	99			59,951			2,014			(348		)	61,716
Depreciation, depletion, amortization and accretion	—			140,339			22,234			—			162,573
Gain on derivative contracts	—			(562,081		)	(107,769		)	—			(669,850		)
(Gain) loss on sale of assets	—			(319		)	619			—			300
Total expenses	99			(212,251		)	(38,130		)	(33,697		)	(283,979		)
(Loss) income from operations	(99		)	614,840			148,370			(698		)	762,413
Equity earnings from subsidiaries	800,707			48,942			—			(849,649		)	—
Interest (expense) income	(68,527		)	278			(320		)	—			(68,569		)
Gain on sale of investment in subsidiary	55,585			—			—			(55,585		)	—
Bargain purchase gain	—			122,696			—			—			122,696
Other income (expense), net	—			13,951			—			(14,032		)	(81		)
Income before income taxes	787,666			800,707			148,050			(919,964		)	816,459
Income tax (benefit) expense	(100,721		)	—			104			—			(100,617		)
Net income	888,387			800,707			147,946			(919,964		)	917,076
Less: net income attributable to noncontrolling interest	—			—			—			99,004			99,004
Net income attributable to SandRidge Energy, Inc.	$	888,387		$	800,707		$	147,946		$	(1,018,968	)	$	818,072

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	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2013
Total revenues	$	—		$	865,636		$	159,484		$	(443	)	$	1,024,677
Expenses
Direct operating expenses	—			329,130			18,388			(555		)	346,963
General and administrative	175			248,470			4,060			—			252,705
Depreciation, depletion, amortization and accretion	—			301,188			46,178			—			347,366
Impairment	—			12,703			2,940			—			15,643
Gain on derivative contracts	—			(57,753		)	(5,004		)	—			(62,757		)
Loss on sale of assets	—			290,616			107,209			—			397,825
Total expenses	175			1,124,354			173,771			(555		)	1,297,745
Loss from operations	(175		)	(258,718		)	(14,287		)	112			(273,068		)
Equity earnings from subsidiaries	(265,486		)	(8,409		)	—			273,895			—
Interest (expense) income	(147,495		)	426			—			—			(147,069		)
Loss on extinguishment of debt	(82,005		)	—			—			—			(82,005		)
Other income (expense), net	—			1,215			(710		)	—			505
Loss before income taxes	(495,161		)	(265,486		)	(14,997		)	274,007			(501,637		)
Income tax expense	4,727			—			210			—			4,937
Net loss	(499,888		)	(265,486		)	(15,207		)	274,007			(506,574		)
Less: net loss attributable to noncontrolling interest	—			—			—			(6,798		)	(6,798		)
Net loss attributable to SandRidge Energy, Inc.	$	(499,888	)	$	(265,486	)	$	(15,207	)	$	280,805		$	(499,776	)

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	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2012
Total revenues	$	—		$	724,815		$	201,371		$	(66,117	)	$	860,069
Expenses
Direct operating expenses	—			264,352			82,956			(64,947		)	282,361
General and administrative	185			108,065			4,447			(680		)	112,017
Depreciation, depletion, amortization, accretion and impairment	—			231,255			35,503			—			266,758
Gain on derivative contracts	—			(341,146		)	(74,058		)	—			(415,204		)
(Gain) loss on sale of assets	—			(745		)	4,125			—			3,380
Total expenses	185			261,781			52,973			(65,627		)	249,312
(Loss) income from operations	(185		)	463,034			148,398			(490		)	610,757
Equity earnings from subsidiaries	706,180			46,640			—			(752,820		)	—
Interest (expense) income	(135,233		)	265			(566		)	—			(135,534		)
Gain on sale of investment in subsidiary	55,585			—			—			(55,585		)	—
Bargain purchase gain	—			122,696			—			—			122,696
Other income, net	—			73,545			—			(71,158		)	2,387
Income before income taxes	626,347			706,180			147,832			(880,053		)	600,306
Income tax (benefit) expense	(100,780		)	—			234			—			(100,546		)
Net income	727,127			706,180			147,598			(880,053		)	700,852
Less: net income attributable to noncontrolling interest	—			—			—			100,958			100,958
Net income attributable to SandRidge Energy, Inc.	$	727,127		$	706,180		$	147,598		$	(981,011	)	$	599,894

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Condensed Consolidating Statements of Cash Flows



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2013
Net cash (used in) provided by operating activities	$	(162,836	)	$	420,672		$	120,672		$	6,175		$	384,683
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(828,585		)	—			—			(828,585		)
Proceeds from sale of assets	—			2,563,791			95			—			2,563,886
Other	—			31,015			37			(39,654		)	(8,602		)
Net cash provided by investing activities	—			1,766,221			132			(39,654		)	1,726,699
Cash flows from financing activities
Repayments of borrowings	(1,115,500		)	—			—			—			(1,115,500		)
Distributions to unitholders	—			—			(144,810		)	46,094			(98,716		)
Premium on debt redemption	(61,997		)	—			—			—			(61,997		)
Intercompany borrowings (advances), net	2,181,850			(2,192,164		)	10,314			—			—
Other	(56,322		)	5,728			12,615			(12,615		)	(50,594		)
Net cash provided by (used in) financing activities	948,031			(2,186,436		)	(121,881		)	33,479			(1,326,807		)
Net increase (decrease) in cash and cash equivalents	785,195			457			(1,077		)	—			784,575
Cash and cash equivalents at beginning of year	300,228			922			8,616			—			309,766
Cash and cash equivalents at end of period	$	1,085,423		$	1,379		$	7,539		$	—		$	1,094,341

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	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2012 (Revised)
Net cash provided by (used in) operating activities	$	413,460		$	(127,344	)	$	71,648		$	59,942		$	417,706
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(1,091,667		)	(31,373		)	—			(1,123,040		)
Acquisition of assets	(693,091		)	(68,484		)	—			—			(761,575		)
Proceeds from sale of assets	129,830			345,205			1,409			(55,585		)	420,859
Conveyance of property for royalty trust	—			579,425			(587,087		)	7,662			—
Other	(61,487		)	226,253			—			(164,766		)	—
Net cash used in investing activities	(624,748		)	(9,268		)	(617,051		)	(212,689		)	(1,463,756		)
Cash flows from financing activities
Proceeds from borrowings	750,000			—			—			—			750,000
Proceeds from issuance of royalty trust units	—			—			587,086			—			587,086
Proceeds from the sale of royalty trust units	—			—			—			123,549			123,549
Distributions to unitholders	—			—			(118,018		)	41,217			(76,801		)
Cash (paid) received on settlement of financing derivative contracts	—			(45,312		)	12,019			(12,019		)	(45,312		)
Intercompany (advances) borrowings, net	(268,806		)	186,706			82,100			—			—
Other	(63,051		)	—			(16,029		)	—			(79,080		)
Net cash provided by financing activities	418,143			141,394			547,158			152,747			1,259,442
Net increase in cash and cash equivalents	206,855			4,782			1,755			—			213,392
Cash and cash equivalents at beginning of year	204,015			437			3,229			—			207,681
Cash and cash equivalents at end of period	$	410,870		$	5,219		$	4,984		$	—		$	421,073

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19. Subsequent Events

Royalty Trust Distributions. On July 25, 2013, the Royalty Trusts announced quarterly distributions for the three-month period ended June 30, 2013. The following distributions are expected to be paid on August 29, 2013 to holders of record as of the close of business on August 14, 2013 (in thousands):



Royalty Trust	Total Distribution		Amount to be Distributed to Third-Party Unitholders
Mississippian Trust I	$	16,920	$	12,512
Permian Trust	30,707		21,353
Mississippian Trust II	33,952		20,422
Total	$	81,579	$	54,287

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

Introduction

The following discussion and analysis is intended to help the reader understand the Company’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as the Company’s audited consolidated financial statements and the accompanying notes included in the 2012 Form 10-K. The Company’s discussion and analysis includes the following subjects:


•	Overview;


•	Results by Segment;


•	Consolidated Results of Operations;


•	Liquidity and Capital Resources;


•	Critical Accounting Policies and Estimates;


•	Valuation Allowance; and


•	Employee Compensation Plans.

The financial information with respect to the three and six-month periods ended June 30, 2013 and 2012, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Overview

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

The Company also operates businesses and infrastructure systems that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and natural gas marketing business, a saltwater disposal system, an electrical transmission system and an oil field services business, which includes a drilling rig business. These complementary businesses provide the Company with operational flexibility and an advantageous cost structure by reducing the Company’s dependence on third parties for these services. The extent to which each of these supplemental businesses contributes to the Company’s consolidated results of operations largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for the Company’s own account are eliminated in consolidation and, therefore, do not directly contribute to the Company’s consolidated results of operations.

Operational Highlights

Operational highlights for the three and six-month periods ended June 30, 2013 include the following:

•

Drilled 140 and 263 wells, excluding salt water disposal wells, in the Mid-Continent area during the three and six-month periods ended June 30, 2013, respectively. Mid-Continent properties contributed approximately 4,504 MBoe and 8,255 MBoe, or 54% and 48% of the Company’s total production, during the three and six-month periods ended June 30, 2013, respectively, compared to approximately 2,522 MBoe and 4,527 MBoe, or 31% and 32%, during the three and six-month periods ended June 30, 2012, respectively.

•

Gulf of Mexico properties acquired during the second quarter of 2012 contributed production of approximately 2,376 MBoe, or 29%, and 5,041 MBoe, or 29%, of the Company’s total production, during the three and six-month periods ended June 30, 2013, respectively, compared to approximately 1,807 MBoe, or 13% and 22% of total production, during the three and six-month periods ended June 30, 2012, respectively.

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•	Production, revenues and direct operating expenses of the properties located in the Permian Basin sold in February 2013, described below, that are included in the Company’s results during the three-month period ended June 30, 2012 and six-month periods ended June 30, 2013 and 2012 were as follows:



	Three Months Ended June 30,		Six Months Ended June 30,
	2012		2013 (1)		2012
Production (MBoe)	2,125		1,148		4,380
Revenues (in thousands)	$	133,630	$	68,027	$	295,395
Direct operating expenses (in thousands)	$	29,291	$	17,453	$	65,281

_______________

(1) Information for the six-month period ended June 30, 2013 is through February 26, 2013, the date of sale.

The decrease in production, revenues and direct operating expenses for the six-month period ended June 30, 2013 compared to the same period in 2012 is a result of natural declines in production due to decreased drilling activity in the Permian Basin in advance of the sale and the Company’s ownership of such properties for only a portion of the first six months of 2013.

2013 Developments and Outlook

Sale of Permian Properties. On February 26, 2013, the Company sold the Permian Properties for $2.6 billion, subject to certain post-closing adjustments expected to be finalized in the third quarter of 2013. The Company used a portion of the sale proceeds to fund the redemption of approximately $1.1 billion aggregate principal amount of outstanding Senior Fixed Rate Notes, discussed below, and intends to use the remaining proceeds to fund its capital expenditures in the Mississippian formation and for general corporate purposes. The Company recorded a non-cash loss on the sale of $399.1 million, of which $71.7 million was allocated to noncontrolling interests. Additionally, the Company settled a portion of its existing oil derivative contracts in February 2013 prior to their respective maturities to reduce volumes hedged in proportion to the anticipated reduction in daily production volumes due to the sale, which resulted in a realized loss of approximately $29.6 million. Including the impact from the sale of the Permian Properties, the Company anticipates total production during 2013 of approximately 33.3 MMBoe.

Redemption of Senior Fixed Rate Notes. In March 2013, the Company redeemed the outstanding $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and the outstanding $750.0 million aggregate principal amount of its 8.0% Senior Notes due 2018 for total consideration of $1,061.34 per $1,000 principal amount and $1,052.77 per $1,000 principal amount, respectively. The premium paid to redeem these notes and the associated unamortized debt issuance costs resulted in a loss on extinguishment of debt of $82.0 million for the six-month period ended June 30, 2013. The redemption of these Senior Fixed Rate Notes will result in a reduction in interest expense from the anticipated total for the year ending December 31, 2013 of approximately $72.8 million.

Results by Segment

The Company operates in three business segments: exploration and production, drilling and oil field services and midstream services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of oil and natural gas properties and includes the activities of the Royalty Trusts. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells and provides various oil field services. The midstream services segment is engaged in the purchasing, gathering, treating and selling of natural gas and the distribution of electricity to the Company’s exploration and production operations in the Mississippian formation.

Management evaluates the performance of the Company’s business segments based on income (loss) from operations, which is defined as segment operating revenues less operating expenses and depreciation, depletion, amortization, accretion and impairment. Results of these measurements provide important information to the Company about the activity, profitability and contributions of each of the Company’s lines of business. The results of the Company’s business segments for the three and six-month periods ended June 30, 2013 and 2012 are discussed below.

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Exploration and Production Segment

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

The primary factors affecting the financial results of the Company’s exploration and production segment are the prices the Company receives for its oil and natural gas production, the quantity of oil and natural gas it produces and changes in the fair value of its commodity derivative contracts. The average NYMEX prices for oil and natural gas during the three and six-month periods ended June 30, 2013 and 2012 are shown in the following table:



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Oil (per Bbl)	$	94.14	$	93.30	$	94.22	$	98.11
Natural gas (per Mcf)	$	4.02	$	2.28	$	3.76	$	2.36

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Set forth in the table below is financial, production and pricing information for the three and six-month periods ended June 30, 2013 and 2012.



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Results (in thousands)
Revenues
Oil(1)	$	359,822		$	388,809		$	750,146		$	697,161
Natural gas	94,460			40,949			182,153			73,962
Other	4,092			5,076			7,485			6,832
Inter-segment revenue	(81		)	(77		)	(162		)	(155		)
Total revenues	458,293			434,757			939,622			777,800
Operating expenses
Production	117,581			123,425			251,023			207,491
Production taxes	6,564			11,001			16,003			23,255
Depreciation and depletion—oil and natural gas	138,903			139,260			296,429			226,326
Accretion of asset retirement obligations	9,800			7,965			19,579			10,572
Gain on derivative contracts	(103,654		)	(669,850		)	(62,757		)	(415,204		)
(Gain) loss on sale of assets	(16		)	15			399,049			3,373
Other operating expenses	47,449			36,606			80,338			59,488
Total operating expenses	216,627			(351,578		)	999,664			115,301
Income (loss) from operations	$	241,666		$	786,335		$	(60,042	)	$	662,499

Production data
Oil (MBbls)(1)	4,119			4,556			8,561			7,982
Natural gas (MMcf)	25,233			21,903			52,554			37,648
Total volumes (MBoe)	8,325			8,206			17,320			14,257
Average daily total volumes (MBoe/d)	91.5			90.2			95.7			78.3
Average prices—as reported(2)
Oil (per Bbl)(1)	$	87.35		$	85.35		$	87.62		$	87.34
Natural gas (per Mcf)	$	3.74		$	1.87		$	3.47		$	1.96
Total (per Boe)	$	54.57		$	52.37		$	53.83		$	54.09
Average prices—including impact of derivative contract settlements
Oil (per Bbl)(1)	$	91.87		$	89.76		$	91.43		$	88.26
Natural gas (per Mcf)	$	3.68		$	2.39		$	3.43		$	2.37
Total (per Boe)	$	56.62		$	56.21		$	55.59		$	55.68

__________________


(1)	Includes natural gas liquids.


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

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Revenues

Exploration and production segment revenues increased $23.5 million, or 5.4%, in the three-month period ended June 30, 2013 from the same period in 2012, as a result of a 3.3 Bcf, or 15.2%, increase in natural gas production, a $1.87 per Mcf, or 100.0%, increase in the average price received for natural gas production and a $2.00 per Bbl, or 2.3%, increase in the average price received for oil production. The increases were partially offset by a decrease of 437 MBbls, or 9.6%, in oil production due to the sale of the Permian Properties in February 2013. Exploration and production segment revenues increased $161.8 million, or 20.8%, in the six-month period ended June 30, 2013 from the same period in 2012, as a result of a 579 MBbls, or 7.3%, increase in oil production, a 14.9 Bcf, or 39.6%, increase in natural gas production and a $1.51 per Mcf, or 77.0%, increase in the average price received for natural gas production. The increase in combined production in the three and six-month periods ended June 30, 2013 compared to the same periods in 2012 was due to production of approximately 2,376 MMBoe and 5,041 MMBoe, respectively, from properties located in the Gulf of Mexico that were acquired during the second quarter of 2012 combined with an increase in production from Mid-Continent properties of approximately 1,982 MBoe and 3,728 MBoe, respectively, as a result of increased drilling throughout 2012 and continuing in 2013. The increases were partially offset by a decrease in production from the Permian Basin due to the sale of the Permian Properties in February 2013 and natural declines in production as a result of decreased drilling activity in this area prior to the closing of the sale.

Operating Expenses

Production expense includes the costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production expenses decreased $5.8 million, or 4.7%, in the three-month period ended June 30, 2013 compared to the same period in 2012 primarily due to a 9.6% decrease in oil production in 2013 due to the sale of the Permian Properties in February 2013. Production expenses increased $43.5 million, or 21.0%, in the six-month period ended June 30, 2013 compared to the same period in 2012 primarily due to increased oil and natural gas production. Combined production increased 3,063 MBoe, or 21.5% in the six-month period ended June 30, 2013. During the six-month period ended June 30, 2013, production expense was $14.49 per Boe, down slightly from the comparable 2012 period rate of $14.55 per Boe.

Production taxes decreased by $4.4 million, or 40.3%, and $7.3 million, or 31.2%, in the three and six-month periods ended June 30, 2013, respectively, compared to the same periods in 2012. Approximately 30% of the Company’s oil and natural gas production for the three and six-month periods ended June 30, 2013 was from the Gulf of Mexico which is not subject to production tax, compared to 22% and 13% of total production for the three and six-month periods ended June 30, 2012, respectively. In addition, wells drilled in the Mississippian formation in Oklahoma benefit from a tax credit incentive program that reduces the combined statutory rates applicable to the first four years of production from such wells.

Depreciation and depletion for the Company’s oil and natural gas properties for the three-month period ended June 30, 2013 was consistent with expense for the same period in 2012 due to comparable production volumes and depreciation and depletion rates. The depreciation and depletion rate per Boe was $16.69 for the three-month period ended June 30, 2013 compared to $16.97 for the three-month period ended June 30, 2012. Depreciation and depletion increased $70.1 million, or 31.0%, for the six-month period ended June 30, 2013 compared to the same period in 2012. The increase was due to a 21.5% increase in the Company’s combined production volume as well as an increase in the depreciation and depletion rate per Boe to $17.11 for the six-month period ended June 30, 2013 from $15.87 per Boe for the comparable period in 2012. The increase in the depreciation and depletion rates for the six-month periods noted above primarily resulted from the acquisition of properties located in the Gulf of Mexico during 2012.

Accretion on asset retirement obligations increased $1.8 million and $9.0 million for the three and six-month periods ended June 30, 2013, respectively, compared to the same periods in 2012. These increases are primarily the result of the increase in future plugging and abandonment obligations associated with the oil and natural gas properties located in the Gulf of Mexico that were acquired during the second quarter of 2012.

Loss on sale of assets increased $395.7 million for the six-month period ended June 30, 2013 compared to the same period in 2012 primarily as a result of the $399.1 million loss on the sale of the Permian Properties in February 2013.

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The following table summarizes the cash settlements and valuation gain and loss on the Company’s commodity derivative contracts, which are included in income (loss) from operations for the exploration and production segment for the three and six-month periods ended June 30, 2013 and 2012 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Realized (gain) loss
Realized (gain) loss on early settlements	$	(654	)	$	(57,292	)	$	28,968		$	(57,292	)
Realized loss on amended contracts	—			—			—			117,108
Realized gain on settlements at contractual maturity	(17,063		)	(31,828		)	(30,600		)	(23,480		)
Total realized (gain) loss	(17,717		)	(89,120		)	(1,632		)	36,336
Unrealized gain	(85,937		)	(580,730		)	(61,125		)	(451,540		)
Gain on commodity derivative contracts	$	(103,654	)	$	(669,850	)	$	(62,757	)	$	(415,204	)

The Company’s derivative contracts are not designated as accounting hedges and, as a result, realized and unrealized gains or losses on commodity derivative contracts are recorded each quarter as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Early settlements are not considered in the calculation of effective prices. In conjunction with the sale of the Permian Properties, the Company settled a portion of its existing oil derivative contracts prior to contractual maturity, resulting in a realized loss of $29.6 million which is included in total realized (gain) loss on early settlements for the six-month period ended June 30, 2013. The realized gain on settlements at contractual maturity for the three and six-month periods ended June 30, 2013 and 2012 was due primarily to lower oil prices at the time of settlement compared to the contract price for the Company’s oil price swaps. Non-cash realized losses of $117.1 million resulting from the amendment of certain 2012 derivative contracts to contracts maturing in 2014 and 2015 were included in the net realized loss for the six-month period ended June 30, 2012.

Unrealized gain or loss on derivative contracts represents the change in fair value of open derivative contracts during the period. The unrealized gain on the Company’s commodity contracts recorded during the three and six-month periods ended June 30, 2013 and 2012 was attributable to a decrease in average oil prices at the end of the period compared to the average oil prices at the beginning of the period, or the contract price for contracts entered into during the period.

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

Drilling and Oil Field Services Segment

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

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Set forth in the table below is financial and drilling rig information regarding the drilling and oil field services segment for the three and six-month periods ended June 30, 2013 and 2012.



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Results (in thousands)
Revenues	$	47,100		$	104,076		$	96,837		$	202,408
Inter-segment revenue	(31,011		)	(70,444		)	(63,378		)	(139,467		)
Total revenues	16,089			33,632			33,459			62,941
Operating expenses	24,944			28,954			51,279			54,784
Impairment	10,588			—			10,588			—
(Loss) income from operations	$	(19,443	)	$	4,678		$	(28,408	)	$	8,157

Drilling rig statistics
Average number of operational rigs owned during the period	27.0			30.0			28.5			29.6
Average number of rigs working for third parties	3.3			9.6			3.4			9.5
Number of days drilling for third parties	284			821			601			1,681
Average drilling revenue per day per rig drilling for third parties(1)	$	15,630		$	17,194		$	15,371		$	16,519

Rig status - June 30							2013			2012
Working for SandRidge							9			21
Working for third parties							4			8
Idle(2)							14			—
Total operational							27			29
Non-operational(3)							3			2
Total rigs							30			31

____________________


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


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


(3)	Rigs held for sale at June 30, 2013.

Drilling and oil field services segment revenues decreased $17.5 million to $16.1 million in the three-month period ended June 30, 2013 from the same period in 2012 and decreased $29.5 million to $33.5 million in the six-month period ended June 30, 2013 from the same period in 2012 due to a decrease in the number of rigs working for third parties and a decrease in supplies sold to, and oil field services work performed for, wells that had been operated by the Company in the Permian Basin prior to their sale. Drilling and oil field services segment operating expenses decreased $4.0 million and $3.5 million during the three and six-month periods ended June 30, 2013, respectively, compared to the same periods in 2012 due to the decrease in work performed in the Permian Basin, partially offset by costs associated with maintenance performed on rigs that were stacked as a result of the sale of the Permian Properties. During the three and six-month periods ended June 30, 2013, the Company recorded an impairment of approximately $10.6 million on certain drilling assets identified for sale in order to adjust their carrying values to fair value. The impairment and decrease in revenue resulted in a loss from operations of $19.4 million and $28.4 million in the three and six-month periods ended June 30, 2013, respectively.

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Midstream Services Segment

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

Set forth in the table below is financial information regarding the midstream services segment for the three and six-month periods ended June 30, 2013 and 2012.



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Results (in thousands)
Operating revenues	$	41,038		$	24,798		$	77,872		$	50,960
Construction contract	23,253			—			23,253			—
Inter-segment revenue	(26,464		)	(16,296		)	(51,160		)	(34,591		)
Total revenues	37,827			8,502			49,965			16,369
Operating expenses	22,530			12,133			37,127			22,727
Construction contract	23,253			—			23,253			—
Loss from operations	$	(7,956	)	$	(3,631	)	$	(10,415	)	$	(6,358	)

Gas Marketed
Volumes (MMcf)	1,961			2,280			4,009			4,681
Average price	$	4.16		$	2.25		$	3.75		$	2.27

Midstream services segment revenues and expenses, excluding construction contract revenue and expense, for the three-month period ended June 30, 2013 increased $6.1 million and $10.4 million, respectively, from the same period in 2012. Segment operating revenues and expenses, excluding construction contract revenue and expense, for the six-month period ended June 30, 2013 increased $10.3 million and $14.4 million, respectively, from the same period in 2012. The increases in operating revenue and expenses were due to an increase of $1.91 per Mcf and $1.48 per Mcf in the average price received for natural gas purchased and marketed in west Texas during the three and six-month periods ended June 30, 2013, respectively, and an increase in revenue from and expenses related to electrical transmission services provided by the Company’s expanded electrical infrastructure in the Mid-Continent to third-party working interest owners. In addition, operating expenses for the three and six-month periods ended June 30, 2013 include an impairment of $2.1 million on certain midstream pipe inventory and natural gas compressors due to the determination that their future use was limited. These increases were slightly offset by a 319 MMcf and 672 MMcf decrease in third-party volumes processed and marketed during the three and six-month periods ended June 30, 2013, respectively, as a result of decreased natural gas production in west Texas.

During the second quarter of 2013, the Company substantially completed the construction of a series of electrical transmission expansion and upgrade projects and, as a result, recognized construction contract revenue and costs equal to $23.3 million. For more information about these projects, see “Note 7 - Construction Contracts” to the unaudited condensed consolidated financial statements included in this Quarterly Report.

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Consolidated Results of Operations

Revenues

The Company’s consolidated revenues for the three and six-month periods ended June 30, 2013 and 2012 are presented in the table below.



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Revenues
Oil and natural gas	$	454,282	$	429,758	$	932,299	$	771,123
Drilling and services	16,078		33,632		33,448		62,941
Midstream and marketing	15,198		8,852		28,230		17,158
Construction contract	23,253		—		23,253		—
Other	4,176		6,192		7,447		8,847
Total revenues(1)	$	512,987	$	478,434	$	1,024,677	$	860,069

___________________

(1)

Includes $53.8 million and $44.7 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three-month periods ended June 30, 2013 and 2012, respectively. Includes $99.5 million and $80.2 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the six-month periods ended June 30, 2013 and 2012, respectively.

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

Other revenues decreased for the three and six-month periods ended June 30, 2013 compared to the same periods in 2012 due to the Company no longer selling CO₂ to third parties from the Company’s natural gas treating plants or CO₂ compression facilities as natural gas from the Company’s legacy natural gas treating plants was diverted to the Century Plant during 2013. This decrease was slightly offset by an increase in revenues from the Bullwinkle and other offshore platforms, which were acquired as part of the Dynamic Acquisition. The Bullwinkle platform serves as a processing hub for deepwater production for third-party fields for which it receives production handling revenue.

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Expenses

The Company’s consolidated expenses for the three and six-month periods ended June 30, 2013 and 2012 are presented below.



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In thousands)
Expenses
Production	$	116,811		$	122,481		$	249,312		$	205,791
Production taxes	6,564			11,001			16,003			23,255
Cost of sales	15,348			19,241			31,665			36,802
Midstream and marketing	14,927			8,559			26,730			16,513
Construction contract	23,253			—			23,253			—
Depreciation and depletion—oil and natural gas	138,903			139,260			296,429			226,326
Depreciation and amortization—other	16,022			15,348			31,358			29,860
Accretion of asset retirement obligations	9,800			7,965			19,579			10,572
Impairment	15,643			—			15,643			—
General and administrative	173,261			61,716			252,705			112,017
Gain on derivative contracts	(103,654		)	(669,850		)	(62,757		)	(415,204		)
(Gain) loss on sale of assets	(349		)	300			397,825			3,380
Total expenses(1)	$	426,529		$	(283,979	)	$	1,297,745		$	249,312

___________________

(1)

Includes $8.5 million and $(54.5) million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three-month periods ended June 30, 2013 and 2012, respectively. Includes $105.5 million and $(21.2) million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the six-month periods ended June 30, 2013 and 2012, respectively. The expenses attributable to noncontrolling interests in consolidated VIEs for the six-month period ended June 30, 2013 include $71.7 million of allocated loss on sale of assets associated with the sale of the Permian Properties, respectively.

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

General and administrative expenses increased $111.5 million, or 180.7%, for the three-month period ended June 30, 2013 from the same period in 2012. This increase is due primarily to $99.4 million in severance costs associated with former Company executives and $11.6 million in costs associated with changes to the Company’s annual incentive plan. General and administrative expenses increased $140.7 million, or 125.6%, for the six-month period ended June 30, 2013 from the same period in 2012. This increase is due primarily to $109.8 million in severance costs associated with former Company executives, $11.6 million in costs associated with changes to the Company’s annual incentive plan and $20.8 million in costs related to the TPG-Axon consent solicitation.

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

The Company’s other income (expense), taxes and net income (loss) attributable to noncontrolling interest for the three and six-month periods ended June 30, 2013 and 2012 are presented in the table below.



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In thousands)
Other income (expense)
Interest expense	$	(61,159	)	$	(68,569	)	$	(147,069	)	$	(135,534	)
Bargain purchase gain	—			122,696			—			122,696
Loss on extinguishment of debt	—			—			(82,005		)	—
Other (expense) income, net	(106		)	(81		)	505			2,387
Total other (expense) income	(61,265		)	54,046			(228,569		)	(10,451		)
Income (loss) before income taxes	25,193			816,459			(501,637		)	600,306
Income tax expense (benefit)	508			(100,617		)	4,937			(100,546		)
Net income (loss)	24,685			917,076			(506,574		)	700,852
Less: net income (loss) attributable to noncontrolling interest	45,121			99,004			(6,798		)	100,958
Net (loss) income attributable to SandRidge Energy, Inc.	$	(20,436	)	$	818,072		$	(499,776	)	$	599,894

Interest expense for the three and six-month periods ended June 30, 2013 and 2012 consisted of the following:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In thousands)
Interest expense
Interest expense on debt	$	63,046		$	68,141		$	149,282		$	123,684
Amortization of debt issuance costs, discounts and premium	2,478			3,513			6,158			6,686
Dynamic Acquisition committed financing fee	—			—			—			10,875
Interest rate swap loss	—			49			14			895
Capitalized interest	(4,365		)	(3,134		)	(8,385		)	(6,606		)
Total interest expense	$	61,159		$	68,569		$	147,069		$	135,534

Interest expense increased $11.5 million for the six-month period ended June 30, 2013 compared to the same period in 2012, primarily as a result of issuances of Senior Fixed Rate Notes in 2012, partially offset by a reduction in interest expense associated with the Senior Floating Rate Notes and Senior Fixed Rate Notes repurchased and redeemed in 2012 and the first quarter of 2013. The increase in interest expense on debt was partially offset by the committed financing fees of $10.9 million, which were expensed during the six-month period ended June 30, 2012 as a result of the Company’s election to issue Senior Fixed Rate Notes to fund the cash portion of the Dynamic Acquisition rather than utilize previously secured committed financing. See “Note 8—Long-Term Debt” to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of the Company’s long-term debt transactions in 2013 and 2012.

The bargain purchase gain recorded during the three and six-month periods ended June 30, 2012 resulted from the excess of net assets acquired over consideration paid in the Dynamic Acquisition in April 2012. The Company was able to acquire Dynamic for less than the estimated fair value of its net assets due to their offshore location resulting in less bidding competition.

In connection with the March 2013 redemption of the Company’s 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018, the Company recognized a loss on extinguishment of debt of $82.0 million for the six-month period ended June 30, 2013. This loss represents the premium paid to redeem these notes and the unamortized debt issuance costs associated with the notes.

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The Company's income tax expense of $0.5 million for the three-month period ended June 30, 2013 is related to state income tax expense of $0.8 million partially offset by a benefit of $0.3 million for federal AMT, both associated with the tax year ending December 31, 2013. The Company recorded a reduction to the previously recorded current liability for federal AMT and the corresponding deferred tax asset each in the amount of $0.3 million for the three-month period ended June 30, 2013. As a result of recording a reduction to the deferred tax asset, the Company decreased its valuation allowance against its net deferred tax asset by $0.3 million. The Company's income tax expense of $4.9 million for the six-month period ended June 30, 2013 is primarily related to federal AMT associated with the tax year ending December 31, 2013. The Company recorded a current liability and a corresponding deferred tax asset each in the amount of $4.0 million for the six-month period ended June 30, 2013. As a result of recording a deferred tax asset, the Company increased its valuation allowance against its net deferred tax asset by $4.0 million. Despite incurring federal AMT and state income tax, the Company's effective tax rate remains low as a result of having a valuation allowance on its net deferred tax asset.

Net income (loss) attributable to noncontrolling interest represents the portion of net income (loss) attributable to third-party ownership in the Company’s consolidated VIEs and subsidiaries. Net income (loss) attributable to noncontrolling interest decreased to $45.1 million for the three-month period ended June 30, 2013 from $99.0 million during the same period in 2012 due primarily to a decrease in unrealized gains on the Royalty Trusts’ derivative contracts in the 2013 period compared to the 2012 period. Net loss attributable to noncontrolling interest of $6.8 million for the six-month period ended June 30, 2013 compared to net income attributable to noncontrolling interest of $101.0 million during the same period in 2012 was due primarily to the $71.7 million loss on the sale of the Permian Properties attributable to noncontrolling interest during the six-month period ended June 30, 2013 as well as the decrease in unrealized gains on the Royalty Trusts’ derivative contracts in the 2013 period compared to the 2012 period, partially offset by net income from the Mississippian Trust II, which completed its initial public offering in April 2012.

Liquidity and Capital Resources

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

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

After a comprehensive review and analysis by management and the Board of the Company’s strategy, assets and spending levels, which resulted in an increased focus on capital discipline, creating sustainable returns and lowering risk levels, the Company’s 2013 budget for capital expenditures, including expenditures related to the Company’s drilling programs for the Royalty Trusts, was revised in May 2013 to approximately $1.45 billion. The majority of the Company’s capital expenditures are discretionary and could be curtailed if the Company’s cash flows are less than expected or if the Company is unable to obtain capital on attractive terms. The Company and one of its wholly owned subsidiaries are parties to development agreements with the Permian Trust and the Mississippian Trust II that obligate the Company to drill, or cause to be drilled, a specified number of wells within specified areas of mutual interest for each Royalty Trust by March 31, 2016 and December 31, 2016, respectively. The Company fulfilled its drilling obligation to the Mississippian Trust I during the second quarter of 2013. In addition, production targets contained in certain gathering and treating arrangements require the Company to incur capital expenditures or make associated shortfall payments.

Based on current cash balances, anticipated oil and natural gas prices and production, commodity derivative contracts in place, and funding commitments from third parties for drilling carries, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2013. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit borrowings. The Company may increase or decrease planned capital expenditures depending on oil and natural gas prices, the availability of capital through asset sales and the issuance of additional equity or long-term debt.

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The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depend on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows, and while fixed price swap contracts are in place for the majority of expected oil production for the remainder of 2013, fixed price swap contracts and collars are in place for only a portion of expected oil production for 2014 and 2015. No fixed price swap contracts are in place for any of the Company’s future natural gas production or for its oil production beyond 2015.

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

As of June 30, 2013, the Company’s cash and cash equivalents were $1.1 billion, which includes $7.5 million attributable to the Company’s consolidated VIEs that is available only to satisfy obligations of the VIEs. The Company had approximately $3.2 billion in total debt outstanding and $28.6 million in outstanding letters of credit with no amount outstanding under its senior credit facility at June 30, 2013. As of and for the three and six-month periods ended June 30, 2013, the Company was in compliance with applicable covenants under all of its outstanding Senior Fixed Rate Notes and senior credit facility. As of August 1, 2013, the Company’s cash and cash equivalents were approximately $1.0 billion, including $6.7 million attributable to the Company’s consolidated VIEs. Additionally, there was no amount outstanding under the Company’s senior credit facility and $28.6 million in outstanding letters of credit which reduced the availability under the senior credit facility to $746.4 million.

Working Capital

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

At June 30, 2013, the Company had a working capital surplus of $758.2 million compared to a deficit of $27.6 million at December 31, 2012. Current assets and current liabilities at December 31, 2012 each included a $255.0 million escrow deposit received in conjunction with the agreement to sell the Permian Properties. This deposit had no impact on working capital at December 31, 2012. Excluding the change in current assets attributable to the escrow deposit, current assets increased $754.1 million at June 30, 2013, compared to current assets at December 31, 2012, primarily due to a $784.6 million increase in cash and cash equivalents due primarily to net proceeds received from the sale of the Permian Properties after funding the March 2013 redemption of the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018. This increase was slightly offset by a $33.4 million decrease in accounts receivable and amounts due from working interest partners as a result of a decrease in drilling activity due to the sale of the Permian Properties, and a $17.6 million decrease in the net asset position of the Company’s current derivative contracts due to an increase in oil prices since December 31, 2012 and the settlement of derivative contracts during the six month-period ended June 30, 2013. Excluding the change in current liabilities due to the escrow deposit, current liabilities decreased $31.7 million, primarily due to a $38.6 million decrease in the Company’s current asset retirement obligation due to Gulf of Mexico plugging and abandonment obligations settled during the six-month period ended June 30, 2013, a $19.6 million decrease in accounts payable and accrued expenses as a result of a decrease in drilling activity due to the sale of the Permian Properties, a $15.5 million decrease in billings and contract loss in excess of costs incurred due to costs incurred in the final stages of the Century Plant construction and a $13.1 million decrease in the net liability position of the Company’s current derivative contracts due to settlements on outstanding commodity contracts during 2013. These decreases were offset by $55.1 million in related party accounts payable at June 30, 2013 for amounts payable to the Company’s former CEO in connection with his separation from the Company.

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Cash Flows

The Company’s cash flows for the six-month periods ended June 30, 2013 and 2012 are presented in the following table and discussed below:



	Six Months Ended June 30,
	2013			2012
	(In thousands)
Cash flows provided by operating activities	$	384,683		$	417,706
Cash flows provided by (used in) investing activities	1,726,699			(1,463,756		)
Cash flows (used in) provided by financing activities	(1,326,807		)	1,259,442
Net increase in cash and cash equivalents	$	784,575		$	213,392

Cash Flows from Operating Activities

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

Net cash provided by operating activities for the six-month period ended June 30, 2013 decreased from the comparable period in 2012 primarily due to an increase in cash paid during the six-month period ended June 30, 2013 to settle the Company’s plugging and abandonment obligations, primarily on Gulf of Mexico properties acquired during the second quarter of 2012, and a decrease in realized gains on the Company’s commodity derivative contracts.

Cash Flows from Investing Activities

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

Cash flows provided by investing activities were $1.7 billion for the six-month period ended June 30, 2013 compared to cash flows used by investing activities of $1.5 billion for the same period in 2012. The change was due primarily to proceeds received from the sale of the Permian Properties and a decrease in capital expenditures and acquisitions in the six-month period ended June 30, 2013. Proceeds from the sale of assets totaled $2.6 billion in the six-month period ended June 30, 2013 compared to $420.9 million in the same period in 2012.

Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the six-month periods ended June 30, 2013 and 2012 are summarized below:



	Six Months Ended June 30,
	2013		2012
	(In thousands)
Capital Expenditures
Exploration and production	$	716,173	$	1,010,248
Drilling and oil field services	1,515		13,752
Midstream services	30,332		41,729
Other	27,850		65,983
Capital expenditures, excluding acquisitions	775,870		1,131,712
Acquisitions	8,602		761,575
Total	$	784,472	$	1,893,287

Capital expenditures for the six-month period ended June 30, 2013 decreased by $1.1 billion from the same period in 2012 primarily as a result of the Dynamic Acquisition having occurred in 2012 and, to a lesser extent, a reduction to the Company’s 2013 capital budget resulting from management’s and the Board’s review and analysis of the Company’s strategy, assets and spending levels.

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Cash Flows from Financing Activities

The Company’s financing activities used $1.3 billion of cash for the six-month period ended June 30, 2013 compared to providing $1.3 billion of cash in the same period in 2012. Cash used in financing activities during the 2013 period was primarily comprised of the redemption of $1.1 billion aggregate principal amount of the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018 as well as the premium paid of $62.0 million in connection with the redemption of these notes, $98.7 million in distributions to Royalty Trust unitholders, $28.5 million in purchases of treasury stock as a result of shares of restricted stock that were traded for taxes and $27.8 million in dividends paid on the Company’s convertible perpetual preferred stock.

Cash provided by financing activities during the six-month period ended June 30, 2012 was primarily comprised of $750.0 million from the issuance of the 8.125% Senior Notes, $587.1 million from the issuance of Mississippian Trust II common units, and $123.5 million of proceeds from the sale of Mississippian Trust I and Permian Trust common units. These proceeds were offset by $76.8 million in distributions to Royalty Trust unitholders, $45.3 million in cash paid to settle financing derivatives, $27.8 million in dividends paid on the Company’s 8.5%, 6.0% and 7.0% convertible perpetual preferred stock and $27.3 million in debt issuance costs.

Indebtedness

Long-term debt consists of the following at June 30, 2013 (in thousands):



8.75% Senior Notes due 2020, net of $5,575 discount	$	444,425
7.5% Senior Notes due 2021, including premium of $4,128	1,179,128
8.125% Senior Notes due 2022	750,000
7.5% Senior Notes due 2023, net of $3,893 discount	821,107
Total debt	$	3,194,660

The indentures governing the Senior Fixed Rate Notes referred to above contain covenants imposing certain restrictions on the Company’s activities, including, but not limited to, limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and during the three and six-month periods ended June 30, 2013, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Fixed Rate Notes.

Maturities of Long-Term Debt. As of June 30, 2013, there are no aggregate maturities of long-term debt, excluding discounts and premiums, until January 2020.

2013 Redemption of Senior Notes. In March 2013, the Company redeemed the outstanding $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and the outstanding $750.0 million aggregate principal amount of its 8.0% Senior Notes due 2018 for total consideration of $1,061.34 per $1,000 principal amount and $1,052.77 per $1,000 principal amount, respectively. The premium paid to redeem these notes and the associated unamortized debt issuance costs resulted in a loss on extinguishment of debt of $82.0 million for the six-month period ended June 30, 2013. The redemption was funded by a portion of the proceeds received from the sale of the Permian Properties. As a result of their redemption in March 2013, the Company was no longer obligated for future interest payments totaling $423.6 million on the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018.

Senior Credit Facility. The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. The Company’s borrowing base is generally redetermined in April and October of each year, and was reaffirmed at $775.0 million in March 2013. The next redetermination is scheduled to take place in October 2013. Quarterly, the Company pays a commitment fee assessed at an annual rate of 0.5% on any available portion of the senior credit facility. The borrowing base is determined based upon the discounted present value of future cash flows attributable to the Company’s proved reserves. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base.

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As of June 30, 2013, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded. As of and during the three and six-month periods ended June 30, 2013, the Company was in compliance with all applicable financial covenants under the senior credit facility.

At June 30, 2013, the Company had no amount outstanding under the senior credit facility and $28.6 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $746.4 million at June 30, 2013. The senior credit facility matures in March 2017.

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

Critical Accounting Policies and Estimates

For a description of the Company’s critical accounting policies and estimates, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2012 Form 10-K. For a discussion of recent accounting pronouncements, see Note 1 to the Company’s unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report.

Valuation Allowance

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

Management continues to closely monitor all available evidence, including both positive and negative, in considering whether to maintain a valuation allowance on its net deferred tax asset. Factors considered include, but are not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, the historical earnings of the Company and the prospects of future earnings. The Company's earnings have been trending upward leading to the Company having cumulative positive earnings for the 36-month period ended December 31, 2012. However, as a result of the sale of the Permian Properties on February 26, 2013, the Company has cumulative negative earnings for the 36-month periods ended March 31, 2013 and June 30, 2013. See “Note 2 - Acquisitions and Divestitures” to the unaudited condensed consolidated financial statements included in this Quarterly Report for discussion of the sale of the Permian Properties. Based on net book value, historical costs and proved reserves as of February 26, 2013, the Company recorded a loss on the sale of $399.1 million, which caused the Company to report a loss for the six-month period ended June 30, 2013. The resulting cumulative negative earnings are not a definitive factor in determining to maintain a valuation allowance as all available evidence should be considered, but it is a significant piece of negative evidence in management’s analysis. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.

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

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

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In determining to maintain the valuation allowance, management concluded that the objectively verifiable negative evidence of cumulative negative earnings for the 36-month period ended June 30, 2013 is difficult to overcome with any forms of positive evidence that may exist. Accordingly, management has not changed its judgment regarding the need for a full valuation allowance against its net deferred tax asset. The valuation allowance against the Company's net deferred tax asset at December 31, 2012 was $496.6 million.

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

Employee Compensation Plans

Annual Incentive Plan

In June 2013, the Compensation Committee of the Company’s Board approved an annual incentive plan effective June 2013 for all employees and discontinued the Company’s then existing cash bonus program with the final payments under the program made in July 2013. For certain members of management, the annual incentive plan incorporates objective performance criteria, individual performance goals and competitive target award levels for the 2013 performance year with payout percentages ranging from 0% to 200% of specified target levels based on actual performance. As of June 30, 2013, the Company had accrued approximately $11.0 million for the 2013 annual incentive for all employees, including an accrual for the annual incentive for specified members of management at 100% of the target values. As the payout for management is dependent on actual performance compared to established performance targets, the actual amount paid for 2013 performance under the annual incentive plan could differ significantly from the established target values.

Performance Units

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

General

This discussion provides information about the financial instruments the Company uses to manage commodity prices and interest rate volatility, including instruments used to manage commodity prices for production attributable to the Royalty Trusts. All contracts are settled in cash and do not require the actual delivery of a commodity at settlement.

Commodity Price Risk. The Company’s most significant market risk relates to the prices it receives for its oil and natural gas production. Due to the historical price volatility of these commodities, the Company periodically has entered into, and expects in the future to enter into, derivative arrangements for the purpose of reducing the variability of oil and natural gas prices the Company receives for its production. From time to time, the Company enters into commodity pricing derivative contracts for a portion of its anticipated production volumes depending upon management’s view of opportunities under the then-prevailing current market conditions. The Company’s senior credit facility limits its ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves.

The Company uses, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, collars and basis swaps. At June 30, 2013, the Company’s commodity derivative contracts consisted of fixed price swaps and collars, which are described below:



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

Collars	Two-way collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract.

The Company’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month or quarter of the contract period. The Company’s two-way and three-way oil collars are settled based upon the arithmetic average of NYMEX oil prices during the calculation period for the relevant contract. The Company’s natural gas fixed price swap transactions are settled based upon NYMEX prices. The Company’s natural gas collars are settled based upon the NYMEX prices on the penultimate commodity business day for the relevant contract. Settlement for oil derivative contracts occurs in the succeeding month or quarter and natural gas derivative contracts are settled in the production month or quarter.

At June 30, 2013, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps



	Notional (MBbls)	Weighted Average Fixed Price
July 2013 - December 2013	6,211	$	99.19
January 2014 - December 2014	7,511	$	92.42
January 2015 - December 2015	5,076	$	83.69

Natural Gas Price Swaps

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Oil Collars - Two-way

Oil Collars - Three-way



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

Natural Gas Collars



	Notional (MMcf)	Collar Range
July 2013 - December 2013	3,432	$3.78	—	$6.71
January 2014 - December 2014	937	$4.00	—	$7.78
January 2015 - December 2015	1,010	$4.00	—	$8.55

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

The following table summarizes the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts for the three and six-month periods ended June 30, 2013 and 2012 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Realized (gain) loss(1)	$	(17,717	)	$	(89,120	)	$	(1,632	)	$	36,336
Unrealized gain	(85,937		)	(580,730		)	(61,125		)	(451,540		)
Gain on commodity derivative contracts	$	(103,654	)	$	(669,850	)	$	(62,757	)	$	(415,204	)

____________________

(1)

The three-month periods ended June 30, 2013 and 2012 included $0.7 million and $57.3 million, respectively, of realized gains related to early settlements. The six-month periods ended June 30, 2013 and 2012 included $29.0 million and $(57.3) million, respectively, of realized losses (gains) related to early settlements. The six-month period ended June 30, 2012 also included $117.1 million of non-cash realized losses on derivative contracts amended in January 2012.

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

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

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A default by the Company under its senior credit facility constitutes a default under its derivative contracts with counterparties that are lenders under the senior credit facility. The Company does not require collateral or other security from counterparties to support derivative instruments. The Company has master netting agreements with all of its derivative contract counterparties, which allows the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the senior credit facility can be offset against amounts owed to such counterparty under the Company’s senior credit facility. As of June 30, 2013, the Company's open derivative contracts are with counterparties that share in the collateral supporting the Company's senior credit facility. As a result, the Company is not required to post additional collateral under derivative contracts. To secure their obligations under the derivative contracts novated by the Company, the Permian Trust and the Mississippian Trust II have each given the counterparties to such contracts a lien on their royalty interest. See “Note 3 - Variable Interest Entities” to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on the Permian Trust’s and the Mississippian Trust II’s derivative contracts.

The Company’s ability to fund its capital expenditure budget is partially dependent upon the availability of funds under its senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in the senior credit facility, the Company’s bank group currently consists of 23 financial institutions with commitments ranging from 1.00% to 6.00% of the borrowing base.

Interest Rate Risk. The Company is subject to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as its interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily the LIBOR and the federal funds rate. The Company had no outstanding variable rate debt as of June 30, 2013.

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

The following table summarizes the cash settlements and valuation gains and losses on the Company’s interest rate swap for the three and six-month periods ended June 30, 2013 and 2012 (in thousands):



	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013			2012
Realized loss	$	—	$	2,294		$	2,409		$	4,494
Unrealized gain	—		(2,245		)	(2,395		)	(3,599		)
Loss on interest rate swap	$	—	$	49		$	14		$	895

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ITEM 4. Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company performed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this Quarterly Report. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2013 to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

There was no change in the Company’s internal control over financial reporting during the quarter ended June 30, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. Other Information

ITEM 1. Legal Proceedings

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP filed suit against the Company and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas and CO₂ produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO₂ produced from the plaintiffs' acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek approximately $45.5 million in actual damages for the period of time between January 2004 and December 2011, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from the plaintiffs' acreage that results from treatment of natural gas at the Century Plant. The Commissioner of the General Land Office of the State of Texas (“GLO”) is named as an additional defendant in the lawsuit as some of the affected oil and natural gas leases described in the plaintiffs' allegations cover mineral classified lands in which the GLO is entitled to one-half of the royalties attributable to such leases. The GLO has filed a cross-claim against the SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands and seeking approximately $13.0 million in actual damages, inclusive of penalties and interest. On February 5, 2013, the Company received a favorable summary judgment ruling that effectively removes a majority of the plaintiffs' and GLO's claims. On April 29, 2013, the court entered an order allowing for an interlocutory appeal of its summary judgment ruling. The Company intends to continue to defend the remaining issues in this lawsuit as well as any appellate proceedings. At the time of the ruling on summary judgment, the lawsuit was still in the discovery stage and, accordingly, an estimate of reasonably possible losses associated with the remaining causes of action, if any, cannot be made until all of the facts, circumstances and legal theories relating to such claims and the Company's defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

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


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


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


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


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


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


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

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

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solicitation, (vi) a mandatory injunction requiring the defendants to disclose all material information related to the change-in-control provisions in the Company's indentures and senior credit facility; and (vii) an order requiring the Company's current directors to account to the plaintiff and the putative class for alleged damages. On March 8, 2013, the court granted plaintiff's motion for a preliminary injunction, enjoining the Board, unless and until it approved the TPG-Axon nominees for purposes of the change-in-control provisions of the Company's outstanding debt agreements, from (i) soliciting any further consent revocations in opposition to TPG-Axon's consent solicitation, (ii) relying upon or otherwise giving effect to any consent revocations received by the Company as of March 11, 2013, and (iii) impeding the dissident stockholder's consent solicitation in any way. On March 9, 2013, the Board approved TPG-Axon's nominees for purposes of the change-in-control provisions in the Company's debt instruments. On March 13, 2013, TPG-Axon and the Board entered into a settlement agreement under which TPG-Axon's consent solicitation was withdrawn. As a result of these actions, the Company believes that many of the original claims asserted by the plaintiff in the Kallick action have been rendered moot. The plaintiff has asked for the court’s permission to add additional claims, which request is currently pending. Until such time as claims are known, the Company is unable to estimate if any reasonably possible losses exist.

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

ITEM 1A. Risk Factors

The risk factor below updates the Company’s risk factors previously discussed in Item 1A—Risk Factors in the Company’s 2012 Form 10-K.

Unless the Company replaces its oil and natural gas reserves, its reserves and production will decline, which could adversely affect the Company's business, financial condition and results of operations.

In February 2013, the Company closed the sale of its Permian assets (other than those associated with the Permian Trust), which accounted for 21% of the Company's total production in the fourth quarter of 2012 and 35% of the Company's reserves at December 31, 2012. The Company's future oil and natural gas reserves and production, and therefore its cash flow and income, are highly dependent on its success in efficiently developing and exploiting its current reserves and economically finding or acquiring additional recoverable reserves. The Company may not be able to develop, find or acquire additional reserves to replace its current and future production at acceptable costs, which could adversely affect its business, financial condition and results of operations.

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

As part of the Company’s restricted stock program, the Company makes required tax payments on behalf of employees when their stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The shares withheld are initially recorded as treasury shares, then immediately retired. During the quarter ended June 30, 2013, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1, 2013 — April 30, 2013	56,989	$	4.97	N/A	N/A
May 1, 2013 — May 31, 2013	269,775	$	5.10	N/A	N/A
June 1, 2013 — June 30, 2013	3,001,961	$	4.77	N/A	N/A

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

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SIGNATURE

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



	SandRidge Energy, Inc.

	By:	/s/ EDDIE M. LEBLANC
		Eddie M. LeBlanc Executive Vice President and Chief Financial Officer

Date: August 7, 2013

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EXHIBIT INDEX



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
3.1	Certificate of Incorporation of SandRidge Energy, Inc.	S-1	333-148956	3.1	1/30/2008
3.2	Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated July 16, 2010	10-Q	001-33784	3.2	8/9/2010
3.3	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	3/9/2009
10.1	Separation Agreement, dated April 26, 2013 between SandRidge Energy, Inc. and Todd N. Tipton	8-K	001-33784	10.1	4/26/2013
10.2	Separation Agreement, dated April 26, 2013 between SandRidge Energy, Inc. and Rodney E. Johnson	8-K	001-33784	10.2	4/26/2013
10.3	Amendment to the SandRidge Energy, Inc. 2009 Incentive Plan					*
31.1	Section 302 Certification—Chief Executive Officer					*
31.2	Section 302 Certification—Chief Financial Officer					*
32.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer					*
101.INS	XBRL Instance Document					*
101.SCH	XBRL Taxonomy Extension Schema Document					*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					*
101.DEF	XBRL Taxonomy Extension Definition Document					*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					*