SandRidge Energy (SD) 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 21, 2014	Jun. 28, 2013
Document Information [Line Items]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'SD	'	'
Entity Registrant Name	'SANDRIDGE ENERGY INC	'	'
Entity Central Index Key	'0001349436	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	495,085,274	'
Entity Public Float	'	'	$2,300,000

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'		'
Cash and cash equivalents	$814,663		$309,766
Accounts receivable, net	349,218		445,506
Derivative contracts	12,779		71,022
Costs in excess of billings and contract loss	4,079		11,229
Prepaid expenses	39,253		31,319
Restricted deposit	0		255,000
Other current assets	21,831		19,043
Total current assets	1,241,823		1,142,885
Oil and natural gas properties, using full cost method of accounting	'		'
Proved (includes development and project costs excluded from amortization of $45.6 million and $72.4 million at December 31, 2013 and 2012, respectively)	10,972,816	[1]	12,262,921	[1]
Unproved	531,606		865,863
Less: accumulated depreciation, depletion and impairment	-5,762,969		-5,231,182
Net oil and natural gas properties capitalized costs	5,741,453		7,897,602
Other property, plant and equipment, net	566,222		582,375
Derivative contracts	14,126		23,617
Other assets	121,171		144,252
Total assets	7,684,795		9,790,731
Current liabilities	'		'
Accounts payable and accrued expenses	812,488		766,544
Billings and contract loss in excess of costs incurred	0		15,546
Derivative contracts	34,267		14,860
Asset retirement obligations	87,063		118,504
Deposit on pending sale	0		255,000
Total current liabilities	933,818		1,170,454
Long-term debt	3,194,907		4,301,083
Derivative contracts	20,564		59,787
Asset retirement obligations	337,054		379,906
Other long-term obligations	22,825		17,046
Total liabilities	4,509,168		5,928,276
Commitments and contingencies (Note 15)	'		'
Preferred stock, $0.001 par value, 50,000 shares authorized	'		'
Common stock, $0.001 par value, 800,000 shares authorized; 491,609 issued and 490,290 outstanding at December 31, 2013 and 491,578 issued and 490,359 outstanding at December 31, 2012	483		476
Additional paid-in capital	5,298,301		5,233,019
Additional paid-in capital—stockholder receivable	-3,750		-5,000
Treasury stock, at cost	-8,770		-8,602
Accumulated deficit	-3,460,462		-2,851,048
Total SandRidge Energy, Inc. stockholders’ equity	1,825,810		2,368,853
Noncontrolling interest	1,349,817		1,493,602
Total equity	3,175,627		3,862,455
Total liabilities and equity	7,684,795		9,790,731
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2013 and 2012; aggregate liquidation preference of $265,000	'		'
Preferred stock, $0.001 par value, 50,000 shares authorized	'		'
Preferred stock	3		3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at December 31, 2013 and 2012; aggregate liquidation preference of $200,000	'		'
Preferred stock, $0.001 par value, 50,000 shares authorized	'		'
Preferred stock	2		2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at December 31, 2013 and 2012; aggregate liquidation preference of $300,000	'		'
Preferred stock, $0.001 par value, 50,000 shares authorized	'		'
Preferred stock	$3		$3
[1]	Includes cumulative capitalized interest of approximately $23.4 million and $11.7 million at December 31, 2013 and 2012, respectively.

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Share data in Thousands, except Per Share data, unless otherwise specified
Production costs, cumulative	$45,600,000	$72,400,000
Preferred stock, par value (in dollars per share)	$0.00	$0.00
Preferred stock, shares authorized (in shares)	50,000	50,000
Preferred stock, shares outstanding (in shares)	7,650	7,650
Common stock, par value (in dollars per share)	$0.00	$0.00
Common stock, shares authorized (in shares)	800,000	800,000
Common stock, issued (in shares)	491,609	491,578
Common stock, outstanding (in shares)	490,290	490,359
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2013 and 2012; aggregate liquidation preference of $265,000	'	'
Preferred stock, shares issued (in shares)	2,650	2,650
Preferred stock, shares outstanding (in shares)	2,650	2,650
Preferred stock, aggregate liquidation preference	265,000,000	265,000,000
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at December 31, 2013 and 2012; aggregate liquidation preference of $200,000	'	'
Preferred stock, shares issued (in shares)	2,000	2,000
Preferred stock, shares outstanding (in shares)	2,000	2,000
Preferred stock, aggregate liquidation preference	200,000,000	200,000,000
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at December 31, 2013 and 2012; aggregate liquidation preference of $300,000	'	'
Preferred stock, shares issued (in shares)	3,000	3,000
Preferred stock, shares outstanding (in shares)	3,000	3,000
Preferred stock, aggregate liquidation preference	$300,000,000	$300,000,000

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	'	'	'
Oil, natural gas and NGL	$1,820,278	$1,759,282	$1,226,794
Drilling and services	66,586	116,633	103,298
Midstream and marketing	58,304	40,486	66,690
Construction contract	23,349	796,323	0
Other	14,871	18,241	18,431
Total revenues	1,983,388	2,730,965	1,415,213
Expenses	'	'	'
Production	516,427	477,154	322,877
Production taxes	32,292	47,210	46,069
Cost of sales	57,118	68,227	65,654
Midstream and marketing	53,644	39,669	66,007
Construction contract	23,349	796,323	0
Depreciation and depletion—oil and natural gas	567,732	568,029	317,246
Depreciation and amortization—other	62,136	60,805	53,630
Accretion of asset retirement obligations	36,777	28,996	9,368
Impairment	26,280	316,004	2,825
General and administrative	207,920	241,682	148,643
Employee termination benefits	122,505	0	0
Loss (gain) on derivative contracts	47,123	-241,419	-44,075
Loss (gain) on sale of assets	399,086	3,089	-2,044
Total expenses	2,152,389	2,405,769	986,200
(Loss) income from operations	-169,001	325,196	429,013
Other income (expense)	'	'	'
Interest expense	-270,234	-303,349	-237,332
Bargain purchase gain	0	122,696	0
Loss on extinguishment of debt	-82,005	-3,075	-38,232
Other income, net	12,445	4,741	3,122
Total other expense	-339,794	-178,987	-272,442
(Loss) income before income taxes	-508,795	146,209	156,571
Income tax expense (benefit)	5,684	-100,362	-5,817
Net (loss) income	-514,479	246,571	162,388
Less: net income attributable to noncontrolling interest	39,410	105,000	54,323
Net (loss) income attributable to SandRidge Energy, Inc.	-553,889	141,571	108,065
Preferred stock dividends	55,525	55,525	55,583
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	($609,414)	$86,046	$52,482
(Loss) earnings per share	'	'	'
Basic (in dollars)	($1.27)	$0.19	$0.13
Diluted (in dollars)	($1.27)	$0.19	$0.13
Weighted average number of common shares outstanding	'	'	'
Basic (in shares)	481,148	453,595	398,851
Diluted (in shares)	481,148	456,015	406,645

CONSOLIDATED_STATEMENTS_OF_CHA

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $)	Total	Convertible Perpetual Preferred Stock	Common Stock	Additional Paid-In Capital	Treasury Stock	Accumulated Deficit	Noncontrolling Interest
In Thousands
Beginning Balance at Dec. 31, 2010	$1,547,483	$8	$398	$4,528,912	($3,547)	($2,989,576)	$11,288
Beginning Balance (in shares) at Dec. 31, 2010	'	'	406,360	'	'	'	'
Beginning Balance (in shares) at Dec. 31, 2010	'	7,650	'	'	'	'	'
Issuance of units by royalty trusts	917,528	'	'	'	'	'	917,528
Distributions to noncontrolling interest owners	-60,200	'	'	'	'	'	-60,200
Issuance of convertible perpetual preferred stock, net (in shares)	'	0	'	'	'	'	'
Issuance of convertible perpetual preferred stock, net	'	0	'	'	'	'	'
Issuance of convertible perpetual preferred stock, net	-231	'	'	-231	'	'	'
Issuance of common stock in acquisition	0	'	'	'	'	'	'
Purchase of treasury stock	-10,834	'	'	'	-10,834	'	'
Retirement of treasury stock	0	'	'	-10,834	10,834	'	'
Stock purchase - retirement plans, net of distributions (in shares)	'	'	-405	'	'	'	'
Stock purchase—retirement plans, net of distributions	568	'	'	3,179	-2,611	'	'
Stock-based compensation	47,778	'	'	47,778	'	'	'
Stock-based compensation excess tax benefit	53	'	'	53	'	'	'
Issuance of restricted stock awards, net of cancellations (in shares)	'	'	5,998	'	'	'	'
Issuance of restricted stock awards, net of cancellations	0	'	1	-1	'	'	'
Net (loss) income	162,388	'	'	'	'	108,065	54,323
Convertible perpetual preferred stock dividends	-55,583	'	'	'	'	-55,583	'
Ending Balance at Dec. 31, 2011	2,548,950	8	399	4,568,856	-6,158	-2,937,094	922,939
Ending Balance (in shares) at Dec. 31, 2011	'	7,650	'	'	'	'	'
Ending Balance (in shares) at Dec. 31, 2011	'	'	411,953	'	'	'	'
Issuance of units by royalty trusts	587,086	'	'	'	'	'	587,086
Sale of royalty trust units	139,360	'	'	79,056	'	'	60,304
Distributions to noncontrolling interest owners	-181,727	'	'	'	'	'	-181,727
Issuance of common stock in acquisition (in shares)	'	'	73,962	'	'	'	'
Issuance of common stock in acquisition	542,138	'	74	542,064	'	'	'
Purchase of treasury stock	-11,312	'	'	'	-11,312	'	'
Retirement of treasury stock	0	'	'	-11,312	11,312	'	'
Stock purchase - retirement plans, net of distributions (in shares)	'	'	-345	'	'	'	'
Stock purchase—retirement plans, net of distributions	-298	'	'	2,146	-2,444	'	'
Stock-based compensation	47,228	'	'	47,228	'	'	'
Stock-based compensation excess tax benefit	-16	'	'	-16	'	'	'
Issuance of restricted stock awards, net of cancellations (in shares)	'	'	4,789	'	'	'	'
Issuance of restricted stock awards, net of cancellations	0	'	3	-3	'	'	'
Net (loss) income	246,571	'	'	'	'	141,571	105,000
Convertible perpetual preferred stock dividends	-55,525	'	'	'	'	-55,525	'
Ending Balance at Dec. 31, 2012	3,862,455	8	476	5,228,019	-8,602	-2,851,048	1,493,602
Ending Balance (in shares) at Dec. 31, 2012	7,650	7,650	'	'	'	'	'
Ending Balance (in shares) at Dec. 31, 2012	490,359	'	490,359	'	'	'	'
Sale of royalty trust units	28,985	'	'	7,289	'	'	21,696
Distributions to noncontrolling interest owners	-206,470	'	'	'	'	'	-206,470
Contributions from noncontrolling interest owners	1,579	'	'	'	'	'	1,579
Issuance of common stock in acquisition	0	'	'	'	'	'	'
Purchase of treasury stock	-30,126	'	'	'	-30,126	'	'
Retirement of treasury stock	0	'	'	-30,126	30,126	'	'
Stock purchase - retirement plans, net of distributions (in shares)	'	'	-99	'	'	'	'
Stock purchase—retirement plans, net of distributions	-435	'	'	-267	-168	'	'
Stock-based compensation	88,397	'	'	88,397	'	'	'
Stock-based compensation excess tax benefit	-4	'	'	-4	'	'	'
Payment received on shareholder receivable	1,250	'	'	1,250	'	'	'
Issuance of restricted stock awards, net of cancellations (in shares)	'	'	30	'	'	'	'
Issuance of restricted stock awards, net of cancellations	0	'	7	-7	'	'	'
Net (loss) income	-514,479	'	'	'	'	-553,889	39,410
Convertible perpetual preferred stock dividends	-55,525	'	'	'	'	-55,525	'
Ending Balance at Dec. 31, 2013	$3,175,627	$8	$483	$5,294,551	($8,770)	($3,460,462)	$1,349,817
Ending Balance (in shares) at Dec. 31, 2013	7,650	7,650	'	'	'	'	'
Ending Balance (in shares) at Dec. 31, 2013	490,290	'	490,290	'	'	'	'

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net (loss) income	($514,479)	$246,571	$162,388
Adjustments to reconcile net (loss) income to net cash provided by operating activities	'	'	'
Depreciation, depletion and amortization	629,868	628,834	370,876
Accretion of asset retirement obligations	36,777	28,996	9,368
Impairment	26,280	316,004	2,825
Debt issuance costs amortization	10,091	14,388	11,372
Amortization of discount, net of premium, on long-term debt	1,036	2,592	2,383
Bargain purchase gain	0	-122,696	0
Loss on extinguishment of debt	82,005	3,075	38,232
Deferred income tax provision (benefit)	3,842	-100,288	-6,986
Loss (gain) on derivative contracts	47,123	-241,419	-44,075
Cash (paid) received on settlement of derivative contracts	-5,879	125,932	-53,536
Loss (gain) on sale of assets	399,086	3,089	-2,044
Stock-based compensation	85,270	42,795	38,684
Other	3,929	1,387	5,834
Changes in operating assets and liabilities increasing (decreasing) cash	'	'	'
Receivables	90,048	-141,534	-61,645
Costs in excess of billings and contract loss, net	-8,396	-89,003	-11,013
Prepaid expenses	-7,934	-5,952	-4,359
Other current assets	810	-1,586	1,432
Other assets and liabilities, net	5,777	34,447	-35,773
Accounts payable and accrued expenses	116,999	121,889	51,522
Asset retirement obligations	-133,623	-84,361	-16,531
Net cash provided by operating activities	868,630	783,160	458,954
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Capital expenditures for property, plant and equipment	-1,496,731	-2,146,372	-1,727,106
Acquisitions of assets	-17,028	-840,740	-34,628
Proceeds from sale of assets	2,584,115	431,167	859,405
Net cash provided by (used in) investing activities	1,070,356	-2,555,945	-902,329
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from borrowings	0	1,850,344	2,033,000
Repayments of borrowings	-1,115,500	-366,029	-2,130,293
Premium on debt redemption	-61,997	-844	-30,338
Debt issuance costs	-91	-48,538	-20,326
Proceeds from issuance of royalty trust units	0	587,086	917,528
Proceeds from the sale of royalty trust units	28,985	139,360	0
Noncontrolling interest distributions	-206,470	-181,727	-60,200
Noncontrolling interest contributions	1,579	0	0
Proceeds from issuance of convertible perpetual preferred stock, net	0	0	-231
Stock-based compensation excess tax benefit	-4	-16	53
Purchase of treasury stock	-32,976	-14,723	-13,796
Dividends paid—preferred	-55,525	-55,525	-56,742
Cash received on shareholder receivable	1,250	0	0
Cash received (paid) on settlement of financing derivative contracts	6,660	-34,518	6,538
Net cash (used in) provided by financing activities	-1,434,089	1,874,870	645,193
CASH AND CASH EQUIVALENTS, beginning of year	309,766	207,681	5,863
NET INCREASE IN CASH AND CASH EQUIVALENTS	504,897	102,085	201,818
CASH AND CASH EQUIVALENTS, end of year	$814,663	$309,766	$207,681

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on exploration and production activities in the Mid-Continent region of the United States. The Company owns and operates additional interests in west Texas and owned interests in the Gulf of Mexico and Gulf Coast until February 2014, as discussed in Note 21. The Company also operates businesses and infrastructure systems that are complementary to its primary exploration and production activities, including gas gathering and processing facilities, marketing operations, a saltwater disposal system, an electrical transmission system and a drilling rig and related oil field services 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. Noncontrolling interest represents third-party ownership interests in the Company’s subsidiaries and consolidated VIEs and is included as a component of equity in the consolidated balance sheet and consolidated statement of changes in equity. All significant intercompany accounts and transactions have been eliminated in consolidation.
	Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. 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. In addition to the VIEs that the Company consolidates, the Company also holds a variable interest in another VIE that is not consolidated as it was determined that the Company is not the primary beneficiary. The Company monitors both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 4 for discussion of the Company’s significant associated VIEs.
	Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.
	Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“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, natural gas and NGL 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.
	Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.
	Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the exploration, production and treating services for oil and natural gas. An allowance for doubtful accounts has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts.
	Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements.
	Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5.
	Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates.
	The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statement of cash flows. See Note 13 for further discussion of the Company’s derivatives.
	Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized internal costs of $74.7 million, $61.3 million and $37.1 million to the full cost pool in 2013, 2012 and 2011, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
	Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.
	Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down is not reversible at a later date.
	The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.
	Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.
	Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 10 to 39 years for buildings and 3 to 30 years for equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statement of operations.
	Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If any asset or asset group is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. See Note 8 for further discussion of impairments.
	Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. During 2013, 2012 and 2011, interest of approximately $11.7 million, $10.1 million and $1.0 million, respectively, was capitalized on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. Additionally, interest of $4.9 million, $4.7 million and $2.0 million was capitalized in 2013, 2012 and 2011, respectively, on midstream and corporate assets which were under construction.
	Debt Issuance Costs. The Company amortizes debt issuance costs related to its long-term debt as interest expense over the scheduled maturity period of the related debt. The Company includes unamortized debt issuance costs in other assets in the consolidated balance sheet. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.
	Restricted Deposits. Restricted deposits represent bank trust and escrow accounts required by the Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, surety bond underwriters, purchase agreements or other settlement agreements to satisfy the Company’s eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. Such restricted deposits are included in other assets in the accompanying consolidated balance sheets.
	Restricted deposits may also include escrow deposits received on pending sales of oil and natural gas properties. Amounts are considered restricted until the transaction closes. In December 2012, the Company entered into an agreement to sell all of its oil and natural gas properties in the Permian Basin in west Texas, excluding the assets attributable to SandRidge Permian Trust’s (the “Permian Trust”) area of mutual interest (the “Permian Properties”), and received a $255.0 million deposit. At December 31, 2012, this deposit was included in current assets and current liabilities in the accompanying consolidated balance sheets as the sale did not close until February 2013. See Note 3 for further discussion of the sale of the Permian Properties.
	Goodwill. In conjunction with its acquisition of Arena Resources, Inc. (“Arena”) in 2010, the Company recorded goodwill equal to the excess of the consideration paid over the fair value of identifiable net assets acquired. Goodwill was assigned to the Company’s exploration and production segment and was not deductible for income tax purposes.
	Entry by the Company in December 2012 into an agreement to sell the Permian Properties was determined to be a triggering event. As such, an impairment test was performed as of December 31, 2012, resulting in the full impairment of goodwill. See Note 8 for further discussion of the goodwill impairment test performed.
	Investments. Investments in marketable equity securities have been designated as available for sale and measured at fair value pursuant to the fair value option which requires unrealized gains and losses be reported in earnings.
	Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statement of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 14 for further discussion of the Company’s asset retirement obligations.
	In certain instances, the Company is required to maintain deposits to escrow accounts for future plugging and abandonment obligations. See Restricted Deposits discussed above.
	Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statement of operations.
	The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $2.6 million and $3.6 million at December 31, 2013 and 2012, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheet.
	The Company accounted for its two construction contracts, discussed in Note 11, using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract losses are recorded at the time it is determined that a loss will be incurred. The contract loss on the Century Plant construction contract was recorded as a development cost within the Company’s full cost pool. Contract gains, if any, are recorded upon substantial completion of the construction project.
	The Company recognizes revenues and expenses generated from daywork and footage drilling contracts as the services are performed as the Company does not bear the risk of completion of the well. The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another are recognized at the time mobilization services are performed.
	In general, natural gas purchased and sold by the midstream business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Midstream services revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determined and collectability is reasonably assured. Revenues from third-party midstream services are presented on a gross basis, since the Company acts as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold.
	Stock-Based Compensation. The Company grants restricted stock awards to members of its Board of Directors (the “Board”) and its employees. Such awards and the related stock-based compensation cost are measured based on the calculated fair value of the award on the grant date. The expense, net of estimated forfeitures, is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award. To the extent stock-based compensation cost relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statement of operations. The related excess tax benefit received upon vesting of restricted stock, if any, is reflected in the consolidated statement of cash flows as a financing activity. The related excess tax expense due upon vesting of restricted stock, if any, is reflected in the consolidated statement of cash flows as an operating activity.
	Performance Unit Compensation. The Company awards performance units, which contain a market-based performance component and will be settled in cash upon vesting, to certain members of senior management. The Company recognizes a liability and expense for performance unit compensation for the portion earned over the requisite service period in an amount equal to the fair value of the performance units granted. Changes in the fair value of the units for which service has been met are recognized as compensation expense with a corresponding adjustment to the liability. To the extent performance unit compensation cost relates to those directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statement of operations.
	Advertising Costs. The Company expenses advertising costs as incurred. Advertising and promotional costs were $5.1 million, $11.8 million, and $4.8 million, respectively, during the years ended December 31, 2013, 2012 and 2011.
	Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.
	The Company has elected an accounting policy in which interest and penalties on income taxes are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.
	Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculation consist of unvested restricted stock awards, using the treasury method, and convertible preferred stock. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 19 for the Company’s earnings per share calculation.
	Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 15 for discussion of the Company’s commitments and contingencies.
	Concentration of Risk. All of the Company’s derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market 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 derivative transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its derivative counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty.
	A default by the Company under its senior secured revolving credit facility (the “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 counterparties, which allow 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 derivative contracts. 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, if any, to such counterparty under the Company’s senior credit facility.
	The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.
	The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. See Note 22 for information regarding the Company’s major customers. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect the Company’s ability to sell the oil, natural gas and NGLs it produces.
	Recently Adopted Accounting Pronouncements. In December 2011, the Financial Accounting Standards Board 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 13 for the Company’s derivative disclosures.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Supplemental Cash Flow Information	'
	Supplemental Cash Flow Information
	Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Years Ended December 31,
		2013			2012			2011
		(In thousands)
	Supplemental Disclosure of Cash Flow Information
	Cash paid for interest, net of amounts capitalized	$	(274,850	)	$	(257,152	)	$	(224,127	)
	Cash paid for income taxes	(4,610		)	(1,324		)	(2,083		)
	Supplemental Disclosure of Noncash Investing and Financing Activities
	Deposit on pending sale	$	(255,000	)	$	255,000		$	—
	Change in accrued capital expenditures	72,848			(27,610		)	(89,388		)
	Adjustment to oil and natural gas properties for contract loss	—			50,000			25,000
	Asset retirement costs capitalized	5,078			7,479			5,716
	Common stock issued in connection with acquisition	—			542,138			—

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2013
Acquisitions and Divestitures [Abstract]	'
Acquisitions and Divestitures	'
	Acquisitions and Divestitures
	2011 Divestitures
	The Company completed the following divestitures in 2011, all of which were accounted for as adjustments to the full cost pool with no gain or loss recognized:
	•	In July 2011, the Company sold its Wolfberry assets in the Permian Basin for $151.6 million, net of fees and post-closing adjustments.
	•	In August 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for $199.0 million, net of fees and post-closing adjustments.
	•	In November 2011, the Company sold its east Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $225.4 million, net of fees and post-closing adjustments.
	2012 Acquisitions and Divestitures
	Dynamic Acquisition. The Company acquired 100% of the equity interests of Dynamic Offshore Resources, LLC (“Dynamic”) 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”). The Dynamic Acquisition expanded the Company’s presence in the Gulf of Mexico, adding oil, natural gas and NGL reserves and production to its existing asset base in this area.
	In the second quarter of 2013, the Company completed its valuation of the Dynamic Acquisition with no adjustments in 2013 to the valuation of assets acquired and liabilities assumed, which are included in the following table (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 long-term 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.
	-7	The bargain purchase gain resulted 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, natural gas and NGL 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 5.
	The following unaudited pro forma combined results of operations for the years ended December 31, 2012 and 2011 are presented as though the Dynamic Acquisition had been completed as of January 1, 2011. The pro forma combined results of operations for the years ended December 31, 2012 and 2011 have been prepared by adjusting the historical results of the Company to include the historical results of Dynamic, certain reclassifications to conform Dynamic’s presentation and accounting policies to the Company’s and to exclude the bargain purchase gain, the partial valuation allowance release and certain acquisition costs. The supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented. The pro forma results of operations do not include any cost savings or other synergies that resulted from the Dynamic Acquisition or any estimated costs incurred to integrate Dynamic.
		Year Ended December 31,
		2012(1)				2011(2)
		(In thousands, except per share data)
		(Unaudited)
	Revenues	$	2,908,899			$	1,932,945
	Net income	$	39,563			$	509,644
	(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(120,962	)		$	399,278
	(Loss) earnings per common share
	Basic	$	(0.25	)		$	0.84
	Diluted	$	(0.25	)		$	0.8
	____________________
	-1	Pro forma net income, loss applicable to SandRidge Energy, Inc. common stockholders and loss per common share exclude a $122.7 million bargain purchase gain, a $100.3 million partial valuation allowance release included in income tax benefit, $10.9 million of fees incurred to secure financing for the Dynamic Acquisition included in interest expense and $13.0 million of transaction costs incurred and included in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2012.
	-2	Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and earnings per common share include a $122.7 million bargain purchase gain, a $100.3 million partial valuation allowance release, $10.9 million of fees incurred to secure financing and $13.0 million of transaction costs.
	Revenues of $365.0 million and income from operations of $81.5 million associated with Dynamic have been included in the accompanying consolidated statement of operations for the year ended December 31, 2012. Additionally, the Company incurred $13.0 million in acquisition-related costs for the Dynamic Acquisition, which have been included in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2012.
	Sale of Tertiary Recovery Properties. In June 2012, the Company sold its tertiary recovery properties located in the Permian Basin area of west Texas for approximately $130.8 million, net of post-closing adjustments. The sale of the acreage and working interests in wells was accounted for as an adjustment to the full cost pool with no gain or loss recognized.
	Acquisition of Gulf of Mexico Properties. In June 2012, the Company acquired oil and natural gas properties in the Gulf of Mexico (the “Gulf of Mexico Properties”) 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, natural gas and NGL reserves and production to its existing asset base in this area.
	This acquisition qualified as a business combination for accounting purposes and, as such, the Company estimated the fair value of the acquired properties as of June 20, 2012, which was the date on which the Company obtained control of the properties. The fair value was estimated using a discounted cash flow model based upon market assumptions of future commodity prices, projections of estimated quantities of oil, natural gas and NGL 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 5.
	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 obligations	(55,443		)
Total identifiable net assets	$	43,282
The following unaudited pro forma combined results of operations for the years ended December 31, 2012 and 2011 are presented as though the Company acquired the Gulf of Mexico Properties as of January 1, 2011. The pro forma combined results of operations for the years ended December 31, 2012 and 2011 have been prepared by adjusting the historical results of the Company to include the historical results of the acquired properties and estimates of the effect of the transaction on the combined results. The 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.
	Year Ended December 31,
	2012				2011
	(In thousands, except per share data)
	(Unaudited)
Revenues	$	2,759,381			$	1,502,325
Net income	$	247,035			$	191,073
Income available to SandRidge Energy, Inc. common stockholders	$	86,510			$	81,167
Earnings per common share
Basic	$	0.19			$	0.2
Diluted	$	0.19			$	0.2
Revenues of $26.2 million and earnings of $19.1 million generated by the acquired properties have been included in the accompanying consolidated statement of operations for the year ended December 31, 2012. Acquisition-related costs of $0.2 million have been expensed as incurred in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2012.
2013 Divestiture
Sale of Permian Properties. On February 26, 2013, the Company sold the Permian Properties for $2.6 billion, including certain post-closing adjustments that were 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 $398.9 million loss on the sale. The loss, including the impact of the final post-closing adjustments, is included in loss (gain) on sale of assets in the accompanying consolidated statement of operations for the year ended December 31, 2013. The loss was calculated based on a comparison of proceeds received and the asset retirement obligations attributable to the Permian Properties that were 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 these 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. A portion of the loss totaling $71.7 million was allocated to noncontrolling interests and is reflected in net income attributable to noncontrolling interest in the accompanying consolidated statement of operations for the year ended December 31, 2013.
The following table presents revenues and direct operating expenses of the Permian Properties included in the accompanying consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011 (in thousands):
		Year Ended December 31,
		2013(1)				2012				2011
Revenues		$	68,027			$	566,075			$	614,666
Direct operating expenses		$	17,453			$	130,337			$	144,066
____________________
-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 December 31, 2013 were as follows:
Partner		Closing Date		Total Drilling Carry				Drilling Carry Recorded				Drilling Carry Remaining
				(In thousands)
Atinum MidCon I, LLC		September 2011		$	250,000			$	250,000			$	—
Repsol E&P USA, Inc.		Jan-12		750,000				544,400				205,600
				$	1,000,000			$	794,400			$	205,600
During the years ended December 31, 2013 and 2012, the Company recorded approximately $408.0 million and $367.6 million, respectively, for Atinum MidCon I, LLC and Repsol E&P USA, Inc.’s drilling carries, which offset the Company’s capital expenditures for the respective period. As of December 31, 2013, Atinum MidCon I, LLC had fully funded its drilling carry commitment. Under the agreement with Repsol E&P USA, Inc., the remaining drilling carry commitment may be reduced if a certain number of wells are not drilled within the area of mutual interest during a 12-month period. However, the Company expects Repsol E&P USA, Inc. to fully fund its drilling carry commitment during 2014.

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Variable Interest Entities	'
	Variable Interest Entities
	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 represent 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. During 2013, the partners each contributed approximately $1.6 million to GRLP for legal expenses incurred for the settlement of insurance claims related to fires at the Plant in 2008.
	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 December 31, 2013 and 2012, $0.7 million and $1.1 million, respectively, of noncontrolling interest in the accompanying consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying consolidated balance sheets at December 31, 2013 and 2012 consisted of the following (in thousands):
		December 31,
		2013				2012
	Cash and cash equivalents	$	132			$	1,080
	Accounts receivable, net	16				20
	Prepaid expenses	32				64
	Other current assets	109				109
	Total current assets	289				1,273
	Other property, plant and equipment, net	1,163				1,246
	Total assets	$	1,452			$	2,519
	Accounts payable and accrued expenses	$	129			$	274
	Total liabilities	$	129			$	274
	Grey Ranch Plant Genpar, LLC. The Company owns a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP. Additionally, the Company serves as Genpar’s administrative manager. Genpar’s ownership interest in GRLP is its only asset. As managing partner of GRLP, Genpar has the sole right to manage, control and conduct the business of GRLP. However, Genpar is restricted from making certain major decisions, including the decision to remove the Company as operator of the Plant. The rights afforded the Company under the Plant operating agreement and the restrictions on Genpar limit Genpar’s ability to make decisions on behalf of GRLP. Therefore, Genpar is considered a VIE. Although both the Company and Genpar’s other equity owner share equally in Genpar’s economic losses and benefits and also have agreements that may be considered variable interests, the Company determined it was the primary beneficiary of Genpar due to (i) its ability, as administrative manager and operator of the Plant, to direct the activities of Genpar that most significantly impact its economic performance and (ii) its obligation or right, as operator of the Plant, to absorb the losses of or receive benefits from Genpar that could potentially be significant to Genpar. As the primary beneficiary, the Company consolidates Genpar’s activity. However, its sole asset, the investment in GRLP, is eliminated in consolidation. Genpar has no liabilities.
	Royalty Trusts. SandRidge owns beneficial interests in three Delaware statutory trusts. SandRidge Mississippian Trust I (the “Mississippian Trust I”), the Permian Trust and SandRidge Mississippian Trust II (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 thousands)		$	336,893			$	580,635			$	587,087
	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)		12/31/30				3/31/31				12/31/31
	____________________
	-1	Subsequent to the initial public offerings, the Company sold common units of the Royalty Trusts 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 the 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 years ended December 31, 2013, 2012 and 2011 as follows (in thousands):
			Year Ended December 31,
			2013(1)				2012(2)				2011(2)
	Total distributions		$	299,674			$	274,979			$	91,162
	Distributions to third-party unitholders		$	206,470			$	181,727			$	57,449
	____________________
	-1	Subordination thresholds were not met for the Mississippian Trust I’s second and third quarter 2013 distributions or for the Permian Trust’s second quarter 2013 distribution, resulting in reduced distributions to the Company on its subordinated units for these periods.
	-2	The Company received incentive distributions from the Mississippian Trust I during the first and second quarters of 2012 and the third quarter of 2011.
	See Note 21 for discussion of the Royalty Trusts’ distributions announced in January 2014.
	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 December 31, 2013 or 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 December 31, 2013, the total maximum amount recoverable by the Permian Trust and Mississippian Trust II under the liens was approximately $124.6 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 December 31, 2013 underlying the derivatives agreements. The combined volume in the tables below reflects the total volume of the Royalty Trusts’ open oil and natural gas commodity derivative contracts.
	Oil Price Swaps Underlying the Royalty Trust Derivatives Agreements
		Notional (MBbls)			Weighted Average
					Fixed Price
	January 2014 — December 2014	1,862			$	100.7
	January 2015 — December 2015	630			$	101.03
	Natural Gas Collars Underlying the Royalty Trust Derivatives Agreements
		Notional (MMcf)			Collar Range
	January 2014 — December 2014	937			$	4		—	$	7.78
	January 2015 — December 2015	1,010			$	4		—	$	8.55
	Oil Price Swaps Underlying the Derivatives Agreements and Novated to the Royalty Trusts
		Notional (MBbls)			Weighted Average
					Fixed Price
	January 2014 — December 2014	991			$	100.79
	January 2015 — March 2015	141			$	100.9
	See Note 13 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 at the end of the subordination period. After this conversion, the Company will continue to consolidate the activities of the Mississippian Trust I as its primary beneficiary due to the Company’s continued (a) power to direct the activities that most significantly impact the economic performance of the Royalty Trust and (b) obligation to absorb losses and right to receive residual returns through its variable interests in the Royalty Trust, including ownership of common units, that could potentially be significant to the Mississippian Trust I.
	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 December 31, 2013 and 2012, $1.3 billion and $1.5 billion, respectively, of noncontrolling interest in the accompanying 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 consolidated balance sheets at December 31, 2013 and 2012 consisted of the following (in thousands):
		December 31,
		2013				2012
	Cash and cash equivalents(1)	$	7,912			$	7,445
	Accounts receivable	22,540				28,596
	Derivative contracts	4,983				10,286
Total current assets	35,435				46,327
Investment in royalty interests(2)	1,325,942				1,325,942
Less: accumulated depletion	(186,095		)		(103,746		)
	1,139,847				1,222,196
Derivative contracts	1,476				7,660
Total assets	$	1,176,758			$	1,276,183
Accounts payable and accrued expenses	$	3,393			$	1,101
Total liabilities	$	3,393			$	1,101
____________________
-1	Includes $3.0 million held by the trustee at December 31, 2013 and 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 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 at the time of conveyance.
During 2012 and 2013, the Company sold Royalty Trust common units it owned in transactions exempt from registration pursuant to Rule 144 under the Securities Act, which further reduced its beneficial interest in the Royalty Trusts. Total proceeds from such transactions were $29.0 million and $139.4 million for the years ended December 31, 2013 and 2012, respectively. 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. The Company’s beneficial interests in the Royalty Trusts at December 31, 2013 and 2012 were as follows:
	December 31,
	2013			2012
Mississippian Trust I	26.9	%		26.9	%
Permian Trust	28.5	%		30.5	%
Mississippian Trust II	37.6	%		39.9	%
See Note 15 for discussion of the Company’s legal proceedings to which the Mississippian Trust I and Mississippian Trust II are also parties and Note 21 for discussion of the sale of Permian Trust common units in January 2014.
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 December 31, 2013 and 2012 included in the accompanying consolidated balance sheets are as follows (in thousands):
	December 31,
	2013				2012
Accounts receivable due from PGC	$	741			$	1,976
Accounts payable due to PGC	$	3,634			$	5,053

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	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 of December 31, 2013 or 2012, as described below.
	Level 1 Fair Value Measurements
	Restricted deposits. The fair value of restricted deposits invested in mutual funds or municipal bonds is based on quoted market prices. For restricted deposits held in savings accounts, carrying value approximates fair value. Restricted deposits are included in other assets in the accompanying 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 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 is the estimate of future oil basis differentials. Significant increases (decreases) in oil basis differentials could result in a significantly higher (lower) fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of the Company’s oil basis swaps at December 31, 2012 are included in the table below. All of the outstanding oil basis swaps at December 31, 2012 contractually matured during 2013.
	Unobservable Input		Range				Weighted Average		Fair Value
			(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):
	December 31, 2013
		Fair Value Measurements												Netting(1)			Assets/Liabilities at Fair Value
		Level 1				Level 2				Level 3
	Assets
	Restricted deposits	$	27,955			$	—			$	—			$	—		$	27,955
	Commodity derivative contracts	—				50,274				—				(23,369		)	26,905
	Investments	13,708				—				—				—			13,708
		$	41,663			$	50,274			$	—			$	(23,369	)	$	68,568
	Liabilities
	Commodity derivative contracts	$	—			$	78,200			$	—			$	(23,369	)	$	54,831
		$	—			$	78,200			$	—			$	(23,369	)	$	54,831
	December 31, 2012
		Fair Value Measurements												Netting(1)			Assets/Liabilities at Fair Value
		Level 1				Level 2				Level 3
	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 years ended December 31, 2011, 2012 and 2013 (in thousands):
			Commodity Derivative Contracts				Interest Rate Swaps
											Total
	Balance of Level 3 at December 31, 2010		$	(205,860	)		$	(16,694	)		$	(222,554	)
	Gain (loss) on derivative contracts		44,075				(3,168		)		40,907
	Cash paid on settlements		50,713				9,414				60,127
	Transfers(1)		106,820				10,448				117,268
	Balance of Level 3 at December 31, 2011		$	(4,252	)		$	—			$	(4,252	)
	Loss on derivative contracts		(5,460		)		—				(5,460		)
	Purchases		5,697				—				5,697
	Cash paid on settlements		3,503				—				3,503
	Balance of Level 3 at December 31, 2012		$	(512	)		$	—			$	(512	)
	Loss on derivative contracts		(133		)		—				(133		)
	Cash paid on settlements		645				—				645
	Balance of Level 3 at December 31, 2013		$	—			$	—			$	—
	____________________
	-1	Fair values related to the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap were transferred from Level 3 to Level 2 in the fourth quarter of 2011 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the years ended December 31, 2013 and 2012, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.
	The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred.
	Losses due to changes in fair value of the Company’s Level 3 commodity derivative contracts outstanding at December 31, 2012 were $0.5 million for the year ended December 31, 2012. These amounts have been included in loss (gain) on derivative contracts in the accompanying consolidated statements of operations. There were no outstanding Level 3 commodity derivative contracts at December 31, 2013.
	See Note 13 for further discussion of the Company’s derivative contracts.
	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 December 31, 2013 and 2012 were as follows (in thousands):
	December 31, 2013								December 31, 2012
	Fair Value				Carrying Value				Fair Value				Carrying Value
9.875% Senior Notes due 2016(1)	$	—			$	—			$	392,913			$	356,657
8.0% Senior Notes due 2018	—				—				790,313				750,000
8.75% Senior Notes due 2020(2)	486,000				444,736				490,500				444,127
7.5% Senior Notes due 2021(3)	1,230,813				1,178,922				1,257,250				1,179,328
8.125% Senior Notes due 2022	795,000				750,000				823,125				750,000
7.5% Senior Notes due 2023(4)	837,375				821,249				882,750				820,971
____________________
-1	Carrying value is net of $8,843 discount at December 31, 2012.
-2	Carrying value is net of $5,264 and $5,873 discount at December 31, 2013 and 2012, respectively.
-3	Carrying value includes a premium, applicable to notes issued in August 2012, of $3,922 and $4,328 at December 31, 2013 and 2012, respectively.
-4	Carrying value is net of $3,751 and $4,029 discount at December 31, 2013 and 2012, respectively.
See Note 12 for discussion of the Company’s long-term debt, including the purchase, redemption and issuance of senior notes in 2012 and 2013.
Fair Value of Non-Financial Assets and Liabilities
See Note 3 for information regarding the Company’s valuation of its acquisitions and Note 8 for discussion of the Company’s impairment valuation.

Accounts_Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2013
Accounts Receivable, Net, Current [Abstract]	'
Accounts Receivable	'
	Accounts Receivable
	A summary of accounts receivable is as follows (in thousands):
		December 31,
		2013			2012
	Oil, natural gas and NGL sales	$	166,157		$	215,450
	Joint interest billing	168,596			202,405
	Oil and natural gas services	17,904			21,186
	Insurance receivable	2,500			4,590
	Related party	—			978
	Other	5,122			6,532
		360,279			451,141
	Less: allowance for doubtful accounts	(11,061		)	(5,635		)
	Total accounts receivable, net	$	349,218		$	445,506
	The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2013, 2012 and 2011 (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Allowance for doubtful accounts at January 1	$	5,635		$	3,906		$	1,503
	Additions charged to costs and expenses(1)	5,497			1,735			2,511
	Deductions(2)	(71		)	(6		)	(108		)
	Allowance for doubtful accounts at December 31	$	11,061		$	5,635		$	3,906
	____________________
	-1	Includes $2.7 million of allowance for receivables deemed uncollectible at December 31, 2013 primarily due to bankruptcy status of customers.
	-2	Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established.

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Property, plant and equipment consists of the following (in thousands):
		December 31,
		2013			2012
	Oil and natural gas properties
	Proved(1)	$	10,972,816		$	12,262,921
	Unproved	531,606			865,863
	Total oil and natural gas properties	11,504,422			13,128,784
	Less accumulated depreciation, depletion and impairment	(5,762,969		)	(5,231,182		)
	Net oil and natural gas properties capitalized costs	5,741,453			7,897,602
	Land	18,423			17,927
	Non-oil and natural gas equipment(2)	600,603			643,370
	Buildings and structures(3)	233,405			205,349
	Total	852,431			866,646
	Less accumulated depreciation and amortization	(286,209		)	(284,271		)
	Other property, plant and equipment, net	566,222			582,375
	Total property, plant and equipment, net	$	6,307,675		$	8,479,977
	____________________
	-1	Includes cumulative capitalized interest of approximately $23.4 million and $11.7 million at December 31, 2013 and 2012, respectively.
	-2	Includes cumulative capitalized interest of approximately $4.3 million at both December 31, 2013 and 2012.
	-3	Includes cumulative capitalized interest of approximately $12.0 million and $7.1 million at December 31, 2013 and 2012, respectively.
	Cumulative full cost ceiling limitation impairment charges of $3.5 billion at both December 31, 2013 and 2012 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the accompanying consolidated balance sheets. There was no full cost ceiling impairment during any of the years ended December 31, 2013, 2012 or 2011. See Note 8 for discussion of impairment of other property, plant and equipment.
	The average rates used for depreciation and depletion of oil and natural gas properties were $16.81 per Boe in 2013, $16.93 per Boe in 2012 and $13.57 per Boe in 2011.
	Costs Excluded from Amortization
	The following table summarizes the costs, by year incurred, related to unproved properties and pipe inventory, which were excluded from oil and natural gas properties subject to amortization at December 31, 2013 (in thousands):
					Year Cost Incurred
		Total			2013			2012		2011		2010 and Prior
	Property acquisition	$	515,849		$	114,252		$	291,999	$	34,164	$	75,434
	Exploration(1)	61,327			48,764			5,479		3,598		3,486
	Total costs incurred	$	577,176		$	163,016		$	297,478	$	37,762	$	78,920
	____________________
	-1	Includes $45.6 million of pipe inventory costs incurred ($42.6 million in 2013, $2.8 million in 2012 and $0.2 million in 2010 and prior years).
	The Company expects to complete the majority of the evaluation activities within 10 years from the applicable date of acquisition, contingent on the Company’s capital expenditures and drilling program. In addition, the Company’s internal engineers evaluate all properties on at least an annual basis.

Impairment

Impairment	12 Months Ended
	Dec. 31, 2013
Impairment [Abstract]	'
Impairment	'
	Impairment
	Property, Plant and Equipment
	As deemed necessary based on events in 2012 and 2013, the Company analyzed various property, plant and equipment for impairment. Estimated fair values of these assets were calculated using a discounted cash flow method or recent offers from third-party purchasers.
	Gas Treating Plants and Other Midstream Assets. In the fourth quarter of 2012, the Company substantially completed construction of the Century Plant, a CO2 treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). In conjunction with the substantial completion and resulting diversion of the Company’s high CO2 natural gas production from its legacy gas treating plants to the Century Plant, the Company evaluated its legacy gas treating plants and CO2 compression facilities for impairment. Due to prevailing low natural gas prices, the Company’s natural gas production was not projected to reach the available treating capacity at the Century Plant. As such, the Company determined the use of its legacy gas treating plants and CO2 compression facilities in west Texas was limited, and accordingly, recorded a $79.3 million impairment of its gas treating plants and CO2 compression facilities at December 31, 2012.
	During 2013, the Company evaluated certain midstream pipe inventory, natural gas compressors, gas treating plants and a CO2 compressor station for impairment after determining that their future use was limited. As a result of these evaluations, the Company recorded impairments of $12.2 million during the year ended December 31, 2013 on these assets to reduce their carrying value to market value.
	Drilling Assets. As a result of the Company’s entry into an agreement to sell the Permian Properties, the Company performed an impairment assessment of its drilling rigs as of December 31, 2012 by calculating the estimated future cash flows to be generated by the rigs and their related assets. As the undiscounted future cash flows were in excess of the assets’ carrying value, no impairment was indicated at that time.
	During the second and third quarters of 2013, the Company committed to plans to sell various drilling assets. The net book value of these drilling assets was adjusted to fair value, resulting in an impairment of $11.1 million and a combined remaining net book value at that time of $6.2 million. Fair value for the drilling assets was estimated based on recent offers received from third parties with consideration of current market conditions. Including subsequent asset sales the remaining net book value of these assets was $5.9 million at December 31, 2013. These assets are included in other current assets in the accompanying consolidated balance sheet at December 31, 2013 as the Company intends to sell the assets within a year.
	Other Property, Plant and Equipment. In the second quarter of 2013, the Company committed to a plan to sell a corporate asset. The net book value of the corporate asset was adjusted to fair value, resulting in an impairment of $2.9 million during the year ended December 31, 2013. The fair value of the corporate asset was based on a current offer from a third-party purchaser, which is considered a Level 3 input. The corporate asset was sold in the fourth quarter of 2013.
	The Company recorded a $1.3 million impairment in 2012 due to the write-off of certain software costs as the software was determined to be obsolete.
	Goodwill
	In December 2012, the Company entered into an agreement to sell the Permian Properties, which the Company determined to be a triggering event for purposes of evaluating goodwill as the Permian Properties are included in the exploration and production segment, the reporting unit to which goodwill was assigned. As such, an impairment test was performed as of December 31, 2012. Primarily as a result of a decrease in the Company’s probable reserves as of December 31, 2012, which are one of the significant components in the determination of the fair value of the reporting unit, the carrying value of the reporting unit exceeded the fair value. Probable reserves used in the reporting unit fair value calculation decreased due to their reclassification to possible reserves as a result of the Company’s year-end evaluation of drilling results across its acreage in the Mississippian formation. Possible reserves are not included in the fair value calculation of the reporting unit. The Company performed step two of the impairment test, which indicated the entire balance of goodwill was impaired. As a result, the Company recorded an impairment equal to the carrying amount of goodwill, or $235.4 million, at December 31, 2012, which is included in impairment in the accompanying consolidated statement of operations for the year ended December 31, 2012.

Other_Assets

Other Assets	12 Months Ended
	Dec. 31, 2013
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]	'
Other Assets	'
	Other Assets
	Other assets consist of the following (in thousands):
		December 31,
		2013		2012
	Debt issuance costs, net of amortization(1)	$	61,923	$	83,643
	Restricted deposits	27,955		27,947
	Notes receivable on asset retirement obligations	11,640		11,433
	Investments	13,708		10,348
	Other	5,945		10,881
	Total other assets	$	121,171	$	144,252
	____________________
	-1	In 2013, the unamortized debt issuance costs associated with the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018 were written off at the time the Company redeemed these notes. See Note 12 for discussion of the senior note redemptions.

Accounts_Payable_and_Accrued_E

Accounts Payable and Accrued Expenses	12 Months Ended
	Dec. 31, 2013
Accounts Payable and Accrued Liabilities, Current [Abstract]	'
Accounts Payable and Accrued Expenses	'
	Accounts Payable and Accrued Expenses
	Accounts payable and accrued expenses consist of the following (in thousands):
		December 31,
		2013		2012
	Accounts payable and other accrued expenses	$	341,008	$	461,067
	Accrued interest	80,740		92,125
	Production payable	127,647		97,245
	Drilling advances	184,203		68,742
	Payroll and benefits	59,785		29,811
	Convertible perpetual preferred stock dividends	16,572		16,572
	Related party	2,533		982
	Total accounts payable and accrued expenses	$	812,488	$	766,544

Construction_Contracts

Construction Contracts	12 Months Ended
	Dec. 31, 2013
Contractors [Abstract]	'
Construction Contracts	'
	Construction Contracts
	Century Plant. 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 plant for the purpose of separating and removing CO2 from the delivered natural gas stream and the Company recognized construction contract revenue and costs equal to the revised contract price of $796.3 million, which are included in the accompanying statement of operations for the year ended December 31, 2012. 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 $4.1 million at December 31, 2013, representing costs incurred in the final stages of construction, are reported as a current asset in the accompanying consolidated balance sheet. Billings and contract loss in excess of costs of $15.5 million at December 31, 2012 are reported as a current liability in the accompanying consolidated balance sheet.
	Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, but accounted for separately, 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 15 for additional discussion of the treating agreement. The Company retains all methane gas from the natural gas it delivers to the Century Plant.
	Transmission Expansion Projects. In the second quarter of 2013, the Company substantially completed the construction of a series of electrical transmission expansion and upgrade projects in northern Oklahoma for a third party. The Company constructed these projects for a contract price of $23.3 million, which included agreed upon change orders. Upon substantial completion of the contract, the Company recognized construction contract revenue and costs equal to the revised contract price of $23.3 million, which are included in the accompanying consolidated statement of operations for the year ended December 31, 2013. Costs in excess of billings on these projects of $11.2 million at December 31, 2012 are included in current assets in the accompanying consolidated balance sheet. All costs had been billed as of December 31, 2013.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	Long-term debt consists of the following (in thousands):
		December 31,
		2013		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 $5,264 and $5,873 discount, respectively	444,736		444,127
	7.5% Senior Notes due 2021, including a premium of $3,922 and $4,328, respectively	1,178,922		1,179,328
	8.125% Senior Notes due 2022	750,000		750,000
	7.5% Senior Notes due 2023, net of $3,751 and $4,029 discount, respectively	821,249		820,971
	Total debt	3,194,907		4,301,083
	Less: current maturities of long-term debt	—		—
	Long-term debt	$	3,194,907	$	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 December 31, 2013, the senior credit facility contained financial covenants, including maintenance of 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 year ended December 31, 2013, the Company was in compliance with all applicable financial covenants under the senior credit facility.
	The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of certain of the Company’s material present and future subsidiaries; certain intercompany debt of the Company; and substantially all of the Company’s assets, including proved oil, natural gas and NGL reserves representing at least 80.0% of the discounted present value (as defined in the senior credit facility) of proved oil, natural gas and NGL reserves considered by the lenders in determining the borrowing base for the senior credit facility.
	At the Company’s election, interest under the senior credit facility is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 0.75% and 1.75% per annum. Interest is payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. Quarterly, the Company pays a commitment fee assessed at an annual rate of 0.5% on any available portion of the senior credit facility. There were no amounts outstanding under the senior credit facility during 2013 or 2012. The average annual interest rate paid on amounts outstanding under the senior credit facility during 2011 was 2.69%.
	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 is generally redetermined in April and October of each year, and was reaffirmed at $775.0 million in October 2013. The next borrowing base redetermination will be in April 2014. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base.
	At December 31, 2013, the Company had no amount outstanding under the senior credit facility and $29.1 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 23 for condensed financial information of the subsidiary guarantors.
	Debt issuance costs of $70.2 million incurred in connection with the offerings and subsequent registered exchange offers, including those discussed below, of the Senior Fixed Rate Notes outstanding at December 31, 2013 are included in other assets in the accompanying consolidated balance sheet 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 $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and $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 expense incurred to write off the remaining associated unamortized debt issuance costs, totaling $82.0 million, were recorded as a loss on extinguishment of debt in the accompanying consolidated statement of operations for the year ended December 31, 2013.
	2012 Activity. In 2012, the Company completed offerings of senior notes (the “2012 Senior Notes”), as further discussed below, to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S of the Securities Act. The Company incurred $41.0 million of debt issuance costs in connection with the 2012 Senior Notes offerings.
	In April 2012, the Company issued $750.0 million of unsecured 8.125% Senior Notes due 2022. Net proceeds from the offering were approximately $730.1 million after deducting offering expenses, and were used to finance the cash portion of the Dynamic Acquisition purchase price and to pay related fees and expenses, with any remaining amount used for general corporate purposes.
	In August 2012, the Company issued $825.0 million of unsecured 7.5% Senior Notes due 2023 at 99.5% of par and $275.0 million of additional unsecured 7.5% Senior Notes due 2021 at 101.625% of par, plus accrued interest from March 15, 2012. The Company received net proceeds from this offering of approximately $1.1 billion, after deducting offering expenses and excluding accrued interest received. The net proceeds of the offering were used to fund the Company’s tender offer for, and subsequent redemption of, its Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”), discussed under Senior Floating Rate Notes due 2014 below, to fund the Company’s capital expenditures and for general corporate purposes.
	In November 2012, pursuant to registered exchange offers, the Company replaced the 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.
	2011 Activity. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. In November 2011, pursuant to an exchange offer, the Company replaced these 7.5% Senior Notes due 2021 with equivalent senior notes that are registered under the Securities Act. The exchange offer did not result in the incurrence of any additional indebtedness.
	In 2011, the Company tendered the $650.0 million principal amount of its 8.625% Senior Notes due 2015. The premium paid to purchase these notes and the expense incurred to write off the remaining associated unamortized debt issuance costs, totaling $38.2 million ,were recorded as a loss on extinguishment of debt in the accompanying consolidated statement of operations for the year ended December 31, 2011.
	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 year ended December 31, 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 the third quarter of 2012, the Company purchased 100.0% or $350.0 million of the outstanding 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 premium paid to purchase these notes and the write off of the remaining unamortized debt issuance costs associated with the notes, totaling $3.1 million, were recorded as a loss on extinguishment of debt and included in the accompanying consolidated statement of operations for the year ended December 31, 2012. The Senior Floating Rate Notes were issued in May 2008 and bore interest at LIBOR plus 3.625% prior to their retirement.
	Maturities of Long-Term Debt
	As of December 31, 2013, there are no maturities of long-term debt until January 2020.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivatives	'
	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 loss (gain) on derivative contracts for commodity derivative contracts and in interest expense for interest rate swaps in the 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 contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. At December 31, 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 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.
	Interest Rate Swaps. The Company is exposed to interest rate risk on its long-term fixed rate debt and will be exposed to variable interest rates if it draws on its senior credit facility. 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.
	Prior to its maturity on April 1, 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 was not designated as a hedge.
	Derivatives Agreements with Royalty Trusts. Effective April 1, 2011, August 1, 2011 and April 1, 2012, the Company entered into derivatives agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II, respectively, to provide each Royalty Trust with the economic effect of certain oil and natural gas derivative contracts 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 Mississippian Trust II. As a party to these contracts, the Permian Trust and 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 Mississippian Trust II, the Company has the right, under certain circumstances, to assign or novate to the Permian Trust and 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 Mississippian Trust II, have been included in the Company’s consolidated derivative disclosures. See Note 4 for the Royalty Trusts’ open derivative contracts.
	Fair Value of Derivatives. The following table presents the fair value of the Company’s derivative contracts as of December 31, 2013 and 2012 on a gross basis without regard to same-counterparty netting (in thousands):
					December 31,
	Type of Contract		Balance Sheet Classification		2013				2012
	Derivative assets
	Oil price swaps		Derivative contracts—current		$	15,887			$	88,052
	Natural gas price swaps		Derivative contracts—current		1,598				—
	Oil basis swaps		Derivative contracts—current		—				183
	Oil collars—three way		Derivative contracts—current		706				—
	Natural gas collars		Derivative contracts—current		177				3,111
	Oil price swaps		Derivative contracts—noncurrent		19,376				37,983
	Oil collars—three way		Derivative contracts—noncurrent		12,189				190
	Natural gas collars		Derivative contracts—noncurrent		341				884
	Derivative liabilities
	Oil price swaps		Derivative contracts—current		(38,396		)		(31,991		)
	Natural gas price swaps		Derivative contracts—current		(1,460		)		—
	Oil basis swaps		Derivative contracts—current		—				(695		)
	Oil collars—two way		Derivative contracts—current		—				(103		)
	Interest rate swap		Derivative contracts—current		—				(2,395		)
	Oil price swaps		Derivative contracts—noncurrent		(38,344		)		(67,900		)
	Oil collars—three way		Derivative contracts—noncurrent		—				(7,327		)
	Total net derivative contracts				$	(27,926	)		$	19,992
	Refer to Note 5 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. As of December 31, 2013, the counterparties to the Company’s open derivative contracts consisted of 13 financial institutions, 11 of which are also lenders under the Company’s senior credit facility. As a result, the Company is not required to post additional collateral under derivative contracts as the majority of the counterparties to the Company’s derivative contracts share in the collateral supporting the Company’s senior credit facility. To secure their obligations under the derivative contracts novated by the Company, the Permian Trust and 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):
	December 31, 2013
			Gross Amounts				Gross Amounts Offset				Amounts Net of Offset		Financial Collateral			Net Amount
	Assets
	Derivative contracts - current		$	18,368			$	(5,589	)		$	12,779	$	—		$	12,779
	Derivative contracts - noncurrent		31,906				(17,780		)		14,126		—			14,126
	Total		$	50,274			$	(23,369	)		$	26,905	$	—		$	26,905
	Liabilities
	Derivative contracts - current		$	39,856			$	(5,589	)		$	34,267	$	(34,267	)	$	—
	Derivative contracts - noncurrent		38,344				(17,780		)		20,564		(20,564		)	—
	Total		$	78,200			$	(23,369	)		$	54,831	$	(54,831	)	$	—
	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 Company recorded loss (gain) on commodity derivative contracts of $47.1 million, $(241.4) million and $(44.1) million for the years ended December 31, 2013, 2012 and 2011, respectively, as reflected in the accompanying consolidated statements of operations. Included in the loss (gain) on commodity derivative contracts for the years ended December 31, 2013, 2012 and 2011 are net cash (receipts) payments upon contract settlement of $(3.2) million, $(100.7) million and $37.6 million, respectively. For the year ended December 31, 2013, $29.6 million of cash payments related to settlements of commodity derivative contracts with contractual maturities after the year in which they were settled as a result of the sale of the Permian Properties. For the year ended December 31, 2012, the gain on commodity derivative contracts is net of a non-cash loss of $117.1 million resulting from the amendment of certain 2012 derivative contracts to contracts maturing in 2014 and 2015.
	The Company recorded a loss on its interest rate swaps of $0.01 million, $1.2 million and $3.2 million for the years ended December 31, 2013, 2012 and 2011, respectively, which is included in interest expense in the accompanying consolidated statements of operations. Included in the loss for the years ended December 31, 2013, 2012 and 2011 are cash payments upon contract settlement of $2.4 million, $9.2 million and $9.4 million, respectively.
	At December 31, 2013, the Company’s open commodity derivative contracts consisted of the following:
	Oil Price Swaps
		Notional (MBbls)			Weighted Average
					Fixed Price
	January 2014 — December 2014	8,813			$	92.98
	January 2015 — December 2015	7,979			$	86.13
	Natural Gas Price Swaps
	Notional (MMcf)			Weighted Average
				Fixed Price
January 2014 — December 2014	35,490			$	4.2
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
January 2014 — December 2014	937			$4.00	—	$7.78
January 2015 — December 2015	1,010			$4.00	—	$8.55

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligation	'
	Asset Retirement Obligations
	The following table presents the balance and activity of the asset retirement obligations for the years ended December 31, 2013, 2012 and 2011 (in thousands).
		2013			2012			2011
	Asset retirement obligations at January 1	$	498,410		$	128,116		$	119,877
	Liability incurred upon acquiring and drilling wells	5,078			7,479			5,716
	Liability assumed in acquisition(1)	—			371,365			—
	Revisions in estimated cash flows	(3,077		)	34,654			7,574
	Liability settled or disposed in current period(2)	(113,071		)	(72,200		)	(14,419		)
	Accretion(3)	36,777			28,996			9,368
	Asset retirement obligations at December 31	424,117			498,410			128,116
	Less: current portion	87,063			118,504			32,906
	Asset retirement obligations, net of current	$	337,054		$	379,906		$	95,210
	____________________
	-1	Represents asset retirement obligations assumed in the acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.
	-2	Year ended December 31, 2013 includes $45.3 million for the decommissioning of various platforms, pipeline and associated wells in the Gulf of Mexico and $15.2 million of asset retirement obligations disposed in conjunction with the sale of the Permian Properties. Years ended December 31, 2013 and 2012 include the settlement of plugging and abandonment obligations associated with properties in the Gulf of Mexico. Year ended December 31, 2011 includes amounts related to the Permian Basin and east Texas properties sold during 2011.
	-3	Years ended December 31, 2013 and 2012 include accretion attributable to asset retirement obligations assumed in the acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Operating Leases. The Company has obligations under noncancelable operating leases, primarily for office space and equipment used in drilling and services activities. Total rental expense under operating leases for the years ended December 31, 2013, 2012 and 2011 was approximately $3.6 million, $2.6 million and $1.5 million, respectively.
	Future minimum payments under noncancelable operating leases (with initial lease terms exceeding one year) as of December 31, 2013 were as follows (in thousands):
	Years ending December 31
	2014	$	3,239
	2015	2,988
	2016	2,640
	2017	1,756
	2018	215
		$	10,838
	Rig Commitments. The Company has contracts with third-party drilling rig operators for the use of their rigs at specified day or footage rates. These commitments are not recorded in the consolidated balance sheets. Minimum future commitments as of December 31, 2013 were $20.3 million for 2014 and $1.1 million for 2015.
	Oil and Natural Gas Transportation and Throughput Agreements. The Company has subscribed firm gas transportation service under a transportation service agreement on the Midcontinent Express Pipeline, the term of which continues until March 2019. This commitment is not recorded in the consolidated balance sheets. Under the terms of the agreement, the Company is obligated to pay a demand charge and in exchange, obtains the right to flow natural gas production through this pipeline to more competitive marketing areas. The Company also has oil and natural gas throughput agreements in place, which require fixed fees based on minimum volume requirements for the right to flow oil and natural gas through certain pipelines. The amounts of the required payments related to the transportation and throughput agreements as of December 31, 2013 were as follows (in thousands):
	Years ending December 31
	2014	$	19,947
	2015	11,794
	2016	11,346
	2017	11,315
	2018	11,315
	Thereafter	2,790
		$	68,507
	Natural Gas Gathering Agreement. The Company has a gas gathering agreement with PGC related to its properties located in the Piñon Field in west Texas. Under the gas gathering agreement, the Company has dedicated its west Texas acreage for priority gathering services through June 30, 2029 and will pay a fee for such services. Pursuant to the gas gathering agreement, the base fee can be reduced if certain criteria are met. The table below presents the base fee contractual obligations under this agreement as of December 31, 2013 (in thousands).
	Years ending December 31
	2014	$	42,542
	2015	42,334
	2016	42,272
	2017	41,991
	2018	41,825
	Thereafter	100,559
		$	311,523
	Development Agreements with Royalty Trusts. The Company’s development agreements with the Permian Trust and Mississippian Trust II obligate the Company to drill, or cause to be drilled, a specified number of wells within an area of mutual interest for each trust by March 31, 2016 and December 31, 2016, respectively. The estimated cost to fulfill the drilling obligations remaining at December 31, 2013 totaled approximately $137.0 million. The Company fulfilled its drilling obligation to SandRidge Mississippian Trust I during 2013.
	Treating Agreement. 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 is required to deliver a total of approximately 3,200 Bcf of CO2 during the agreement period. At December 31, 2013, approximately 3,000 Bcf of CO2 remained to be delivered. The Company is obligated to pay Occidental $0.25 per Mcf to the extent minimum annual CO2 volume requirements are not met. Additionally, if CO2 volumes delivered by the Company over the term of the agreement do not reach 3,200 Bcf, the Company is obligated to pay Occidental $0.70 per Mcf for such undelivered CO2 volumes at the end of the agreement term in 2042. Based upon natural gas production levels in 2013, the Company accrued $32.7 million for amounts related to the Company’s shortfall in meeting its 2013 delivery obligations, which was included in production expenses in the accompanying consolidated statement of operations for the year ended December 31, 2013. Based on current projected natural gas production levels, the Company expects to accrue between approximately $30.0 million and $37.0 million during the year ending December 31, 2014 for amounts related to the Company’s anticipated shortfall in meeting its 2014 annual delivery obligations. Due to the sensitivity of drilling activity to market prices for natural gas, the Company is unable to estimate additional amounts it may be obligated to pay under the agreement in subsequent periods; however, if natural gas prices remain low, drilling activity will likely remain very limited, which would result in additional shortfall payments in future periods.
	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 13 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, as discussed above. The Company depends on cash flows from operating activities, funding commitments from third parties for drilling carries and, as necessary, borrowings under its senior credit facility to fund its capital expenditures. Additionally, the Company may use proceeds from the issuance of equity and debt securities in the capital markets and from the sales or other monetizations of assets to fund its capital expenditures. Based on current cash balances, including proceeds received from the sale of certain of the Company’s subsidiaries that owned its Gulf of Mexico and Gulf Coast oil and natural gas properties (collectively, the “Gulf Properties”), 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 2014; However, a substantial or extended decline in oil, natural gas or NGL prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL 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 12 for discussion of the financial covenants in the senior credit facility.
	Litigation and Claims. 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 CO 2 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 CO 2 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 SandRidge Entities' 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. On June 29, 2013, the court granted in part and denied in part the defendants’ motion. The Company and the other defendants intend to defend this lawsuit vigorously and believe 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 defendants’ 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 former 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.
	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 complaint by May 1, 2013. On June 3, 2013, the Company and the individual defendants filed their respective motions to dismiss the consolidated complaint. On September 11, 2013, the court granted the defendants’ respective motions to dismiss the consolidated complaint without prejudice, and granted plaintiffs leave to file an amended consolidated complaint. The plaintiffs filed an amended consolidated complaint on October 9, 2013, in which plaintiffs allege that: (i) the Company’s former Chief Executive Officer (“CEO”), Tom Ward, breached his fiduciary duties by usurping corporate opportunities, (ii) certain of the Company’s current and former directors breached their fiduciary duties of care, (iii) Mr. Ward and certain of the Company’s current and former directors wasted corporate assets, (iv) certain entities allegedly affiliated with Mr. Ward aided and abetted Mr. Ward’s breaches of fiduciary duties, (v) Mr. Ward and entities allegedly affiliated with Mr. Ward misappropriated the Company’s confidential and proprietary information, and (vi) entities allegedly affiliated with Mr. Ward were unjustly enriched. The defendants have filed respective motions to dismiss the amended consolidated complaint, which are 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 the 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 June 19, 2013, the court stayed the Hefner action until at least November 29, 2013. The court subsequently lifted its stay for purposes of hearing and deciding the defendants’ respective motions to dismiss. On September 18, 2013, the court denied the defendants’ motions to dismiss.
	On May 8, 2013, the court stayed the Romano action pending further order of the court. On October 31, 2013, the plaintiff filed a motion to lift the stay, which was denied by the court on February 7, 2014.
	Because the Federal Shareholder Derivative Litigation and the State Shareholder Derivative Litigation are in the early stages, 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 plaintiffs’ claims and the defendants’ 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. On July 23, 2013, plaintiffs filed a consolidated amended complaint, which 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 the Mississippian Trust I in or traceable to its initial public offering on or about April 12, 2011, and (c) purchasers of common units of the Mississippian Trust II (together with the Mississippian Trust I, the “Mississippian Trusts”) in or traceable to its initial public offering on or about April 23, 2012. The claims are based on allegations that the Company, certain of its current and former officers and directors, and the Mississippian Trusts, 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. The defendants have filed respective motions to dismiss the consolidated amended complaint, which are pending before the court. Because the Securities Litigation is in the early stages, 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 defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to the Securities Litigation. Each of the Mississippian Trusts has requested that the Company indemnify it for any losses it may incur in connection with the Securities Litigation.
	On July 15, 2013, James Hart and fifteen other named plaintiffs filed an Amended Complaint in the United States District Court for the District of Kansas in an action undertaken individually and on behalf of others similarly situated against SandRidge Energy, Inc., SandRidge Operating Company, SandRidge Exploration and Production, LLC, SandRidge Midstream, Inc., and Lariat Services, Inc. In their Amended Complaint, plaintiffs allege that the defendants failed to properly calculate overtime pay for the plaintiffs and for other similarly situated current and former employees. The plaintiffs further allege that the defendants required the plaintiffs and other similarly situated current and former employees to engage in work-related activities without pay. The plaintiffs assert claims against the defendants for (i) violations of the Fair Labor Standards Act, (ii) violations of the Kansas Wage Payment Act, (iii) breach of contract, and (iv) fraud, and seek to recover unpaid wages and overtime pay, liquidated damages, statutory penalties, economic damages, compensatory and punitive damages, attorneys’ fees and costs, and both pre- and post-judgment interest.
	On October 3, 2013, the plaintiffs filed a Motion for Conditional Collective Action Certification and for Judicial Notice to Class and a Motion to Toll the Statute of Limitations. On October 11, 2013, the defendants filed a Motion to Dismiss and a Motion to Transfer Venue to the United States District Court for the Western District of Oklahoma. All of these motions are pending before the court. The Company and the other defendants intend to defend this lawsuit vigorously. 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 defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.
	On December 18, 2013, the Company received a subpoena duces tecum from the U.S. Department of Justice in connection with an ongoing investigation of possible violations of antitrust laws in connection with the purchase or lease of land, oil or gas rights.  The Company is cooperating with the investigation.
	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.

Equity

Equity	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Equity	'
	Equity
	Preferred Stock
	The following table presents information regarding the Company’s preferred stock (in thousands):
		December 31,
		2013			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 7.7 million shares are designated as convertible perpetual preferred stock at December 31, 2013 and 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.
	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. After a 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 convertible perpetual preferred stock is not redeemable by the Company at any time. The following table summarizes information about each series of the Company’s convertible perpetual preferred stock:
			Convertible Perpetual Preferred Stock
			8.50%				6.00%			7.00%
	Liquidation preference per share		$	100			$	100		$	100
	Annual dividend per share		$	8.5			$	6		$	7
	Conversion rate per share to common stock		12.4805				9.2115			12.8791
	Conversion date to common stock at Company's option(1)		February 20, 2014				December 21, 2014			November 20, 2015
	____________________
	-1	Conversion is dependent on certain factors, including the Company’s stock trading above specified prices for a set period.
	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 years ended December 31, 2013, 2012 and 2011 as presented in the accompanying consolidated statements of operations, are included in tables below (in thousands):
		Dividends Paid				Dividends Unpaid			Total
	Year Ended December 31, 2013
	8.5% Convertible perpetual preferred stock	$	14,078			$	8,447		$	22,525
	6.0% Convertible perpetual preferred stock	6,500				5,500			12,000
	7.0% Convertible perpetual preferred stock	18,375				2,625			21,000
	Total	$	38,953			$	16,572		$	55,525
	Year Ended December 31, 2012
	8.5% Convertible perpetual preferred stock	$	14,078			$	8,447		$	22,525
	6.0% Convertible perpetual preferred stock	6,500				5,500			12,000
	7.0% Convertible perpetual preferred stock	18,375				2,625			21,000
	Total	$	38,953			$	16,572		$	55,525
	Year Ended December 31, 2011
	8.5% Convertible perpetual preferred stock	$	14,078			$	8,447		$	22,525
	6.0% Convertible perpetual preferred stock	6,500				5,500			12,000
	7.0% Convertible perpetual preferred stock	18,433				2,625			21,058
	Total	$	39,011			$	16,572		$	55,583
	Common Stock
	The following table presents information regarding the Company’s common stock (in thousands):
		December 31,
		2013			2012
	Shares authorized	800,000			800,000
	Shares outstanding at end of period	490,290			490,359
	Shares held in treasury	1,319			1,219
	On April 17, 2012, the Company issued approximately 74.0 million shares of SandRidge common stock to satisfy the stock portion of the consideration paid in the Dynamic Acquisition. See Note 3 for further discussion of the Dynamic Acquisition.
	Stockholder Rights Plan
	On November 19, 2012, the Company’s Board adopted a stockholder rights plan pursuant to which the Board authorized and declared to stockholders of record on November 29, 2012 a dividend of one preferred share purchase right (the “Right”) for each outstanding share of common stock. Effective April 29, 2013, at the direction of the Board, the Company amended the stockholder rights plan to accelerate the expiration date of the Rights to April 29, 2013, resulting in expiration of the Rights and termination of the stockholder rights plan.
	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. The following table shows the number of shares withheld for taxes and the associated value of those shares for the years ended December 31, 2013, 2012 and 2011. These shares were accounted for as treasury stock when withheld, and then immediately retired.
		Year Ended December 31,
		2013				2012			2011
		(In thousands)
	Number of shares withheld for taxes	5,679				1,547			1,176
	Value of shares withheld for taxes	$	30,126			$	11,312		$	10,834
	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 for accounting purposes. 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 Securities Exchange Act of 1934, as amended. The claim was filed in December 2010 and related to certain transactions involving Company common stock entered into 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 receivable was recorded as a component of additional paid-in capital. Amounts receivable from Mr. Ward at December 31, 2013 and 2012 of $3.8 million and $5.0 million, respectively, are included in the accompanying consolidated balance sheets.
	Restricted Common Stock
	The Company awards restricted common stock under its long-term incentive compensation plan that generally vests over a four-year period, subject to certain conditions, and is valued based upon the market value of common stock on the date of grant. 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.
	Restricted stock activity for the years ended December 31, 2013, 2012 and 2011 was as follows (shares in thousands):
		Number of			Weighted-
		Shares			Average Grant
		Date Fair Value
Unvested restricted shares outstanding at December 31, 2010	9,476			$	10.89
Granted	8,003			$	8.95
Vested	(3,270	)		$	12.91
Forfeited / Canceled	(823	)		$	9.17
Unvested restricted shares outstanding at December 31, 2011	13,386			$	9.34
Granted	7,604			$	7.46
Vested	(4,394	)		$	10.73
Forfeited / Canceled	(1,268	)		$	8.54
Unvested restricted shares outstanding at December 31, 2012	15,328			$	8.07
Granted	7,462			$	6.32
Vested	(13,395	)		$	7.85
Forfeited / Canceled	(1,752	)		$	7.33
Unvested restricted shares outstanding at December 31, 2013	7,643			$	6.92
For the years ended December 31, 2013, 2012 and 2011, the Company recognized equity compensation expense of $82.8 million, $39.7 million, and $36.0 million, net of $5.5 million, $7.5 million, and $7.6 million capitalized, respectively, related to restricted common stock. Amounts recognized during the year ended December 31, 2013 include approximately $48.5 million recognized in connection with the separation of certain former executives from the Company.
The total fair value of restricted stock that vested during the years ended December 31, 2013, 2012 and 2011, was $71.6 million, $32.1 million and $30.2 million, respectively. As of December 31, 2013, there was approximately $37.0 million of unrecognized compensation cost related to unvested restricted stock awards, which is expected to be recognized over a weighted average period of 2.3 years. The Company had approximately 9.6 million shares available for grant under its existing incentive compensation plan at December 31, 2013.
See Note 17 for discussion of the Company’s performance units.

Incentive_Retirement_and_Defer

Incentive, Retirement and Deferred Compensation Plans	12 Months Ended
	Dec. 31, 2013
Compensation Related Costs [Abstract]	'
Incentive, Retirement and Deferred Compensation Plans Disclosure	'
	Incentive, Retirement and Deferred Compensation Plans
	Annual Incentive Plan. In June 2013, the Compensation Committee of the Company’s Board (the “Compensation Committee”) approved an annual incentive plan effective June 2013 for all employees and discontinued the Company’s then existing cash bonus program with final payments under the program of approximately $10.9 million 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 December 31, 2013, the Company had accrued approximately $30.2 million for the 2013 annual incentive for all employees, including an accrual for an annual incentive for specified members of management based on actual performance compared to target levels specified in the annual incentive plan.
	Performance Units. In July 2013, subsequent to approval by the Compensation Committee, the Company granted 31,142 performance units to certain members of senior management under the Company’s existing long-term incentive plan which vest over a performance period from July 2013 to December 2015. The value, and ultimate payout, of the performance units is determined based upon the Company’s total shareholder return relative to that of a predetermined peer group over a specific performance period. If performance exceeds the minimum thresholds, payout percentages could range from 50% to 200% of specified target values. If minimum target thresholds are not met, the payout is reduced to zero.
	The performance units are valued for accounting purposes using a Monte Carlo simulation based on certain assumptions, including (i) a volatility assumption based on the historical realized price volatility of the Company’s common stock and the common stock of the predetermined peer group and (ii) a risk-free interest rate based on the U.S. Treasury bond yields for a term commensurate with the approximate remaining vesting period. As of December 31, 2013, the Company had a liability of $1.8 million, equal to the fair value of the portion of performance units for which requisite service has been completed. The following table presents a summary of the fair value of the performance units and the related assumptions as of December 31, 2013.
	Expected price volatility range	27	%	-	44.8		%
	Risk-free interest rate				0.4		%
	Fair value per unit (at grant date)				$	69.38
	Fair value per unit (at December 31, 2013)				$	97.06
	For the year ended December 31, 2013, the Company recognized equity compensation expense of $1.6 million, net of $0.2 million capitalized, related to performance units. The total fair value of the 12,178 performance units that vested during the year ended December 31, 2013 was $1.2 million. There were no performance units forfeited during 2013. As of December 31, 2013, there was approximately $1.2 million of unrecognized compensation cost related to unvested performance units, which is expected to be recognized over a weighted average period of 2.0 years.
	Deferred Compensation Plans. The Company maintains a 401(k) retirement plan for its employees. Under the plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by regulations promulgated by the Internal Revenue Service (“IRS”). For the years ended December 31, 2013, 2012 and 2011, the Company made matching contributions of cash purchases of Company stock to the plan equal to 100% on the first 15% of employee deferred wages. Retirement plan expense for the years ended December 31, 2013, 2012 and 2011 was approximately $11.0 million, $11.4 million and $7.4 million, respectively.
	The Company maintains a non-qualified deferred compensation plan that allows eligible highly compensated employees to elect to defer income exceeding the IRS annual limitations on qualified 401(k) retirement plans. The Company makes matching contributions on non-qualified contributions up to a maximum of 15% of employee compensation. For the years ended December 31, 2013, 2012 and 2011, employer contributions of cash purchases of Company stock were approximately $2.7 million, $3.5 million and $3.1 million, respectively.
	Any assets placed in trust by the Company to fund future obligations of the Company’s non-qualified deferred compensation plan are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their own deferred compensation in, and the Company’s contributions to, the plan.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	The Company’s income tax provision (benefit) consisted of the following components for the years ended December 31, 2013, 2012 and 2011 (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Current
	Federal	$	3,842		$	(72	)	$	618
	State	1,842			(2		)	551
		5,684			(74		)	1,169
	Deferred
	Federal	—			(97,410		)	(6,447		)
	State	—			(2,878		)	(539		)
		—			(100,288		)	(6,986		)
	Total provision (benefit)	5,684			(100,362		)	(5,817		)
	Less: income tax provision attributable to noncontrolling interest	308			304			109
	Total provision (benefit) attributable to SandRidge Energy, Inc.	$	5,376		$	(100,666	)	$	(5,926	)
	A reconciliation of the provision (benefit) for income taxes at the statutory federal tax rate to the Company’s actual income tax benefit is as follows for the years ended December 31, 2013, 2012 and 2011 (in thousands):
		2013			2012			2011
	Computed at federal statutory rate	$	(178,078	)	$	51,173		$	54,800
	State taxes, net of federal benefit	(886		)	8,913			5,231
	Non-deductible expenses	2,589			7,247			6,394
	Stock-based compensation	7,611			7,172			8,229
	Net effects of consolidating the non-controlling interests’ tax provisions	(13,901		)	(37,047		)	(19,120		)
	Bargain purchase gain	—			(42,944		)	—
	Impairment of non-deductible goodwill	—			71,885			—
	Change in valuation allowance	188,599			(66,429		)	(51,631		)
	Valuation allowance release	—			(100,288		)	(5,290		)
	Other	(558		)	(348		)	(4,539		)
	Total provision (benefit) attributable to SandRidge Energy, Inc.	$	5,376		$	(100,666	)	$	(5,926	)
	Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are reduced by a valuation allowance when a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. As of December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. During the year ended December 31, 2012, the Company recorded a net deferred tax liability of $100.3 million associated with the Dynamic Acquisition and released a corresponding portion of the previously recorded valuation allowance. In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the acquisition of Arena in order to finalize the purchase price allocation. In connection therewith, the Company adjusted the previously recorded net deferred tax liability associated with the acquisition of Arena by recording an additional net deferred tax liability of $7.0 million and released a corresponding portion of its previously recorded valuation allowance. The partial releases of the valuation allowance in 2012 and 2011 were based on management’s assessment that it is more likely than not that the Company will realize a benefit from more of its existing deferred tax assets as the Dynamic and Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Although the Company had a full valuation allowance against its net deferred tax asset at each year December 31, 2013, 2012 and 2011, the partial releases of the valuation allowance resulted in a deferred tax benefit in 2012 and 2011. The Company continues to closely monitor all available evidence in making its determination for the need to maintain a valuation allowance against its net deferred tax asset.
	Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):
		December 31,
		2013			2012
	Deferred tax liabilities
	Investments(1)	$	301,447		$	334,331
	Property, plant and equipment	180,140			198,424
	Derivative contracts	—			24,819
	Total deferred tax liabilities	481,587			557,574
	Deferred tax assets
	Derivative contracts	3,692			—
	Allowance for doubtful accounts	20,358			17,713
	Net operating loss carryforwards	973,675			859,328
	Litigation settlement	355			7,200
	Compensation and benefits	24,895			13,935
	Alternative minimum tax credits and other carryforwards	46,624			42,242
	Asset retirement obligations	147,626			172,229
	Under-delivery obligation	15,012			—
	Other	2,801			2,193
	Total deferred tax assets	1,235,038			1,114,840
	Valuation allowance	(753,451		)	(557,266		)
	Net deferred tax liability	$	—		$	—
	____________________
	-1	Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. See Note 4 for further discussion of the Royalty Trusts.
	As of December 31, 2013, the Company had approximately $13.1 million of alternative minimum tax credits available that do not expire. In addition, the Company had approximately $2.6 billion of federal net operating loss carryovers that expire during the years 2023 through 2033. Excess tax benefits of approximately $16.3 million associated with the vesting of restricted stock awards are included in the federal net operating loss carryovers, but will not be recognized as a tax benefit recorded to additional paid-in capital until realized.
	Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected certain of the Company’s tax attributes, including $298.4 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. The Company experienced a subsequent ownership change within the meaning of IRC Section 382 on July 16, 2010 as a result of the acquisition of Arena. The subsequent ownership change resulted in a more restrictive limitation on certain of the Company’s tax attributes than with the December 31, 2008 ownership change. The more restrictive limitation applies not only to the $298.4 million of federal net operating loss carryforwards and certain other tax attributes existing at December 31, 2008, but also to net operating losses of approximately $629.8 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 December 31, 2013 or 2012.
	At December 31, 2013 and 2012, respectively, the Company had a liability of approximately $1.4 million and $1.3 million for unrecognized tax benefits. If recognized, approximately $0.9 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):
		December 31,
		2013			2012
	Unrecognized tax benefit at January 1	$	1,330		$	1,758
	Changes to unrecognized tax benefits related to the current year	262			—
	Changes to unrecognized tax benefits related to a prior year	(210		)	(428		)
	Unrecognized tax benefit at December 31	$	1,382		$	1,330
	Consistent with its policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included approximately $(0.1) million, $0.03 million and $0.1 million of accrued gross interest with respect to unrecognized tax benefits in its accompanying consolidated statements of operations during the years ended December 31, 2013, 2012 and 2011, respectively. The Company had a corresponding accrued liability of $0.1 million and $0.2 million for interest and penalties relating to uncertain tax positions at December 31, 2013 and 2012, respectively.
	The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2010 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 $0.8 million.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	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 is 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 years ended December 31, 2013, 2012 and 2011 (in thousands):
		Income (Loss)			Weighted Average Shares	Earnings (Loss) Per Share
		(In thousands, except per share amounts)
	Year Ended December 31, 2011
	Basic earnings per share	$	52,482		398,851	$	0.13
	Effect of dilutive securities
	Restricted stock	—			7,794
	Diluted earnings per share	$	52,482		406,645	$	0.13
	Year Ended December 31, 2012
	Basic earnings per share	$	86,046		453,595	$	0.19
	Effect of dilutive securities
	Restricted stock	—			2,420
	Diluted earnings per share	$	86,046		456,015	$	0.19
	Year Ended December 31, 2013
	Basic loss per share	$	(609,414	)	481,148	$	(1.27	)
	Effect of dilutive securities
	Restricted stock(1)	—			—
	Diluted loss per share	$	(609,414	)	481,148	$	(1.27	)
	____________________
	-1	Restricted stock awards covering 0.5 million shares were excluded from the computation of loss per share because their effect would have been antidilutive.
	In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5%, 6.0% and 7.0% convertible perpetual preferred stock for the years ended December 31, 2013, 2012, and 2011. See Note 16 for discussion of the Company’s convertible perpetual preferred stock. 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 to common stockholders. For the years ended December 31, 2013, 2012 and 2011, 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) income available to common stockholders.
	As discussed in Note 16, the Company’s Board adopted a stockholder rights plan in November 2012 under which holders of common stock were issued Rights. As the contingency for exercising these Rights had not been met as of December 31, 2012, the Company did not include the conversion of any Rights in its computation of diluted earnings per share for the year ended December 31, 2012. The Rights expired and the stockholder rights plan was terminated in 2013.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	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. See Note 6 and Note 10 for accounts receivable and accounts payable, respectively, attributable to related party transactions. During the years ended December 31, 2013, 2012 and 2011, sales to and reimbursements from related parties were $1.6 million, $12.8 million and $21.5 million, respectively. These amounts primarily relate to sales of natural gas from the Permian Properties, which were sold in February 2013, to the Company’s partner in GRLP.
	Former Chairman and CEO Severance. On June 28, 2013, Tom L. Ward separated employment from the Company. In accordance with the terms of Mr. Ward’s employment agreement, the Company paid $57.9 million in severance and accelerated the vesting of approximately 6.3 million shares of restricted stock awards, resulting in $36.8 million of compensation expense, during the third quarter of 2013. Additionally, and in accordance with the agreement, the Company will pay Mr. Ward approximately $4.6 million in 36 monthly installments beginning in January 2014. See Note 16 for discussion of the stockholder receivable due from Mr. Ward.
	Other Employee Termination Benefits. During 2013, certain employees received termination benefits, including severance and accelerated stock vesting, upon separation of service from the Company. Employee termination benefits, excluding amounts attributable to the Company’s former chairman and CEO, were $23.2 million for the year ended December 31, 2013.
	Oklahoma City Thunder Agreements. 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. Any renovation costs paid by the Company with respect to the leased space are applied toward future rent payments. As of December 31, 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.
	2014 Divestiture. See Note 21 for discussion of sale of the Company’s Gulf Properties to Fieldwood Energy LLC, a portfolio company of Riverstone Holdings LLC, affiliates of which own a significant number of shares of the Company’s common stock.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	Subsequent Events
	Sale of Permian Trust Units. On January 9, 2014, the Company sold the remainder of the Permian Trust common units it owned in a transaction exempt from registration pursuant to Rule 144 under the Securities Act for total proceeds of $22.1 million. Subsequent to the sale, the Company owned an approximate 25.0% beneficial interest in the Permian Trust which was attributable to its ownership of the subordinated units.
	Royalty Trust Distributions. On January 30, 2014, the Royalty Trusts announced quarterly distributions for the three-month period ended December 31, 2013. The following distributions will be paid on February 28, 2014 to holders of record as of the close of business on February 14, 2014 (in thousands):
	Royalty Trust		Total Distribution		Amount to be Distributed to Third-Party Unitholders
	Mississippian Trust I		$	10,508	$	10,242
	Permian Trust		33,677		25,239
	Mississippian Trust II		24,160		17,637
	Total		$	68,345	$	53,118
	Sale of Gulf Properties. On February 25, 2014, the Company sold certain of its subsidiaries that own the Company’s Gulf Properties, for $750.0 million, subject to purchase price and post-closing adjustments, and the buyer’s assumption of approximately $370.0 million of related asset retirement obligations to Fieldwood Energy LLC. This transaction is not expected to result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company will record the proceeds as a reduction of its full cost pool with no gain or loss on the sale.
	Under the agreement, the Company has agreed to guarantee certain plugging and abandonment obligations associated with the Gulf Properties to the Bureau of Ocean Energy Management for a period of up to one year from the date of closing. The Company recorded a liability equal to the fair value of the guarantee at the time the transaction closed. As of December 31, 2013, the fair value of the guarantee was approximately $9.0 million. As part of the agreement, the buyer has agreed to indemnify the Company for any costs it may incur as a result of the guarantee. Additionally, the buyer of the Gulf Properties will maintain restricted deposits, totaling approximately $27.9 million, that have been placed in escrow for plugging and abandonment obligations associated with the Gulf Properties for a period of up to one year from the closing date. Upon expiration of the guarantee, the Company will receive payment for half of such restricted deposits, or approximately $14.0 million from the purchaser.
	In conjunction with the divestiture of the Gulf Properties, the Company settled a portion of its existing oil derivative contracts in January and February 2014 prior to their respective maturities to reduce production volumes covered by derivative contracts in proportion to the anticipated reduction in production volumes due to the sale, which resulted in cash payments of approximately $69.6 million.
	The following unaudited pro forma combined results of operations for the year ended December 31, 2013 are presented as though the Company divested of the Gulf Properties as of January 1, 2013. The pro forma combined results of operations for the year ended December 31, 2013 has 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. The 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. 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.
		Year Ended December 31,
		2013
		(In thousands, except per share data)
		(Unaudited)
	Revenues	$	1,356,152
	Net loss(1)	$	(1,068,664	)
	Loss attributable to SandRidge Energy, Inc. common stockholders(1)	$	(1,028,055	)
	Loss per common share(1)
	Basic	$	(2.25	)
	Diluted	$	(2.25	)
	____________________
	-1	Includes pro forma ceiling impairment of $441.0 million, including $80.0 million allocated to noncontrolling interest and $361.0 million attributable to SandRidge Energy, Inc., for the year ended December 31, 2013.
	For the year ended December 31, 2013, the Gulf Properties had associated production, revenues and expenses, including direct operating expenses, depletion, accretion of asset retirement obligations, and general and administrative expenses, of 10.1 MMBoe, $627.2 million and $492.0 million, respectively.

Business_Segment_Information

Business Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Business Segment Information	'
	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 exploration 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 coordinates the delivery of electricity to the Company’s exploration and production operations in the Mid-Continent. The All Other column in the tables below includes items not related to the Company’s reportable segments, including the Company’s corporate operations.
	Management evaluates the performance of the Company’s business segments based on income (loss) from operations.
	Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):
		Exploration and			Drilling and Oil			Midstream			All Other(4)			Consolidated
		Production(1)			Field Services(2)			Services(3)						Total
	Year Ended December 31, 2013
	Revenues	$	1,834,480		$	187,456		$	179,989		$	3,127		$	2,205,052
	Inter-segment revenue	(320		)	(120,815		)	(100,529		)	—			(221,664		)
	Total revenues	$	1,834,160		$	66,641		$	79,460		$	3,127		$	1,983,388
	Income (loss) from operations	$	62,509		$	(40,155	)	$	(21,567	)	$	(169,788	)	$	(169,001	)
	Interest income (expense), net	1,168			—			(209		)	(271,193		)	(270,234		)
	Loss on extinguishment of debt	—			—			—			(82,005		)	(82,005		)
	Other income (expense), net	5,487			—			(3,222		)	10,180			12,445
	Income (loss) before income taxes	$	69,164		$	(40,155	)	$	(24,998	)	$	(512,806	)	$	(508,795	)
	Capital expenditures(5)	$	1,319,012		$	7,125		$	55,706		$	42,040		$	1,423,883
	Depreciation, depletion, amortization and accretion	$	605,242		$	33,291		$	7,972		$	20,140		$	666,645
	At December 31, 2013
	Total assets	$	6,157,225		$	158,737		$	188,165		$	1,180,668		$	7,684,795
	Year Ended December 31, 2012
	Revenues	$	2,571,544		$	379,345		$	116,659		$	4,356		$	3,071,904
	Inter-segment revenue	(403		)	(262,712		)	(77,824		)	—			(340,939		)
	Total revenues	$	2,571,141		$	116,633		$	38,835		$	4,356		$	2,730,965
	Income (loss) from operations	$	518,144		$	11,911		$	(73,027	)	$	(131,832	)	$	325,196
	Interest income (expense), net	1,286			—			(559		)	(304,076		)	(303,349		)
	Bargain purchase gain	122,696			—			—			—			122,696
	Loss on extinguishment of debt	—			—			—			(3,075		)	(3,075		)
	Other income, net	1,868			—			—			2,873			4,741
	Income (loss) before income taxes	$	643,994		$	11,911		$	(73,586	)	$	(436,110	)	$	146,209
	Capital expenditures(5)	$	1,951,490		$	27,527		$	80,413		$	114,552		$	2,173,982
	Depreciation, depletion, amortization and accretion	$	598,101		$	34,677		$	7,188		$	17,864		$	657,830
	At December 31, 2012
	Total assets	$	8,681,056		$	199,523		$	151,492		$	758,660		$	9,790,731
	Year Ended December 31, 2011
	Revenues	$	1,237,565		$	390,485		$	183,912		$	10,535		$	1,822,497
	Inter-segment revenue	(265		)	(287,187		)	(118,731		)	(1,101		)	(407,284		)
	Total revenues	$	1,237,300		$	103,298		$	65,181		$	9,434		$	1,415,213
	Income (loss) from operations	$	521,117		$	10,341		$	(12,975	)	$	(89,470	)	$	429,013
	Interest income (expense), net	509			(95		)	(611		)	(237,135		)	(237,332		)
	Loss on extinguishment of debt	—			—			—			(38,232		)	(38,232		)
	Other income (expense), net	3,601			—			(485		)	6			3,122
	Income (loss) before income taxes	$	525,227		$	10,246		$	(14,071	)	$	(364,831	)	$	156,571
	Capital expenditures(5)	$	1,697,691		$	25,674		$	38,514		$	54,615		$	1,816,494
	Depreciation, depletion, amortization and accretion	$	328,753		$	32,582		$	4,650		$	14,259		$	380,244
	____________________
	-1	Income from operations includes impairment of the Company’s goodwill of $235.4 million for the year ended December 31, 2012.
	-2	For the year ended December 31, 2013, loss from operations includes impairment of $11.1 million on certain drilling assets.
	-3	For the years ended December 31, 2013 and 2012, loss from operations includes impairments of the Company’s gas treating plants in west Texas and other midstream assets of $3.9 million and $59.7 million, respectively.
	-4	For the year ended December 31, 2013, loss from operations includes a $2.9 million impairment of a corporate asset and an $8.3 million impairment of the Company’s CO2 compression facilities. For the year ended December 31, 2012, loss from operations includes a $19.6 million impairment of the Company’s CO2 compression facilities.
	-5	On an accrual basis and exclusive of acquisitions.
	Major Customers. For the years ended December 31, 2013, 2012 and 2011, the Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):
		2013
		Sales			% of Revenue
	Plains Marketing, L.P.	$	491,258		24.8	%
	Shell Trading (US) Company	$	347,422		17.5	%
	Atlas Pipeline Mid-Continent West OK LLC	$	211,838		10.7	%
		2012
		Sales			% of Revenue
	Occidental Petroleum Corporation	$	829,081		30.4	%
	Plains Marketing, L.P.	$	426,339		15.6	%
	Enterprise Crude Oil, LLC	$	394,162		14.4	%
		2011
		Sales			% of Revenue
Enterprise Crude Oil, LLC	$	319,277		22.6	%
Plains Marketing, L.P.	$	276,285		19.5	%
Plains Marketing, L.P., Shell Trading (US) Company, Atlas Pipeline Mid-Continent West OK LLC, and Enterprise Crude Oil, LLC are purchasers of oil, natural gas and NGLs sold by the Company’s exploration and production segment. Sales to Occidental primarily represent construction contract revenues recognized by the exploration and production segment in conjunction with substantial completion of the Century Plant.

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Statements Disclosure [Abstract]	'
Condensed Consolidating Financial Information	'
	Condensed Consolidating Financial Information
	The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. As of December 31, 2013, the subsidiary guarantors, which are 100% owned by the Company, have jointly and severally guaranteed, on a full, unconditional and unsecured basis, the Company’s outstanding Senior Fixed Rate Notes. The 8.625% Senior Notes due 2015 and Senior Floating Rate Notes, prior to their purchase and redemption in 2011 and 2012, respectively, 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, a revision 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 are 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 revisions 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 years ended December 31, 2012 and 2011.
			Year Ended December 31,
			2012				2011
			(In thousands)
	Parent		$	945,448			$	288,415
	Guarantors		$	(809,099	)		$	(172,927	)
	Non-Guarantors		$	(136,349	)		$	(115,488	)
	Condensed Consolidating Balance Sheets
		December 31, 2013
		Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
		(In thousands)
	ASSETS
	Current assets
	Cash and cash equivalents	$	805,505			$	1,013			$	8,145		$	—		$	814,663
	Accounts receivable, net	—				326,345				22,873			—			349,218
	Intercompany accounts receivable	153,325				982,524				70,107			(1,205,956		)	—
	Derivative contracts	—				7,796				14,748			(9,765		)	12,779
	Prepaid expenses	—				39,165				88			—			39,253
	Other current assets	1,376				24,410				124			—			25,910
	Total current assets	960,206				1,381,253				116,085			(1,215,721		)	1,241,823
	Property, plant and equipment, net	—				5,181,128				1,182,132			(55,585		)	6,307,675
	Investment in subsidiaries	5,237,057				(102,848		)		—			(5,134,209		)	—
	Derivative contracts	—				12,650				9,585			(8,109		)	14,126
	Other assets	61,923				65,123				27			(5,902		)	121,171
	Total assets	$	6,259,186			$	6,537,306			$	1,307,829		$	(6,419,526	)	$	7,684,795
	LIABILITIES AND EQUITY
	Current liabilities
	Accounts payable and accrued expenses	$	207,572			$	601,074			$	3,842		$	—		$	812,488
	Intercompany accounts payable	967,365				180,910				57,018			(1,205,293		)	—
	Derivative contracts	—				44,032				—			(9,765		)	34,267
	Asset retirement obligations	—				87,063				—			—			87,063
	Total current liabilities	1,174,937				913,079				60,860			(1,215,058		)	933,818
	Long-term debt	3,200,809				—				—			(5,902		)	3,194,907
	Derivative contracts	—				28,673				—			(8,109		)	20,564
	Asset retirement obligations	—				337,054				—			—			337,054
	Other long-term obligations	1,382				21,443				—			—			22,825
	Total liabilities	4,377,128				1,300,249				60,860			(1,229,069		)	4,509,168
	Equity
	SandRidge Energy, Inc. stockholders’ equity	1,882,058				5,237,057				1,246,969			(6,540,274		)	1,825,810
	Noncontrolling interest	—				—				—			1,349,817			1,349,817
	Total equity	1,882,058				5,237,057				1,246,969			(5,190,457		)	3,175,627
	Total liabilities and equity	$	6,259,186			$	6,537,306			$	1,307,829		$	(6,419,526	)	$	7,684,795
		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
Condensed Consolidating Statements of Operations
	Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2013
Total revenues	$	—			$	1,675,481			$	308,300		$	(393	)	$	1,983,388
Expenses
Direct operating expenses	—				655,101				29,143			(1,414		)	682,830
General and administrative	329				323,808				6,288			—			330,425
Depreciation, depletion, amortization and accretion	—				581,435				85,210			—			666,645
Impairment	—				15,038				11,242			—			26,280
Loss on derivative contracts	—				24,702				22,421			—			47,123
Loss on sale of assets	—				291,743				107,343			—			399,086
Total expenses	329				1,891,827				261,647			(1,414		)	2,152,389
(Loss) income from operations	(329		)		(216,346		)		46,653			1,021			(169,001		)
Equity earnings from subsidiaries	(188,850		)		3,075				—			185,775			—
Interest (expense) income, net	(271,193		)		959				—			—			(270,234		)
Loss on extinguishment of debt	(82,005		)		—				—			—			(82,005		)
Other income (expense), net	—				23,462				(3,728		)	(7,289		)	12,445
(Loss) income before income taxes	(542,377		)		(188,850		)		42,925			179,507			(508,795		)
Income tax expense	5,244				—				440			—			5,684
Net (loss) income	(547,621		)		(188,850		)		42,485			179,507			(514,479		)
Less: net income attributable to noncontrolling interest	—				—				—			39,410			39,410
Net (loss) income attributable to SandRidge Energy, Inc.	$	(547,621	)		$	(188,850	)		$	42,485		$	140,097		$	(553,889	)
	Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2012
Total revenues	$	—			$	2,435,064			$	404,418		$	(108,517	)	$	2,730,965
Expenses
Direct operating expenses	—				1,393,006				146,416			(107,750		)	1,431,672
General and administrative	515				234,954				7,635			(1,422		)	241,682
Depreciation, depletion, amortization and accretion	—				570,786				87,044			—			657,830
Impairment	—				236,671				79,333			—			316,004
Gain on derivative contracts	—				(198,732		)		(42,687		)	—			(241,419		)
Total expenses	515				2,236,685				277,741			(109,172		)	2,405,769
(Loss) income from operations	(515		)		198,379				126,677			655			325,196
Equity earnings from subsidiaries	426,264				20,667				—			(446,931		)	—
Interest (expense) income	(303,510		)		725				(564		)	—			(303,349		)
Gain on sale of subsidiary	55,585				—				—			(55,585		)	—
Bargain purchase gain	—				122,696				—			—			122,696
Loss on extinguishment of debt	(3,075		)		—				—			—			(3,075		)
Other income, net	—				83,797				—			(79,056		)	4,741
Income before income taxes	174,749				426,264				126,113			(580,917		)	146,209
Income tax (benefit) expense	(100,808		)		—				446			—			(100,362		)
Net income	275,557				426,264				125,667			(580,917		)	246,571
Less: net income attributable to noncontrolling interest	—				—				—			105,000			105,000
Net income attributable to SandRidge Energy, Inc.	$	275,557			$	426,264			$	125,667		$	(685,917	)	$	141,571
	Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2011
Total revenues	$	—			$	1,285,854			$	268,427		$	(139,068	)	$	1,415,213
Expenses
Direct operating expenses	—				475,578				158,697			(135,712		)	498,563
General and administrative	416				144,574				4,670			(1,017		)	148,643
Depreciation, depletion, amortization, accretion and impairment	—				351,708				31,361			—			383,069
Gain on derivative contracts	—				(33,749		)		(10,326		)	—			(44,075		)
Total expenses	416				938,111				184,402			(136,729		)	986,200
(Loss) income from operations	(416		)		347,743				84,025			(2,339		)	429,013
Equity earnings from subsidiaries	379,177				28,751				—			(407,928		)	—
Interest expense	(236,109		)		(197		)		(1,026		)	—			(237,332		)
Loss on extinguishment of debt	(38,232		)		—				—			—			(38,232		)
Other income, net	—				2,880				242			—			3,122
Income before income taxes	104,420				379,177				83,241			(410,267		)	156,571
Income tax (benefit) expense	(5,984		)		—				167			—			(5,817		)
Net income	110,404				379,177				83,074			(410,267		)	162,388
Less: net income attributable to noncontrolling interest	—				—				—			54,323			54,323
Net income attributable to SandRidge Energy, Inc.	$	110,404			$	379,177			$	83,074		$	(464,590	)	$	108,065
Condensed Consolidating Statements of Cash Flows
	Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2013
Net cash (used in) provided by operating activities	$	(239,026	)		$	852,026			$	254,723		$	907		$	868,630
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—				(1,496,731		)		—			—			(1,496,731		)
Proceeds from sale of assets	—				2,566,742				17,373			—			2,584,115
Other	—				89,606				3,197			(109,831		)	(17,028		)
Net cash provided by (used in) investing activities	—				1,159,617				20,570			(109,831		)	1,070,356
Cash flows from financing activities
Repayments of borrowings	(1,115,500		)		—				—			—			(1,115,500		)
Premium on debt redemption	(61,997		)		—				—			—			(61,997		)
Distributions to owners	—				—				(299,675		)	93,205			(206,470		)
Dividends paid—preferred	(55,525		)		—				—			—			(55,525		)
Intercompany borrowings (advances), net	2,009,146				(2,018,212		)		9,066			—			—
Other	(31,821		)		6,660				14,845			15,719			5,403
Net cash provided by (used in) financing activities	744,303				(2,011,552		)		(275,764		)	108,924			(1,434,089		)
Net increase (decrease) in cash and cash equivalents	505,277				91				(471		)	—			504,897
Cash and cash equivalents at beginning of year	300,228				922				8,616			—			309,766
Cash and cash equivalents at end of year	$	805,505			$	1,013			$	8,145		$	—		$	814,663
	Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2012 (Revised)
Net cash provided by operating activities	$	285,567			$	264,717			$	162,281		$	70,595		$	783,160
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—				(2,112,547		)		(33,825		)	—			(2,146,372		)
Acquisitions, net of cash received	(693,091		)		(147,649		)		(587,086		)	587,086			(840,740		)
Proceeds from sale of assets	129,830				942,675				1,333			(642,671		)	431,167
Other	(61,343		)		278,708				—			(217,365		)	—
Net cash used in investing activities	(624,604		)		(1,038,813		)		(619,578		)	(272,950		)	(2,555,945		)
Cash flows from financing activities
Proceeds from borrowings	1,850,344				—				—			—			1,850,344
Repayments of borrowings	(350,000		)		—				(16,029		)	—			(366,029		)
Proceeds from issuance of royalty trust units	—				—				587,086			—			587,086
Proceeds from the sale of royalty trust units	—				—				—			139,360			139,360
Distributions to unitholders	—				—				(274,980		)	93,253			(181,727		)
Dividends paid—preferred	(55,525		)		—				—			—			(55,525		)
Intercompany (advances) borrowings, net	(945,448		)		809,099				136,349			—			—
Other	(64,121		)		(34,518		)		30,258			(30,258		)	(98,639		)
Net cash provided by financing activities	435,250				774,581				462,684			202,355			1,874,870
Net increase in cash and cash equivalents	96,213				485				5,387			—			102,085
Cash and cash equivalents at beginning of year	204,015				437				3,229			—			207,681
Cash and cash equivalents at end of year	$	300,228			$	922			$	8,616		$	—		$	309,766
	Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2011 (Revised)
Net cash provided by (used in) operating activities	$	702,369			$	(221,992	)		$	(9,005	)	$	(12,418	)	$	458,954
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—				(1,726,131		)		(975		)	—			(1,727,106		)
Proceeds from sale of assets	—				1,776,907				26			(917,528		)	859,405
Other	—				(2,074		)		(917,528		)	884,974			(34,628		)
Net cash provided by (used in) investing activities	—				48,702				(918,477		)	(32,554		)	(902,329		)
Cash flows from financing activities
Proceeds from borrowings	2,033,000				—				—			—			2,033,000
Repayments of borrowings	(2,123,000		)		(6,302		)		(991		)	—			(2,130,293		)
Proceeds from issuance royalty trust units	—				—				917,528			—			917,528
Distributions to unitholders	—				—				(96,664		)	36,464			(60,200		)
Dividends paid—preferred	(56,742		)		—				—			—			(56,742		)
Intercompany (advances) borrowings, net	(288,415		)		172,927				115,488			—			—
Other	(64,638		)		6,538				(8,508		)	8,508			(58,100		)
Net cash (used in) provided by financing activities	(499,795		)		173,163				926,853			44,972			645,193
Net increase (decrease) in cash and cash equivalents	202,574				(127		)		(629		)	—			201,818
Cash and cash equivalents at beginning of year	1,441				564				3,858			—			5,863
Cash and cash equivalents at end of year	$	204,015			$	437			$	3,229		$	—		$	207,681

Supplemental_Information_on_Oi

Supplemental Information on Oil and Natural Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Oil and Gas Exploration and Production Industries Disclosures	'
	Supplemental Information on Oil and Natural Gas Producing Activities
	The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves.
	Capitalized Costs Related to Oil and Natural Gas Producing Activities
	The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):
		December 31,
		2013				2012				2011
	Oil and natural gas properties
	Proved	$	10,972,816			$	12,262,921			$	8,969,296
	Unproved	531,606				865,863				689,393
	Total oil and natural gas properties	11,504,422				13,128,784				9,658,689
	Less accumulated depreciation, depletion and impairment	(5,762,969		)		(5,231,182		)		(4,791,534		)
	Net oil and natural gas properties capitalized costs	$	5,741,453			$	7,897,602			$	4,867,155
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
	Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):
		Year Ended December 31,
		2013				2012				2011
	Acquisitions of properties
	Proved	$	21,130			$	1,761,556			$	58,190
	Unproved	100,242				377,185				320,361
	Exploration(1)	82,775				120,438				98,849
	Development(2)	1,131,269				1,704,991				1,296,903
	Total cost incurred	$	1,335,416			$	3,964,170			$	1,774,303
	____________________
	-1	Includes seismic costs of $6.7 million, $15.3 million and $4.9 million for 2013, 2012 and 2011, respectively.
	-2	Includes loss on the construction of the Century Plant of $50.0 million and $25.0 million for 2012 and 2011, respectively. See Note 11.
	Results of Operations for Oil and Natural Gas Producing Activities (Unaudited)
	The Company’s results of operations from oil and natural gas producing activities for each of the years 2013, 2012 and 2011 are shown in the following table (in thousands):
		Year Ended December 31,
		2013				2012				2011
	Revenues	$	1,820,278			$	1,759,282			$	1,226,794
	Expenses
	Production costs	548,719				524,364				368,946
	Depreciation and depletion	567,732				568,029				317,246
	Accretion of asset retirement obligations	36,777				28,996				9,368
	Total expenses	1,153,228				1,121,389				695,560
	Income before income taxes	667,050				637,893				531,234
	Benefit of income taxes(1)	(7,471		)		(437,595		)		(20,134		)
	Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	674,521			$	1,075,488			$	551,368
	____________________
	-1	Reflects the Company’s effective tax rate, including the partial valuation allowance releases.
	Oil, Natural Gas and NGL Reserve Quantities (Unaudited)
	Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
	The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:
	•	the quality and quantity of available data and the engineering and geological interpretation of that data;
	•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
	•	the accuracy of mandated economic assumptions such as the future prices of oil, natural gas and NGLs; and
	•	the judgment of the personnel preparing the estimates.
	Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.
	The table below represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Estimates of substantially all of the Company’s proved reserves have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.
	Cawley, Gillespie & Associates, Inc., (“CG&A”), Netherland, Sewell & Associates, Inc. (“Netherland Sewell”) and Lee Keeling and Associates, Inc. (“Lee Keeling”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2013, 2012 and 2011. CG&A, Netherland Sewell, and Lee Keeling are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. CG&A and Netherland Sewell prepared the estimates of proved reserves for a majority of the Company’s properties as of December 31, 2013. The remaining 13.9% of estimates of proved reserves was based on Company estimates.
	The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.
	2011 Activity. During 2011, excluding asset sales, the Company recognized an overall net increase in its proved oil reserves of approximately 37.6 MMBbls, primarily due to additional reserves of 52.4 MMBbls from extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent and the Central Basin Platform in the Permian Basin, offset by 10.0 MMBbls of production during 2011. Additionally, the Company recognized an overall net increase of 68.6 Bcf in its proved natural gas reserve quantities primarily due to 299.8 Bcf attributable to extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent and the Central Basin Platform in the Permian Basin, offset by revisions of 164.8 Bcf, primarily due to lower natural gas prices, and production of 69.3 Bcf. Continued low natural gas prices could result in additional negative revisions to the Company’s natural gas reserves.
	Sales of proved reserves during 2011 totaled 122.7 MMBoe primarily from the divestitures of certain Permian Basin properties and east Texas properties.
	2012 Activity. During 2012, excluding asset sales, the Company recognized an overall net increase in its proved oil and NGL reserves of approximately 67.9 MMBbls and 40.9 MMBbls, respectively, primarily due to additional reserves from extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent area and the Central Basin Platform in the Permian Basin. These increases to proved oil reserves were slightly offset by downward revisions of 22.3 MMBbls due to well performance in the Mid-Continent and Permian Basin during 2012. Additionally, the Company recognized an overall net increase of 60.5 Bcf in its proved natural gas reserve quantities primarily due to 489.3 Bcf attributable to extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent and the Central Basin Platform in the Permian Basin. These increases were partially offset by downward revisions of 538.2 Bcf, primarily due to lower natural gas prices, and, to a lesser extent, due to well performance in the Mid-Continent and Permian Basin during 2012 and production of 93.5 Bcf. Continued low natural gas prices could result in additional negative revisions to the Company’s natural gas reserves.
	Sales of proved reserves during 2012 totaled 23.6 MMBoe from the divestiture of the Company’s tertiary recovery properties.
	2013 Activity. The Company sold its Permian Properties in February 2013. Proved reserves were 198.9 MMBoe, 55% of which were proved developed reserves, for the Permian Properties at December 31, 2012. Estimated standardized measure of discounted cash flows for the Permian Properties, determined by allocating the Company's standardized measure of discounted cash flows to the Permian Properties based on the present value of discounted cash flows attributable to the Permian Properties relative to the Company's total present value of discounted cash flows was $2.5 billion. See Note 3 for additional information regarding the sale. The Company recognized an increase of 119.2 MMBoe in total reserves primarily attributable to extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent.
	The summary below presents changes in the Company’s estimated reserves for 2011, 2012 and 2013.
		Oil			NGL			Natural Gas
		(MBbls)			(MBbls)			(MMcf)(1)
	Proved developed and undeveloped reserves
	As of December 31, 2010	205,023			47,091			1,762,665
	Revisions of previous estimates	(6,159	)		(3,119	)		(164,845	)
	Acquisitions of new reserves	1,309			224			2,906
Extensions and discoveries	52,406			3,171			299,848
Sales of reserves in place	(28,137	)		(15,194	)		(476,212	)
Production	(9,992	)		(1,838	)		(69,306	)
As of December 31, 2011(2)	214,450			30,335			1,355,056
Revisions of previous estimates	(37,394	)		15,098			(538,214	)
Acquisitions of new reserves	31,470			683			202,995
Extensions and discoveries	89,656			27,259			489,302
Sales of reserves in place	(20,269	)		(3,287	)		(548	)
Production	(15,868	)		(2,094	)		(93,549	)
As of December 31, 2012(2)	262,045			67,994			1,415,042
Revisions of previous estimates	(13,969	)		3,717			(53,432	)
Acquisitions of new reserves	43			13			363
Extensions and discoveries	40,570			18,686			359,918
Sales of reserves in place	(131,769	)		(29,067	)		(228,229	)
Production	(14,279	)		(2,291	)		(103,233	)
As of December 31, 2013(2)	142,641			59,052			1,390,429
Proved developed reserves
As of December 31, 2010	73,111			18,854			784,292
As of December 31, 2011	101,578			17,150			670,382
As of December 31, 2012	136,605			33,785			896,701
As of December 31, 2013	83,893			35,807			951,609
Proved undeveloped reserves
As of December 31, 2010	131,912			28,237			978,373
As of December 31, 2011	112,872			13,185			684,674
As of December 31, 2012	125,440			34,209			518,341
As of December 31, 2013	58,748			23,245			438,820
____________________
-1	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
-2	Includes proved reserves attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 as shown in the table below:
	December 31,
	2013			2012			2011
Oil (MBbl)	13,569			17,340			17,018
NGL (MBbl)	4,737			5,132			1,782
Natural gas (MMcf)	69,693			94,543			45,500
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas (“ASC Topic 932”). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:
•	the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;
•	pricing is applied based upon 12-month average market prices at December 31, 2013, 2012 and 2011 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
	At December 31,
	2013				2012				2011
Oil (per barrel)	$	95.67			$	91.65			$	91.35
NGL (per barrel)	$	31.4			$	32.64			$	46.33
Natural gas (per Mcf)	$	3.65			$	2.29			$	4.06
•	future development and production costs are determined based upon actual cost at year-end;
•	the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
•	a discount factor of 10% per year is applied annually to the future net cash flows.
The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).
	At December 31,
	2013				2012				2011
Future cash inflows from production	$	19,937,484			$	29,482,544			$	26,494,942
Future production costs	(6,843,713		)		(8,899,465		)		(7,392,104		)
Future development costs(1)	(2,546,680		)		(4,021,051		)		(2,977,993		)
Future income tax expenses	(2,283,541		)		(3,721,509		)		(4,043,953		)
Undiscounted future net cash flows	8,263,550				12,840,519				12,080,892
10% annual discount	(4,245,939		)		(7,000,151		)		(6,864,555		)
Standardized measure of discounted future net cash flows(2)	$	4,017,611			$	5,840,368			$	5,216,337
____________________
-1	Includes abandonment costs.
-2	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 respectively.
The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
Present value as of December 31, 2010	$	3,683,515
Changes during the year
Revenues less production and other costs	(857,848		)
Net changes in prices, production and other costs	1,264,736
Development costs incurred	575,546
Net changes in future development costs	87,080
Extensions and discoveries	1,812,167
Revisions of previous quantity estimates	(345,965		)
Accretion of discount	455,501
Net change in income taxes	(833,841		)
Purchases of reserves in-place	44,934
Sales of reserves in-place	(558,257		)
Timing differences and other(1)	(111,231		)
Net change for the year	1,532,822
Present value as of December 31, 2011(2)	5,216,337
Changes during the year
Revenues less production and other costs	(1,234,918		)
Net changes in prices, production and other costs	(2,555,391		)
Development costs incurred	766,943
Net changes in future development costs	(45,397		)
Extensions and discoveries	2,092,423
Revisions of previous quantity estimates	(530,755		)
Accretion of discount	678,200
Net change in income taxes	11,433
Purchases of reserves in-place	1,708,301
Sales of reserves in-place	(410,415		)
Timing differences and other(1)	143,607
Net change for the year	624,031
Present value as of December 31, 2012(2)	5,840,368
Changes during the year
Revenues less production and other costs	(1,271,559		)
Net changes in prices, production and other costs	271,566
Development costs incurred	474,275
Net changes in future development costs	(207,729		)
Extensions and discoveries	1,406,102
Revisions of previous quantity estimates	(296,418		)
Accretion of discount	711,385
Net change in income taxes	477,328
Purchases of reserves in-place	1,628
Sales of reserves in-place	(3,172,187		)
Timing differences and other(1)	(217,148		)
Net change for the year	(1,822,757		)
Present value as of December 31, 2013(2)	$	4,017,611
____________________
-1	The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.
-2	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012, and 2011 respectively.

Quarterly_Financial_Results_Un

Quarterly Financial Results (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Financial Results (Unaudited)	'
	Quarterly Financial Results (Unaudited)
	The Company’s operating results for each quarter of 2013 and 2012 are summarized below (in thousands, except per share data).
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	2013
	Total revenues	$	511,690		$	512,987		$	493,603		$	465,108
	(Loss) income from operations(1)(2)(3)	$	(359,526	)	$	86,458		$	6,088		$	97,979
	Net (loss) income(1)(2)(3)	$	(531,259	)	$	24,685		$	(57,002	)	$	49,097
	(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(1)(2)(3)	$	(493,221	)	$	(34,317	)	$	(87,074	)	$	5,198
	(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders(4)
	Basic	$	(1.03	)	$	(0.07	)	$	(0.18	)	$	0.01
	Diluted	$	(1.03	)	$	(0.07	)	$	(0.18	)	$	0.01
	2012
	Total revenues	$	381,635		$	478,434		$	532,798		$	1,338,098
	(Loss) income from operations(5)(6)	$	(151,656	)	$	762,413		$	(75,871	)	$	(209,690	)
	Net (loss) income(5)(6)(7)	$	(216,224	)	$	917,076		$	(159,752	)	$	(294,529	)
	(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(5)(6)(7)	$	(232,059	)	$	804,191		$	(184,301	)	$	(301,785	)
	(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders(4)
	Basic	$	(0.58	)	$	1.74		$	(0.39	)	$	(0.63	)
	Diluted	$	(0.58	)	$	1.46		$	(0.39	)	$	(0.63	)
	____________________
	-1	Includes a $10.6 million impairment of various drilling assets and a $2.9 million impairment of a corporate asset in the second quarter of 2013 and a $2.1 million and $10.0 million impairment of certain midstream inventory, natural gas compressors, gas treating plants and a CO2 compression station in the second and fourth quarters of 2013, respectively.
	-2	Includes loss (gain) on commodity derivative contracts of $40.9 million, $(103.7) million, $132.8 million and $(22.9) million for the first, second, third and fourth quarters, respectively.
	-3	Includes loss on sale of Permian Properties of $398.9 million in the first quarter of 2013.
	-4	(Loss applicable) income available per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of (loss applicable) income available per share to common stockholders for each of the four quarters may not equal the fiscal year amount.
	-5	Includes a $235.4 million goodwill impairment and a $79.3 million impairment of gas treating plants and CO2 compression facilities in the fourth quarter of 2012.
	-6	Includes loss (gain) on commodity derivative contracts of $254.6 million, $(669.9) million, $193.5 million and $(19.6) million for the first, second, third and fourth quarters, respectively.
	-7	Includes adjustments of $(4.8) million retrospectively applied to the second quarter of 2012 as a result of measurement period adjustments made to the preliminary purchase price allocation for the Dynamic Acquisition in the fourth quarter of 2012.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Nature of Business	'
	Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on exploration and production activities in the Mid-Continent region of the United States. The Company owns and operates additional interests in west Texas and owned interests in the Gulf of Mexico and Gulf Coast until February 2014, as discussed in Note 21. The Company also operates businesses and infrastructure systems that are complementary to its primary exploration and production activities, including gas gathering and processing facilities, marketing operations, a saltwater disposal system, an electrical transmission system and a drilling rig and related oil field services business.
Principles of Consolidation	'
	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. Noncontrolling interest represents third-party ownership interests in the Company’s subsidiaries and consolidated VIEs and is included as a component of equity in the consolidated balance sheet and consolidated statement of changes in equity. All significant intercompany accounts and transactions have been eliminated in consolidation.
Variable Interest Entities	'
	Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. 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. In addition to the VIEs that the Company consolidates, the Company also holds a variable interest in another VIE that is not consolidated as it was determined that the Company is not the primary beneficiary. The Company monitors both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 4 for discussion of the Company’s significant associated VIEs.
Reclassifications	'
	Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.
Use of Estimates	'
	Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“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, natural gas and NGL 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.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.
Accounts Receivable, Net	'
	Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the exploration, production and treating services for oil and natural gas. An allowance for doubtful accounts has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements.
Fair Value Of Nonfinancial Assets and Liabilities	'
	Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5.
Derivative Financial Instruments	'
	Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates.
	The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statement of cash flows. See Note 13 for further discussion of the Company’s derivatives.
Oil and Natural Gas Operations	'
	Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized internal costs of $74.7 million, $61.3 million and $37.1 million to the full cost pool in 2013, 2012 and 2011, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
	Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.
	Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down is not reversible at a later date.
	The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.
	Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.
Property, Plant and Equipment, Net	'
	Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 10 to 39 years for buildings and 3 to 30 years for equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statement of operations.
	Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If any asset or asset group is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. See Note 8 for further discussion of impairments.
Capitalized Interest	'
	Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time.
Debt Issuance Costs	'
	Debt Issuance Costs. The Company amortizes debt issuance costs related to its long-term debt as interest expense over the scheduled maturity period of the related debt. The Company includes unamortized debt issuance costs in other assets in the consolidated balance sheet. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.
Restricted Deposits	'
	Restricted Deposits. Restricted deposits represent bank trust and escrow accounts required by the Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, surety bond underwriters, purchase agreements or other settlement agreements to satisfy the Company’s eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. Such restricted deposits are included in other assets in the accompanying consolidated balance sheets.
	Restricted deposits may also include escrow deposits received on pending sales of oil and natural gas properties. Amounts are considered restricted until the transaction closes.
Goodwill	'
	Goodwill. In conjunction with its acquisition of Arena Resources, Inc. (“Arena”) in 2010, the Company recorded goodwill equal to the excess of the consideration paid over the fair value of identifiable net assets acquired. Goodwill was assigned to the Company’s exploration and production segment and was not deductible for income tax purposes.
	Entry by the Company in December 2012 into an agreement to sell the Permian Properties was determined to be a triggering event. As such, an impairment test was performed as of December 31, 2012, resulting in the full impairment of goodwill. See Note 8 for further discussion of the goodwill impairment test performed.
Investments	'
	Investments. Investments in marketable equity securities have been designated as available for sale and measured at fair value pursuant to the fair value option which requires unrealized gains and losses be reported in earnings.
Asset Retirement Obligations	'
	Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statement of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 14 for further discussion of the Company’s asset retirement obligations.
	In certain instances, the Company is required to maintain deposits to escrow accounts for future plugging and abandonment obligations. See Restricted Deposits discussed above.
Revenue Recognition	'
	The Company recognizes revenues and expenses generated from daywork and footage drilling contracts as the services are performed as the Company does not bear the risk of completion of the well. The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another are recognized at the time mobilization services are performed.
	In general, natural gas purchased and sold by the midstream business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Midstream services revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determined and collectability is reasonably assured. Revenues from third-party midstream services are presented on a gross basis, since the Company acts as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold.
	Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statement of operations.
Natural Gas Balancing	'
	The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves.
Revenue Recognition, Construction Contracts	'
	The Company accounted for its two construction contracts, discussed in Note 11, using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract losses are recorded at the time it is determined that a loss will be incurred. The contract loss on the Century Plant construction contract was recorded as a development cost within the Company’s full cost pool. Contract gains, if any, are recorded upon substantial completion of the construction project.
Stock-based Compensation	'
	Stock-Based Compensation. The Company grants restricted stock awards to members of its Board of Directors (the “Board”) and its employees. Such awards and the related stock-based compensation cost are measured based on the calculated fair value of the award on the grant date. The expense, net of estimated forfeitures, is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award. To the extent stock-based compensation cost relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statement of operations. The related excess tax benefit received upon vesting of restricted stock, if any, is reflected in the consolidated statement of cash flows as a financing activity. The related excess tax expense due upon vesting of restricted stock, if any, is reflected in the consolidated statement of cash flows as an operating activity.
	Performance Unit Compensation. The Company awards performance units, which contain a market-based performance component and will be settled in cash upon vesting, to certain members of senior management. The Company recognizes a liability and expense for performance unit compensation for the portion earned over the requisite service period in an amount equal to the fair value of the performance units granted. Changes in the fair value of the units for which service has been met are recognized as compensation expense with a corresponding adjustment to the liability. To the extent performance unit compensation cost relates to those directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statement of operations.
Advertising Costs	'
	Advertising Costs. The Company expenses advertising costs as incurred.
Income Taxes	'
	Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.
	The Company has elected an accounting policy in which interest and penalties on income taxes are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.
Earnings per Share	'
	Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculation consist of unvested restricted stock awards, using the treasury method, and convertible preferred stock. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 19 for the Company’s earnings per share calculation.
Commitments and Contingencies	'
	Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 15 for discussion of the Company’s commitments and contingencies.
Concentration of Risk	'
	Concentration of Risk. All of the Company’s derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market 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 derivative transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its derivative counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty.
	A default by the Company under its senior secured revolving credit facility (the “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 counterparties, which allow 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 derivative contracts. 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, if any, to such counterparty under the Company’s senior credit facility.
	The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.
	The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. See Note 22 for information regarding the Company’s major customers. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect the Company’s ability to sell the oil, natural gas and NGLs it produces.
Recently Adopted Accounting Pronouncements	'
	Recently Adopted Accounting Pronouncements. In December 2011, the Financial Accounting Standards Board 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 13 for the Company’s derivative disclosures.
Fair Value Transfers	'
	The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred.

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Supplemental Cash Flow Information	'
	Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Years Ended December 31,
		2013			2012			2011
		(In thousands)
	Supplemental Disclosure of Cash Flow Information
	Cash paid for interest, net of amounts capitalized	$	(274,850	)	$	(257,152	)	$	(224,127	)
	Cash paid for income taxes	(4,610		)	(1,324		)	(2,083		)
	Supplemental Disclosure of Noncash Investing and Financing Activities
	Deposit on pending sale	$	(255,000	)	$	255,000		$	—
	Change in accrued capital expenditures	72,848			(27,610		)	(89,388		)
	Adjustment to oil and natural gas properties for contract loss	—			50,000			25,000
	Asset retirement costs capitalized	5,078			7,479			5,716
	Common stock issued in connection with acquisition	—			542,138			—

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2013
Permian Properties	'
Business Acquisitions and Dispositions [Line Items]	'
Disposal, Revenue and Expense Information	'
	The following table presents revenues and direct operating expenses of the Permian Properties included in the accompanying consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011 (in thousands):
			Year Ended December 31,
			2013(1)				2012				2011
	Revenues		$	68,027			$	566,075			$	614,666
	Direct operating expenses		$	17,453			$	130,337			$	144,066
	____________________
	-1	Includes revenues and direct operating expenses through February 26, 2013, the date of sale.
Dynamic Acquisition	'
Business Acquisitions and Dispositions [Line Items]	'
Assets Acquired and Liabilities Assumed	'
	In the second quarter of 2013, the Company completed its valuation of the Dynamic Acquisition with no adjustments in 2013 to the valuation of assets acquired and liabilities assumed, which are included in the following table (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 long-term 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.
	-7	The bargain purchase gain resulted 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.
Unaudited Pro Forma Results of Operations	'
	The pro forma results of operations do not include any cost savings or other synergies that resulted from the Dynamic Acquisition or any estimated costs incurred to integrate Dynamic.
		Year Ended December 31,
		2012(1)				2011(2)
		(In thousands, except per share data)
		(Unaudited)
	Revenues	$	2,908,899			$	1,932,945
	Net income	$	39,563			$	509,644
	(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(120,962	)		$	399,278
	(Loss) earnings per common share
	Basic	$	(0.25	)		$	0.84
	Diluted	$	(0.25	)		$	0.8
	____________________
	-1	Pro forma net income, loss applicable to SandRidge Energy, Inc. common stockholders and loss per common share exclude a $122.7 million bargain purchase gain, a $100.3 million partial valuation allowance release included in income tax benefit, $10.9 million of fees incurred to secure financing for the Dynamic Acquisition included in interest expense and $13.0 million of transaction costs incurred and included in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2012.
	-2	Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and earnings per common share include a $122.7 million bargain purchase gain, a $100.3 million partial valuation allowance release, $10.9 million of fees incurred to secure financing and $13.0 million of transaction costs.
Gulf of Mexico Properties	'
Business Acquisitions and Dispositions [Line Items]	'
Assets Acquired and Liabilities Assumed	'
	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 obligations	(55,443		)
	Total identifiable net assets	$	43,282
Unaudited Pro Forma Results of Operations	'
	The 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.
		Year Ended December 31,
		2012				2011
		(In thousands, except per share data)
		(Unaudited)
	Revenues	$	2,759,381			$	1,502,325
	Net income	$	247,035			$	191,073
	Income available to SandRidge Energy, Inc. common stockholders	$	86,510			$	81,167
	Earnings per common share
	Basic	$	0.19			$	0.2
	Diluted	$	0.19			$	0.2
Drilling Carry Transaction Activities	'
Business Acquisitions and Dispositions [Line Items]	'
Drilling And Completion Costs Associated With Sale Of Working Interests	'
	These transactions and the associated drilling carries as of December 31, 2013 were as follows:
	Partner		Closing Date		Total Drilling Carry				Drilling Carry Recorded				Drilling Carry Remaining
					(In thousands)
	Atinum MidCon I, LLC		September 2011		$	250,000			$	250,000			$	—
	Repsol E&P USA, Inc.		Jan-12		750,000				544,400				205,600
					$	1,000,000			$	794,400			$	205,600

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2013
Variable Interest Entity [Line Items]	'
Open Oil and Natural Gas Commodity Derivative Contracts	'
	At December 31, 2013, the Company’s open commodity derivative contracts consisted of the following:
	Oil Price Swaps
		Notional (MBbls)			Weighted Average
					Fixed Price
	January 2014 — December 2014	8,813			$	92.98
	January 2015 — December 2015	7,979			$	86.13
	Natural Gas Price Swaps
		Notional (MMcf)			Weighted Average
					Fixed Price
	January 2014 — December 2014	35,490			$	4.2
	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
	January 2014 — December 2014	937			$4.00	—	$7.78
	January 2015 — December 2015	1,010			$4.00	—	$8.55
Grey Ranch Plant, L.P	'
Variable Interest Entity [Line Items]	'
Assets and Liabilities Included in Consolidated Balance Sheets	'
	GRLP’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying consolidated balance sheets at December 31, 2013 and 2012 consisted of the following (in thousands):
		December 31,
		2013				2012
	Cash and cash equivalents	$	132			$	1,080
	Accounts receivable, net	16				20
	Prepaid expenses	32				64
	Other current assets	109				109
	Total current assets	289				1,273
	Other property, plant and equipment, net	1,163				1,246
	Total assets	$	1,452			$	2,519
	Accounts payable and accrued expenses	$	129			$	274
	Total liabilities	$	129			$	274
Royalty Trusts	'
Variable Interest Entity [Line Items]	'
Royalty Trust Initial Public Offerings	'
	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 thousands)		$	336,893			$	580,635			$	587,087
	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)		12/31/30				3/31/31				12/31/31
	____________________
	-1	Subsequent to the initial public offerings, the Company sold common units of the Royalty Trusts 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 the Royalty Trust unitholders.
Royalty Trusts Distributions	'
	The Royalty Trusts declared and paid quarterly distributions during the years ended December 31, 2013, 2012 and 2011 as follows (in thousands):
			Year Ended December 31,
			2013(1)				2012(2)				2011(2)
	Total distributions		$	299,674			$	274,979			$	91,162
	Distributions to third-party unitholders		$	206,470			$	181,727			$	57,449
	____________________
	-1	Subordination thresholds were not met for the Mississippian Trust I’s second and third quarter 2013 distributions or for the Permian Trust’s second quarter 2013 distribution, resulting in reduced distributions to the Company on its subordinated units for these periods.
	-2	The Company received incentive distributions from the Mississippian Trust I during the first and second quarters of 2012 and the third quarter of 2011.
Open Oil and Natural Gas Commodity Derivative Contracts	'
	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 Royalty Trust Derivatives Agreements
		Notional (MBbls)			Weighted Average
					Fixed Price
	January 2014 — December 2014	1,862			$	100.7
	January 2015 — December 2015	630			$	101.03
	Natural Gas Collars Underlying the Royalty Trust Derivatives Agreements
		Notional (MMcf)			Collar Range
	January 2014 — December 2014	937			$	4		—	$	7.78
	January 2015 — December 2015	1,010			$	4		—	$	8.55
	Oil Price Swaps Underlying the Derivatives Agreements and Novated to the Royalty Trusts
		Notional (MBbls)			Weighted Average
					Fixed Price
	January 2014 — December 2014	991			$	100.79
	January 2015 — March 2015	141			$	100.9
Assets and Liabilities Included in Consolidated Balance Sheets	'
	The Royalty Trusts’ assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying consolidated balance sheets at December 31, 2013 and 2012 consisted of the following (in thousands):
		December 31,
		2013				2012
	Cash and cash equivalents(1)	$	7,912			$	7,445
	Accounts receivable	22,540				28,596
	Derivative contracts	4,983				10,286
	Total current assets	35,435				46,327
	Investment in royalty interests(2)	1,325,942				1,325,942
	Less: accumulated depletion	(186,095		)		(103,746		)
		1,139,847				1,222,196
	Derivative contracts	1,476				7,660
	Total assets	$	1,176,758			$	1,276,183
	Accounts payable and accrued expenses	$	3,393			$	1,101
	Total liabilities	$	3,393			$	1,101
	____________________
	-1	Includes $3.0 million held by the trustee at December 31, 2013 and 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 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 at the time of conveyance.
Royalty Trusts Ownership Interest	'
	The Company’s beneficial interests in the Royalty Trusts at December 31, 2013 and 2012 were as follows:
		December 31,
		2013			2012
	Mississippian Trust I	26.9	%		26.9	%
	Permian Trust	28.5	%		30.5	%
	Mississippian Trust II	37.6	%		39.9	%
Pinon Gathering Company LLC	'
Variable Interest Entity [Line Items]	'
Amounts Due To/From PGC	'
	Amounts due from and due to PGC as of December 31, 2013 and 2012 included in the accompanying consolidated balance sheets are as follows (in thousands):
		December 31,
		2013				2012
	Accounts receivable due from PGC	$	741			$	1,976
	Accounts payable due to PGC	$	3,634			$	5,053

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]	'
Assets and Liabilities Measured at Fair Value on Recurring Basis	'
	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):
	December 31, 2013
		Fair Value Measurements												Netting(1)			Assets/Liabilities at Fair Value
		Level 1				Level 2				Level 3
	Assets
	Restricted deposits	$	27,955			$	—			$	—			$	—		$	27,955
	Commodity derivative contracts	—				50,274				—				(23,369		)	26,905
	Investments	13,708				—				—				—			13,708
		$	41,663			$	50,274			$	—			$	(23,369	)	$	68,568
	Liabilities
	Commodity derivative contracts	$	—			$	78,200			$	—			$	(23,369	)	$	54,831
		$	—			$	78,200			$	—			$	(23,369	)	$	54,831
	December 31, 2012
		Fair Value Measurements												Netting(1)			Assets/Liabilities at Fair Value
		Level 1				Level 2				Level 3
	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.
Reconciliation of Financial Assets and Liabilities Measured at Fair Value on Recurring Basis using Significant Unobservable Inputs	'
	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 years ended December 31, 2011, 2012 and 2013 (in thousands):
			Commodity Derivative Contracts				Interest Rate Swaps
											Total
	Balance of Level 3 at December 31, 2010		$	(205,860	)		$	(16,694	)		$	(222,554	)
	Gain (loss) on derivative contracts		44,075				(3,168		)		40,907
	Cash paid on settlements		50,713				9,414				60,127
	Transfers(1)		106,820				10,448				117,268
	Balance of Level 3 at December 31, 2011		$	(4,252	)		$	—			$	(4,252	)
	Loss on derivative contracts		(5,460		)		—				(5,460		)
	Purchases		5,697				—				5,697
	Cash paid on settlements		3,503				—				3,503
	Balance of Level 3 at December 31, 2012		$	(512	)		$	—			$	(512	)
	Loss on derivative contracts		(133		)		—				(133		)
	Cash paid on settlements		645				—				645
	Balance of Level 3 at December 31, 2013		$	—			$	—			$	—
	____________________
	-1	Fair values related to the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap were transferred from Level 3 to Level 2 in the fourth quarter of 2011 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the years ended December 31, 2013 and 2012, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.
Estimated Fair Value and Carrying Value of Senior Notes	'
	The estimated fair values and carrying values of the Company’s senior notes at December 31, 2013 and 2012 were as follows (in thousands):
		December 31, 2013								December 31, 2012
		Fair Value				Carrying Value				Fair Value				Carrying Value
	9.875% Senior Notes due 2016(1)	$	—			$	—			$	392,913			$	356,657
	8.0% Senior Notes due 2018	—				—				790,313				750,000
	8.75% Senior Notes due 2020(2)	486,000				444,736				490,500				444,127
	7.5% Senior Notes due 2021(3)	1,230,813				1,178,922				1,257,250				1,179,328
	8.125% Senior Notes due 2022	795,000				750,000				823,125				750,000
	7.5% Senior Notes due 2023(4)	837,375				821,249				882,750				820,971
	____________________
	-1	Carrying value is net of $8,843 discount at December 31, 2012.
	-2	Carrying value is net of $5,264 and $5,873 discount at December 31, 2013 and 2012, respectively.
	-3	Carrying value includes a premium, applicable to notes issued in August 2012, of $3,922 and $4,328 at December 31, 2013 and 2012, respectively.
	-4	Carrying value is net of $3,751 and $4,029 discount at December 31, 2013 and 2012, respectively.
Fair Value Measurements Level 3	'
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]	'
Significant Unobservable Inputs	'
	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 2013.
	Unobservable Input		Range				Weighted Average		Fair Value
			(Price per Bbl)						(In thousands)
	Oil basis differential forward curve		$10.00	–	$21.98		$14.74		$	(512	)

Accounts_Receivable_Tables

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2013
Accounts Receivable, Net, Current [Abstract]	'
Summary of Accounts Receivable	'
	A summary of accounts receivable is as follows (in thousands):
		December 31,
		2013			2012
	Oil, natural gas and NGL sales	$	166,157		$	215,450
	Joint interest billing	168,596			202,405
	Oil and natural gas services	17,904			21,186
	Insurance receivable	2,500			4,590
	Related party	—			978
	Other	5,122			6,532
		360,279			451,141
	Less: allowance for doubtful accounts	(11,061		)	(5,635		)
	Total accounts receivable, net	$	349,218		$	445,506
Balance and Activity in Allowance for Doubtful Accounts	'
	The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2013, 2012 and 2011 (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Allowance for doubtful accounts at January 1	$	5,635		$	3,906		$	1,503
	Additions charged to costs and expenses(1)	5,497			1,735			2,511
	Deductions(2)	(71		)	(6		)	(108		)
	Allowance for doubtful accounts at December 31	$	11,061		$	5,635		$	3,906
	____________________
	-1	Includes $2.7 million of allowance for receivables deemed uncollectible at December 31, 2013 primarily due to bankruptcy status of customers.
	-2	Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established.

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	Property, plant and equipment consists of the following (in thousands):
		December 31,
		2013			2012
	Oil and natural gas properties
	Proved(1)	$	10,972,816		$	12,262,921
	Unproved	531,606			865,863
	Total oil and natural gas properties	11,504,422			13,128,784
	Less accumulated depreciation, depletion and impairment	(5,762,969		)	(5,231,182		)
	Net oil and natural gas properties capitalized costs	5,741,453			7,897,602
	Land	18,423			17,927
	Non-oil and natural gas equipment(2)	600,603			643,370
	Buildings and structures(3)	233,405			205,349
	Total	852,431			866,646
	Less accumulated depreciation and amortization	(286,209		)	(284,271		)
	Other property, plant and equipment, net	566,222			582,375
	Total property, plant and equipment, net	$	6,307,675		$	8,479,977
	____________________
	-1	Includes cumulative capitalized interest of approximately $23.4 million and $11.7 million at December 31, 2013 and 2012, respectively.
	-2	Includes cumulative capitalized interest of approximately $4.3 million at both December 31, 2013 and 2012.
	-3	Includes cumulative capitalized interest of approximately $12.0 million and $7.1 million at December 31, 2013 and 2012, respectively.
Capitalized Costs of Unproved Properties Excluded from Amortization	'
	The following table summarizes the costs, by year incurred, related to unproved properties and pipe inventory, which were excluded from oil and natural gas properties subject to amortization at December 31, 2013 (in thousands):
					Year Cost Incurred
		Total			2013			2012		2011		2010 and Prior
	Property acquisition	$	515,849		$	114,252		$	291,999	$	34,164	$	75,434
	Exploration(1)	61,327			48,764			5,479		3,598		3,486
	Total costs incurred	$	577,176		$	163,016		$	297,478	$	37,762	$	78,920
	____________________
	-1	Includes $45.6 million of pipe inventory costs incurred ($42.6 million in 2013, $2.8 million in 2012 and $0.2 million in 2010 and prior years).

Other_Assets_Tables

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]	'
Other Assets	'
	Other assets consist of the following (in thousands):
		December 31,
		2013		2012
	Debt issuance costs, net of amortization(1)	$	61,923	$	83,643
	Restricted deposits	27,955		27,947
	Notes receivable on asset retirement obligations	11,640		11,433
	Investments	13,708		10,348
	Other	5,945		10,881
	Total other assets	$	121,171	$	144,252
	____________________
	-1	In 2013, the unamortized debt issuance costs associated with the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018 were written off at the time the Company redeemed these notes. See Note 12 for discussion of the senior note redemptions.

Accounts_Payable_and_Accrued_E1

Accounts Payable and Accrued Expenses (Tables)	12 Months Ended
	Dec. 31, 2013
Accounts Payable and Accrued Liabilities, Current [Abstract]	'
Accounts Payable and Accrued Expenses	'
	Accounts payable and accrued expenses consist of the following (in thousands):
		December 31,
		2013		2012
	Accounts payable and other accrued expenses	$	341,008	$	461,067
	Accrued interest	80,740		92,125
	Production payable	127,647		97,245
	Drilling advances	184,203		68,742
	Payroll and benefits	59,785		29,811
	Convertible perpetual preferred stock dividends	16,572		16,572
	Related party	2,533		982
	Total accounts payable and accrued expenses	$	812,488	$	766,544

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-term debt consists of the following (in thousands):
		December 31,
		2013		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 $5,264 and $5,873 discount, respectively	444,736		444,127
	7.5% Senior Notes due 2021, including a premium of $3,922 and $4,328, respectively	1,178,922		1,179,328
	8.125% Senior Notes due 2022	750,000		750,000
	7.5% Senior Notes due 2023, net of $3,751 and $4,029 discount, respectively	821,249		820,971
	Total debt	3,194,907		4,301,083
	Less: current maturities of long-term debt	—		—
	Long-term debt	$	3,194,907	$	4,301,083

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Fair Value of Derivative Contracts	'
	The following table presents the fair value of the Company’s derivative contracts as of December 31, 2013 and 2012 on a gross basis without regard to same-counterparty netting (in thousands):
					December 31,
	Type of Contract		Balance Sheet Classification		2013				2012
	Derivative assets
	Oil price swaps		Derivative contracts—current		$	15,887			$	88,052
	Natural gas price swaps		Derivative contracts—current		1,598				—
	Oil basis swaps		Derivative contracts—current		—				183
	Oil collars—three way		Derivative contracts—current		706				—
	Natural gas collars		Derivative contracts—current		177				3,111
	Oil price swaps		Derivative contracts—noncurrent		19,376				37,983
	Oil collars—three way		Derivative contracts—noncurrent		12,189				190
	Natural gas collars		Derivative contracts—noncurrent		341				884
	Derivative liabilities
	Oil price swaps		Derivative contracts—current		(38,396		)		(31,991		)
	Natural gas price swaps		Derivative contracts—current		(1,460		)		—
	Oil basis swaps		Derivative contracts—current		—				(695		)
	Oil collars—two way		Derivative contracts—current		—				(103		)
	Interest rate swap		Derivative contracts—current		—				(2,395		)
	Oil price swaps		Derivative contracts—noncurrent		(38,344		)		(67,900		)
	Oil collars—three way		Derivative contracts—noncurrent		—				(7,327		)
	Total net derivative contracts				$	(27,926	)		$	19,992
Offsetting Assets and Liabilities	'
	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):
	December 31, 2013
			Gross Amounts				Gross Amounts Offset				Amounts Net of Offset		Financial Collateral			Net Amount
	Assets
	Derivative contracts - current		$	18,368			$	(5,589	)		$	12,779	$	—		$	12,779
	Derivative contracts - noncurrent		31,906				(17,780		)		14,126		—			14,126
	Total		$	50,274			$	(23,369	)		$	26,905	$	—		$	26,905
	Liabilities
	Derivative contracts - current		$	39,856			$	(5,589	)		$	34,267	$	(34,267	)	$	—
	Derivative contracts - noncurrent		38,344				(17,780		)		20,564		(20,564		)	—
	Total		$	78,200			$	(23,369	)		$	54,831	$	(54,831	)	$	—
	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	)	$	—
Open Oil and Natural Gas Commodity Derivative Contracts	'
	At December 31, 2013, the Company’s open commodity derivative contracts consisted of the following:
	Oil Price Swaps
		Notional (MBbls)			Weighted Average
					Fixed Price
	January 2014 — December 2014	8,813			$	92.98
	January 2015 — December 2015	7,979			$	86.13
	Natural Gas Price Swaps
		Notional (MMcf)			Weighted Average
					Fixed Price
	January 2014 — December 2014	35,490			$	4.2
	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
	January 2014 — December 2014	937			$4.00	—	$7.78
	January 2015 — December 2015	1,010			$4.00	—	$8.55

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations	'
	The following table presents the balance and activity of the asset retirement obligations for the years ended December 31, 2013, 2012 and 2011 (in thousands).
		2013			2012			2011
	Asset retirement obligations at January 1	$	498,410		$	128,116		$	119,877
	Liability incurred upon acquiring and drilling wells	5,078			7,479			5,716
	Liability assumed in acquisition(1)	—			371,365			—
	Revisions in estimated cash flows	(3,077		)	34,654			7,574
	Liability settled or disposed in current period(2)	(113,071		)	(72,200		)	(14,419		)
	Accretion(3)	36,777			28,996			9,368
	Asset retirement obligations at December 31	424,117			498,410			128,116
	Less: current portion	87,063			118,504			32,906
	Asset retirement obligations, net of current	$	337,054		$	379,906		$	95,210
	____________________
	-1	Represents asset retirement obligations assumed in the acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.
	-2	Year ended December 31, 2013 includes $45.3 million for the decommissioning of various platforms, pipeline and associated wells in the Gulf of Mexico and $15.2 million of asset retirement obligations disposed in conjunction with the sale of the Permian Properties. Years ended December 31, 2013 and 2012 include the settlement of plugging and abandonment obligations associated with properties in the Gulf of Mexico. Year ended December 31, 2011 includes amounts related to the Permian Basin and east Texas properties sold during 2011.
	-3	Years ended December 31, 2013 and 2012 include accretion attributable to asset retirement obligations assumed in the acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Line Items]	'
Future Minimum Rental Payments for Operating Leases	'
	Future minimum payments under noncancelable operating leases (with initial lease terms exceeding one year) as of December 31, 2013 were as follows (in thousands):
	Years ending December 31
	2014	$	3,239
	2015	2,988
	2016	2,640
	2017	1,756
	2018	215
		$	10,838
Transportation and Throughput Agreements	'
Commitments and Contingencies Disclosure [Line Items]	'
Transportation, Throughput and Gathering Obligations	'
	The amounts of the required payments related to the transportation and throughput agreements as of December 31, 2013 were as follows (in thousands):
	Years ending December 31
	2014	$	19,947
	2015	11,794
	2016	11,346
	2017	11,315
	2018	11,315
	Thereafter	2,790
		$	68,507
Gas Gathering Agreement	'
Commitments and Contingencies Disclosure [Line Items]	'
Transportation, Throughput and Gathering Obligations	'
	The table below presents the base fee contractual obligations under this agreement as of December 31, 2013 (in thousands).
	Years ending December 31
	2014	$	42,542
	2015	42,334
	2016	42,272
	2017	41,991
	2018	41,825
	Thereafter	100,559
		$	311,523

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Stockholders Equity Note [Line Items]	'
Preferred Stock Terms	'
	The following table summarizes information about each series of the Company’s convertible perpetual preferred stock:
			Convertible Perpetual Preferred Stock
			8.50%				6.00%			7.00%
	Liquidation preference per share		$	100			$	100		$	100
	Annual dividend per share		$	8.5			$	6		$	7
	Conversion rate per share to common stock		12.4805				9.2115			12.8791
	Conversion date to common stock at Company's option(1)		February 20, 2014				December 21, 2014			November 20, 2015
	____________________
	-1	Conversion is dependent on certain factors, including the Company’s stock trading above specified prices for a set period.
Preferred Stock Dividends	'
	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 years ended December 31, 2013, 2012 and 2011 as presented in the accompanying consolidated statements of operations, are included in tables below (in thousands):
		Dividends Paid				Dividends Unpaid			Total
	Year Ended December 31, 2013
	8.5% Convertible perpetual preferred stock	$	14,078			$	8,447		$	22,525
	6.0% Convertible perpetual preferred stock	6,500				5,500			12,000
	7.0% Convertible perpetual preferred stock	18,375				2,625			21,000
	Total	$	38,953			$	16,572		$	55,525
	Year Ended December 31, 2012
	8.5% Convertible perpetual preferred stock	$	14,078			$	8,447		$	22,525
	6.0% Convertible perpetual preferred stock	6,500				5,500			12,000
	7.0% Convertible perpetual preferred stock	18,375				2,625			21,000
	Total	$	38,953			$	16,572		$	55,525
	Year Ended December 31, 2011
	8.5% Convertible perpetual preferred stock	$	14,078			$	8,447		$	22,525
	6.0% Convertible perpetual preferred stock	6,500				5,500			12,000
	7.0% Convertible perpetual preferred stock	18,433				2,625			21,058
	Total	$	39,011			$	16,572		$	55,583
Treasury Stock Activity	'
	The following table shows the number of shares withheld for taxes and the associated value of those shares for the years ended December 31, 2013, 2012 and 2011. These shares were accounted for as treasury stock when withheld, and then immediately retired.
		Year Ended December 31,
		2013				2012			2011
		(In thousands)
	Number of shares withheld for taxes	5,679				1,547			1,176
	Value of shares withheld for taxes	$	30,126			$	11,312		$	10,834
Restricted Stock Activity	'
	Restricted stock activity for the years ended December 31, 2013, 2012 and 2011 was as follows (shares in thousands):
		Number of			Weighted-
		Shares			Average Grant
					Date Fair Value
	Unvested restricted shares outstanding at December 31, 2010	9,476			$	10.89
	Granted	8,003			$	8.95
	Vested	(3,270	)		$	12.91
	Forfeited / Canceled	(823	)		$	9.17
	Unvested restricted shares outstanding at December 31, 2011	13,386			$	9.34
	Granted	7,604			$	7.46
	Vested	(4,394	)		$	10.73
	Forfeited / Canceled	(1,268	)		$	8.54
	Unvested restricted shares outstanding at December 31, 2012	15,328			$	8.07
	Granted	7,462			$	6.32
	Vested	(13,395	)		$	7.85
	Forfeited / Canceled	(1,752	)		$	7.33
	Unvested restricted shares outstanding at December 31, 2013	7,643			$	6.92
Preferred Stock	'
Stockholders Equity Note [Line Items]	'
Schedule of Stock by Class	'
	Preferred Stock
	The following table presents information regarding the Company’s preferred stock (in thousands):
		December 31,
		2013			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
Common Stock	'
Stockholders Equity Note [Line Items]	'
Schedule of Stock by Class	'
	Common Stock
	The following table presents information regarding the Company’s common stock (in thousands):
		December 31,
		2013			2012
	Shares authorized	800,000			800,000
	Shares outstanding at end of period	490,290			490,359
	Shares held in treasury	1,319			1,219

Incentive_Retirement_and_Defer1

Incentive, Retirement and Deferred Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation Related Costs [Abstract]	'
Performance Unit Fair Value Assumptions	'
	The following table presents a summary of the fair value of the performance units and the related assumptions as of December 31, 2013.
	Expected price volatility range	27	%	-	44.8		%
	Risk-free interest rate				0.4		%
	Fair value per unit (at grant date)				$	69.38
	Fair value per unit (at December 31, 2013)				$	97.06

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
(Benefit) Provision for Income Taxes	'
	The Company’s income tax provision (benefit) consisted of the following components for the years ended December 31, 2013, 2012 and 2011 (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Current
	Federal	$	3,842		$	(72	)	$	618
	State	1,842			(2		)	551
		5,684			(74		)	1,169
	Deferred
	Federal	—			(97,410		)	(6,447		)
	State	—			(2,878		)	(539		)
		—			(100,288		)	(6,986		)
	Total provision (benefit)	5,684			(100,362		)	(5,817		)
	Less: income tax provision attributable to noncontrolling interest	308			304			109
	Total provision (benefit) attributable to SandRidge Energy, Inc.	$	5,376		$	(100,666	)	$	(5,926	)
Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate	'
	A reconciliation of the provision (benefit) for income taxes at the statutory federal tax rate to the Company’s actual income tax benefit is as follows for the years ended December 31, 2013, 2012 and 2011 (in thousands):
		2013			2012			2011
	Computed at federal statutory rate	$	(178,078	)	$	51,173		$	54,800
	State taxes, net of federal benefit	(886		)	8,913			5,231
	Non-deductible expenses	2,589			7,247			6,394
	Stock-based compensation	7,611			7,172			8,229
	Net effects of consolidating the non-controlling interests’ tax provisions	(13,901		)	(37,047		)	(19,120		)
	Bargain purchase gain	—			(42,944		)	—
	Impairment of non-deductible goodwill	—			71,885			—
	Change in valuation allowance	188,599			(66,429		)	(51,631		)
	Valuation allowance release	—			(100,288		)	(5,290		)
	Other	(558		)	(348		)	(4,539		)
	Total provision (benefit) attributable to SandRidge Energy, Inc.	$	5,376		$	(100,666	)	$	(5,926	)
Deferred Tax Assets and Liabilities	'
	Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):
		December 31,
		2013			2012
	Deferred tax liabilities
	Investments(1)	$	301,447		$	334,331
	Property, plant and equipment	180,140			198,424
	Derivative contracts	—			24,819
	Total deferred tax liabilities	481,587			557,574
	Deferred tax assets
	Derivative contracts	3,692			—
	Allowance for doubtful accounts	20,358			17,713
	Net operating loss carryforwards	973,675			859,328
	Litigation settlement	355			7,200
	Compensation and benefits	24,895			13,935
	Alternative minimum tax credits and other carryforwards	46,624			42,242
	Asset retirement obligations	147,626			172,229
	Under-delivery obligation	15,012			—
	Other	2,801			2,193
	Total deferred tax assets	1,235,038			1,114,840
	Valuation allowance	(753,451		)	(557,266		)
	Net deferred tax liability	$	—		$	—
	____________________
	-1	Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. See Note 4 for further discussion of the Royalty Trusts.
Unrecognized Tax Benefits	'
	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):
		December 31,
		2013			2012
	Unrecognized tax benefit at January 1	$	1,330		$	1,758
	Changes to unrecognized tax benefits related to the current year	262			—
	Changes to unrecognized tax benefits related to a prior year	(210		)	(428		)
	Unrecognized tax benefit at December 31	$	1,382		$	1,330

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share	'
	The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the years ended December 31, 2013, 2012 and 2011 (in thousands):
		Income (Loss)			Weighted Average Shares	Earnings (Loss) Per Share
		(In thousands, except per share amounts)
	Year Ended December 31, 2011
	Basic earnings per share	$	52,482		398,851	$	0.13
	Effect of dilutive securities
	Restricted stock	—			7,794
	Diluted earnings per share	$	52,482		406,645	$	0.13
	Year Ended December 31, 2012
	Basic earnings per share	$	86,046		453,595	$	0.19
	Effect of dilutive securities
	Restricted stock	—			2,420
	Diluted earnings per share	$	86,046		456,015	$	0.19
	Year Ended December 31, 2013
	Basic loss per share	$	(609,414	)	481,148	$	(1.27	)
	Effect of dilutive securities
	Restricted stock(1)	—			—
	Diluted loss per share	$	(609,414	)	481,148	$	(1.27	)
	____________________
	-1	Restricted stock awards covering 0.5 million shares were excluded from the computation of loss per share because their effect would have been antidilutive.

Subsequent_Events_Tables

Subsequent Events (Tables)	12 Months Ended
	Dec. 31, 2013
Royalty Trusts	'
Subsequent Event [Line Items]	'
Royalty Trust Distributions	'
	The Royalty Trusts declared and paid quarterly distributions during the years ended December 31, 2013, 2012 and 2011 as follows (in thousands):
			Year Ended December 31,
			2013(1)		2012(2)		2011(2)
	Total distributions		$	299,674	$	274,979	$	91,162
	Distributions to third-party unitholders		$	206,470	$	181,727	$	57,449
	____________________
	-1	Subordination thresholds were not met for the Mississippian Trust I’s second and third quarter 2013 distributions or for the Permian Trust’s second quarter 2013 distribution, resulting in reduced distributions to the Company on its subordinated units for these periods.
	-2	The Company received incentive distributions from the Mississippian Trust I during the first and second quarters of 2012 and the third quarter of 2011.
Royalty Trusts | Subsequent Event	'
Subsequent Event [Line Items]	'
Royalty Trust Distributions	'
	The following distributions will be paid on February 28, 2014 to holders of record as of the close of business on February 14, 2014 (in thousands):
	Royalty Trust		Total Distribution		Amount to be Distributed to Third-Party Unitholders
	Mississippian Trust I		$	10,508	$	10,242
	Permian Trust		33,677		25,239
	Mississippian Trust II		24,160		17,637
	Total		$	68,345	$	53,118
Gulf of Mexico Properties | Subsequent Event	'
Subsequent Event [Line Items]	'
Gulf Properties Pro Forma Financial Information	'
	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.
		Year Ended December 31,
		2013
		(In thousands, except per share data)
		(Unaudited)
	Revenues	$	1,356,152
	Net loss(1)	$	(1,068,664	)
	Loss attributable to SandRidge Energy, Inc. common stockholders(1)	$	(1,028,055	)
	Loss per common share(1)
	Basic	$	(2.25	)
	Diluted	$	(2.25	)
	____________________
	-1	Includes pro forma ceiling impairment of $441.0 million, including $80.0 million allocated to noncontrolling interest and $361.0 million attributable to SandRidge Energy, Inc., for the year ended December 31, 2013.

Business_Segment_Information_T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Summarized Financial Information Concerning Segments	'
	Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):
		Exploration and			Drilling and Oil			Midstream			All Other(4)			Consolidated
		Production(1)			Field Services(2)			Services(3)						Total
	Year Ended December 31, 2013
	Revenues	$	1,834,480		$	187,456		$	179,989		$	3,127		$	2,205,052
	Inter-segment revenue	(320		)	(120,815		)	(100,529		)	—			(221,664		)
	Total revenues	$	1,834,160		$	66,641		$	79,460		$	3,127		$	1,983,388
	Income (loss) from operations	$	62,509		$	(40,155	)	$	(21,567	)	$	(169,788	)	$	(169,001	)
	Interest income (expense), net	1,168			—			(209		)	(271,193		)	(270,234		)
	Loss on extinguishment of debt	—			—			—			(82,005		)	(82,005		)
	Other income (expense), net	5,487			—			(3,222		)	10,180			12,445
	Income (loss) before income taxes	$	69,164		$	(40,155	)	$	(24,998	)	$	(512,806	)	$	(508,795	)
	Capital expenditures(5)	$	1,319,012		$	7,125		$	55,706		$	42,040		$	1,423,883
	Depreciation, depletion, amortization and accretion	$	605,242		$	33,291		$	7,972		$	20,140		$	666,645
	At December 31, 2013
	Total assets	$	6,157,225		$	158,737		$	188,165		$	1,180,668		$	7,684,795
	Year Ended December 31, 2012
	Revenues	$	2,571,544		$	379,345		$	116,659		$	4,356		$	3,071,904
	Inter-segment revenue	(403		)	(262,712		)	(77,824		)	—			(340,939		)
	Total revenues	$	2,571,141		$	116,633		$	38,835		$	4,356		$	2,730,965
	Income (loss) from operations	$	518,144		$	11,911		$	(73,027	)	$	(131,832	)	$	325,196
	Interest income (expense), net	1,286			—			(559		)	(304,076		)	(303,349		)
	Bargain purchase gain	122,696			—			—			—			122,696
	Loss on extinguishment of debt	—			—			—			(3,075		)	(3,075		)
	Other income, net	1,868			—			—			2,873			4,741
	Income (loss) before income taxes	$	643,994		$	11,911		$	(73,586	)	$	(436,110	)	$	146,209
	Capital expenditures(5)	$	1,951,490		$	27,527		$	80,413		$	114,552		$	2,173,982
	Depreciation, depletion, amortization and accretion	$	598,101		$	34,677		$	7,188		$	17,864		$	657,830
	At December 31, 2012
	Total assets	$	8,681,056		$	199,523		$	151,492		$	758,660		$	9,790,731
	Year Ended December 31, 2011
	Revenues	$	1,237,565		$	390,485		$	183,912		$	10,535		$	1,822,497
	Inter-segment revenue	(265		)	(287,187		)	(118,731		)	(1,101		)	(407,284		)
	Total revenues	$	1,237,300		$	103,298		$	65,181		$	9,434		$	1,415,213
	Income (loss) from operations	$	521,117		$	10,341		$	(12,975	)	$	(89,470	)	$	429,013
	Interest income (expense), net	509			(95		)	(611		)	(237,135		)	(237,332		)
	Loss on extinguishment of debt	—			—			—			(38,232		)	(38,232		)
	Other income (expense), net	3,601			—			(485		)	6			3,122
	Income (loss) before income taxes	$	525,227		$	10,246		$	(14,071	)	$	(364,831	)	$	156,571
	Capital expenditures(5)	$	1,697,691		$	25,674		$	38,514		$	54,615		$	1,816,494
	Depreciation, depletion, amortization and accretion	$	328,753		$	32,582		$	4,650		$	14,259		$	380,244
	____________________
	-1	Income from operations includes impairment of the Company’s goodwill of $235.4 million for the year ended December 31, 2012.
	-2	For the year ended December 31, 2013, loss from operations includes impairment of $11.1 million on certain drilling assets.
	-3	For the years ended December 31, 2013 and 2012, loss from operations includes impairments of the Company’s gas treating plants in west Texas and other midstream assets of $3.9 million and $59.7 million, respectively.
	-4	For the year ended December 31, 2013, loss from operations includes a $2.9 million impairment of a corporate asset and an $8.3 million impairment of the Company’s CO2 compression facilities. For the year ended December 31, 2012, loss from operations includes a $19.6 million impairment of the Company’s CO2 compression facilities.
	-5	On an accrual basis and exclusive of acquisitions.
Major Customers	'
	Major Customers. For the years ended December 31, 2013, 2012 and 2011, the Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):
		2013
		Sales			% of Revenue
	Plains Marketing, L.P.	$	491,258		24.8	%
	Shell Trading (US) Company	$	347,422		17.5	%
	Atlas Pipeline Mid-Continent West OK LLC	$	211,838		10.7	%
		2012
		Sales			% of Revenue
	Occidental Petroleum Corporation	$	829,081		30.4	%
	Plains Marketing, L.P.	$	426,339		15.6	%
	Enterprise Crude Oil, LLC	$	394,162		14.4	%
		2011
		Sales			% of Revenue
	Enterprise Crude Oil, LLC	$	319,277		22.6	%
	Plains Marketing, L.P.	$	276,285		19.5	%

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Statements Disclosure [Abstract]	'
Schedule of Condensed Cash Flow Revisions for Prior Periods	'
	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 years ended December 31, 2012 and 2011.
			Year Ended December 31,
			2012				2011
			(In thousands)
	Parent		$	945,448			$	288,415
	Guarantors		$	(809,099	)		$	(172,927	)
	Non-Guarantors		$	(136,349	)		$	(115,488	)
Condensed Consolidating Balance Sheets of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors	'
	Condensed Consolidating Balance Sheets
		December 31, 2013
		Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
		(In thousands)
	ASSETS
	Current assets
	Cash and cash equivalents	$	805,505			$	1,013			$	8,145		$	—		$	814,663
	Accounts receivable, net	—				326,345				22,873			—			349,218
	Intercompany accounts receivable	153,325				982,524				70,107			(1,205,956		)	—
	Derivative contracts	—				7,796				14,748			(9,765		)	12,779
	Prepaid expenses	—				39,165				88			—			39,253
	Other current assets	1,376				24,410				124			—			25,910
	Total current assets	960,206				1,381,253				116,085			(1,215,721		)	1,241,823
	Property, plant and equipment, net	—				5,181,128				1,182,132			(55,585		)	6,307,675
	Investment in subsidiaries	5,237,057				(102,848		)		—			(5,134,209		)	—
	Derivative contracts	—				12,650				9,585			(8,109		)	14,126
	Other assets	61,923				65,123				27			(5,902		)	121,171
	Total assets	$	6,259,186			$	6,537,306			$	1,307,829		$	(6,419,526	)	$	7,684,795
	LIABILITIES AND EQUITY
	Current liabilities
	Accounts payable and accrued expenses	$	207,572			$	601,074			$	3,842		$	—		$	812,488
	Intercompany accounts payable	967,365				180,910				57,018			(1,205,293		)	—
	Derivative contracts	—				44,032				—			(9,765		)	34,267
	Asset retirement obligations	—				87,063				—			—			87,063
	Total current liabilities	1,174,937				913,079				60,860			(1,215,058		)	933,818
	Long-term debt	3,200,809				—				—			(5,902		)	3,194,907
	Derivative contracts	—				28,673				—			(8,109		)	20,564
	Asset retirement obligations	—				337,054				—			—			337,054
	Other long-term obligations	1,382				21,443				—			—			22,825
	Total liabilities	4,377,128				1,300,249				60,860			(1,229,069		)	4,509,168
	Equity
	SandRidge Energy, Inc. stockholders’ equity	1,882,058				5,237,057				1,246,969			(6,540,274		)	1,825,810
	Noncontrolling interest	—				—				—			1,349,817			1,349,817
	Total equity	1,882,058				5,237,057				1,246,969			(5,190,457		)	3,175,627
	Total liabilities and equity	$	6,259,186			$	6,537,306			$	1,307,829		$	(6,419,526	)	$	7,684,795
		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
Condensed Consolidating Statements of Operations of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors	'
	Condensed Consolidating Statements of Operations
		Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
		(In thousands)
	Year Ended December 31, 2013
	Total revenues	$	—			$	1,675,481			$	308,300		$	(393	)	$	1,983,388
	Expenses
	Direct operating expenses	—				655,101				29,143			(1,414		)	682,830
	General and administrative	329				323,808				6,288			—			330,425
	Depreciation, depletion, amortization and accretion	—				581,435				85,210			—			666,645
	Impairment	—				15,038				11,242			—			26,280
	Loss on derivative contracts	—				24,702				22,421			—			47,123
	Loss on sale of assets	—				291,743				107,343			—			399,086
	Total expenses	329				1,891,827				261,647			(1,414		)	2,152,389
	(Loss) income from operations	(329		)		(216,346		)		46,653			1,021			(169,001		)
	Equity earnings from subsidiaries	(188,850		)		3,075				—			185,775			—
	Interest (expense) income, net	(271,193		)		959				—			—			(270,234		)
	Loss on extinguishment of debt	(82,005		)		—				—			—			(82,005		)
	Other income (expense), net	—				23,462				(3,728		)	(7,289		)	12,445
	(Loss) income before income taxes	(542,377		)		(188,850		)		42,925			179,507			(508,795		)
	Income tax expense	5,244				—				440			—			5,684
	Net (loss) income	(547,621		)		(188,850		)		42,485			179,507			(514,479		)
	Less: net income attributable to noncontrolling interest	—				—				—			39,410			39,410
	Net (loss) income attributable to SandRidge Energy, Inc.	$	(547,621	)		$	(188,850	)		$	42,485		$	140,097		$	(553,889	)
		Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
		(In thousands)
	Year Ended December 31, 2012
	Total revenues	$	—			$	2,435,064			$	404,418		$	(108,517	)	$	2,730,965
	Expenses
	Direct operating expenses	—				1,393,006				146,416			(107,750		)	1,431,672
	General and administrative	515				234,954				7,635			(1,422		)	241,682
	Depreciation, depletion, amortization and accretion	—				570,786				87,044			—			657,830
	Impairment	—				236,671				79,333			—			316,004
	Gain on derivative contracts	—				(198,732		)		(42,687		)	—			(241,419		)
	Total expenses	515				2,236,685				277,741			(109,172		)	2,405,769
	(Loss) income from operations	(515		)		198,379				126,677			655			325,196
	Equity earnings from subsidiaries	426,264				20,667				—			(446,931		)	—
	Interest (expense) income	(303,510		)		725				(564		)	—			(303,349		)
	Gain on sale of subsidiary	55,585				—				—			(55,585		)	—
	Bargain purchase gain	—				122,696				—			—			122,696
	Loss on extinguishment of debt	(3,075		)		—				—			—			(3,075		)
	Other income, net	—				83,797				—			(79,056		)	4,741
	Income before income taxes	174,749				426,264				126,113			(580,917		)	146,209
	Income tax (benefit) expense	(100,808		)		—				446			—			(100,362		)
	Net income	275,557				426,264				125,667			(580,917		)	246,571
	Less: net income attributable to noncontrolling interest	—				—				—			105,000			105,000
	Net income attributable to SandRidge Energy, Inc.	$	275,557			$	426,264			$	125,667		$	(685,917	)	$	141,571
		Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
		(In thousands)
	Year Ended December 31, 2011
	Total revenues	$	—			$	1,285,854			$	268,427		$	(139,068	)	$	1,415,213
	Expenses
	Direct operating expenses	—				475,578				158,697			(135,712		)	498,563
	General and administrative	416				144,574				4,670			(1,017		)	148,643
	Depreciation, depletion, amortization, accretion and impairment	—				351,708				31,361			—			383,069
	Gain on derivative contracts	—				(33,749		)		(10,326		)	—			(44,075		)
	Total expenses	416				938,111				184,402			(136,729		)	986,200
	(Loss) income from operations	(416		)		347,743				84,025			(2,339		)	429,013
	Equity earnings from subsidiaries	379,177				28,751				—			(407,928		)	—
	Interest expense	(236,109		)		(197		)		(1,026		)	—			(237,332		)
	Loss on extinguishment of debt	(38,232		)		—				—			—			(38,232		)
	Other income, net	—				2,880				242			—			3,122
	Income before income taxes	104,420				379,177				83,241			(410,267		)	156,571
	Income tax (benefit) expense	(5,984		)		—				167			—			(5,817		)
Net income	110,404				379,177				83,074			(410,267		)	162,388
Less: net income attributable to noncontrolling interest	—				—				—			54,323			54,323
Net income attributable to SandRidge Energy, Inc.	$	110,404			$	379,177			$	83,074		$	(464,590	)	$	108,065
Condensed Consolidating Statements of Cash Flows of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors	'
	Condensed Consolidating Statements of Cash Flows
		Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
		(In thousands)
	Year Ended December 31, 2013
	Net cash (used in) provided by operating activities	$	(239,026	)		$	852,026			$	254,723		$	907		$	868,630
	Cash flows from investing activities
	Capital expenditures for property, plant and equipment	—				(1,496,731		)		—			—			(1,496,731		)
	Proceeds from sale of assets	—				2,566,742				17,373			—			2,584,115
	Other	—				89,606				3,197			(109,831		)	(17,028		)
	Net cash provided by (used in) investing activities	—				1,159,617				20,570			(109,831		)	1,070,356
	Cash flows from financing activities
	Repayments of borrowings	(1,115,500		)		—				—			—			(1,115,500		)
	Premium on debt redemption	(61,997		)		—				—			—			(61,997		)
	Distributions to owners	—				—				(299,675		)	93,205			(206,470		)
	Dividends paid—preferred	(55,525		)		—				—			—			(55,525		)
	Intercompany borrowings (advances), net	2,009,146				(2,018,212		)		9,066			—			—
	Other	(31,821		)		6,660				14,845			15,719			5,403
	Net cash provided by (used in) financing activities	744,303				(2,011,552		)		(275,764		)	108,924			(1,434,089		)
	Net increase (decrease) in cash and cash equivalents	505,277				91				(471		)	—			504,897
	Cash and cash equivalents at beginning of year	300,228				922				8,616			—			309,766
	Cash and cash equivalents at end of year	$	805,505			$	1,013			$	8,145		$	—		$	814,663
		Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
		(In thousands)
	Year Ended December 31, 2012 (Revised)
	Net cash provided by operating activities	$	285,567			$	264,717			$	162,281		$	70,595		$	783,160
	Cash flows from investing activities
	Capital expenditures for property, plant and equipment	—				(2,112,547		)		(33,825		)	—			(2,146,372		)
	Acquisitions, net of cash received	(693,091		)		(147,649		)		(587,086		)	587,086			(840,740		)
	Proceeds from sale of assets	129,830				942,675				1,333			(642,671		)	431,167
	Other	(61,343		)		278,708				—			(217,365		)	—
	Net cash used in investing activities	(624,604		)		(1,038,813		)		(619,578		)	(272,950		)	(2,555,945		)
	Cash flows from financing activities
	Proceeds from borrowings	1,850,344				—				—			—			1,850,344
	Repayments of borrowings	(350,000		)		—				(16,029		)	—			(366,029		)
	Proceeds from issuance of royalty trust units	—				—				587,086			—			587,086
	Proceeds from the sale of royalty trust units	—				—				—			139,360			139,360
	Distributions to unitholders	—				—				(274,980		)	93,253			(181,727		)
	Dividends paid—preferred	(55,525		)		—				—			—			(55,525		)
	Intercompany (advances) borrowings, net	(945,448		)		809,099				136,349			—			—
	Other	(64,121		)		(34,518		)		30,258			(30,258		)	(98,639		)
	Net cash provided by financing activities	435,250				774,581				462,684			202,355			1,874,870
	Net increase in cash and cash equivalents	96,213				485				5,387			—			102,085
	Cash and cash equivalents at beginning of year	204,015				437				3,229			—			207,681
	Cash and cash equivalents at end of year	$	300,228			$	922			$	8,616		$	—		$	309,766
		Parent				Guarantors				Non-Guarantors			Eliminations			Consolidated
		(In thousands)
	Year Ended December 31, 2011 (Revised)
	Net cash provided by (used in) operating activities	$	702,369			$	(221,992	)		$	(9,005	)	$	(12,418	)	$	458,954
	Cash flows from investing activities
	Capital expenditures for property, plant and equipment	—				(1,726,131		)		(975		)	—			(1,727,106		)
	Proceeds from sale of assets	—				1,776,907				26			(917,528		)	859,405
	Other	—				(2,074		)		(917,528		)	884,974			(34,628		)
	Net cash provided by (used in) investing activities	—				48,702				(918,477		)	(32,554		)	(902,329		)
	Cash flows from financing activities
	Proceeds from borrowings	2,033,000				—				—			—			2,033,000
	Repayments of borrowings	(2,123,000		)		(6,302		)		(991		)	—			(2,130,293		)
	Proceeds from issuance royalty trust units	—				—				917,528			—			917,528
	Distributions to unitholders	—				—				(96,664		)	36,464			(60,200		)
	Dividends paid—preferred	(56,742		)		—				—			—			(56,742		)
	Intercompany (advances) borrowings, net	(288,415		)		172,927				115,488			—			—
	Other	(64,638		)		6,538				(8,508		)	8,508			(58,100		)
	Net cash (used in) provided by financing activities	(499,795		)		173,163				926,853			44,972			645,193
	Net increase (decrease) in cash and cash equivalents	202,574				(127		)		(629		)	—			201,818
Cash and cash equivalents at beginning of year	1,441				564				3,858			—			5,863
Cash and cash equivalents at end of year	$	204,015			$	437			$	3,229		$	—		$	207,681

Supplemental_Information_on_Oi1

Supplemental Information on Oil and Natural Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Reserve Quantities [Line Items]	'
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities	'
	Capitalized Costs Related to Oil and Natural Gas Producing Activities
	The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):
		December 31,
		2013				2012				2011
	Oil and natural gas properties
	Proved	$	10,972,816			$	12,262,921			$	8,969,296
	Unproved	531,606				865,863				689,393
	Total oil and natural gas properties	11,504,422				13,128,784				9,658,689
	Less accumulated depreciation, depletion and impairment	(5,762,969		)		(5,231,182		)		(4,791,534		)
	Net oil and natural gas properties capitalized costs	$	5,741,453			$	7,897,602			$	4,867,155
Cost Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development	'
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
	Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):
		Year Ended December 31,
		2013				2012				2011
	Acquisitions of properties
	Proved	$	21,130			$	1,761,556			$	58,190
	Unproved	100,242				377,185				320,361
	Exploration(1)	82,775				120,438				98,849
	Development(2)	1,131,269				1,704,991				1,296,903
	Total cost incurred	$	1,335,416			$	3,964,170			$	1,774,303
	____________________
	-1	Includes seismic costs of $6.7 million, $15.3 million and $4.9 million for 2013, 2012 and 2011, respectively.
	-2	Includes loss on the construction of the Century Plant of $50.0 million and $25.0 million for 2012 and 2011, respectively. See Note 11.
Results of Operations for Oil, Natural Gas and NGL Producing Activities (Unaudited)	'
	Results of Operations for Oil and Natural Gas Producing Activities (Unaudited)
	The Company’s results of operations from oil and natural gas producing activities for each of the years 2013, 2012 and 2011 are shown in the following table (in thousands):
		Year Ended December 31,
		2013				2012				2011
	Revenues	$	1,820,278			$	1,759,282			$	1,226,794
	Expenses
	Production costs	548,719				524,364				368,946
	Depreciation and depletion	567,732				568,029				317,246
	Accretion of asset retirement obligations	36,777				28,996				9,368
	Total expenses	1,153,228				1,121,389				695,560
	Income before income taxes	667,050				637,893				531,234
	Benefit of income taxes(1)	(7,471		)		(437,595		)		(20,134		)
	Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	674,521			$	1,075,488			$	551,368
	____________________
	-1	Reflects the Company’s effective tax rate, including the partial valuation allowance releases.
Summary of Changes in Estimated Oil, Natural Gas and NGL Reserves (Unaudited)	'
	The summary below presents changes in the Company’s estimated reserves for 2011, 2012 and 2013.
		Oil			NGL			Natural Gas
		(MBbls)			(MBbls)			(MMcf)(1)
	Proved developed and undeveloped reserves
	As of December 31, 2010	205,023			47,091			1,762,665
	Revisions of previous estimates	(6,159	)		(3,119	)		(164,845	)
	Acquisitions of new reserves	1,309			224			2,906
	Extensions and discoveries	52,406			3,171			299,848
	Sales of reserves in place	(28,137	)		(15,194	)		(476,212	)
	Production	(9,992	)		(1,838	)		(69,306	)
	As of December 31, 2011(2)	214,450			30,335			1,355,056
	Revisions of previous estimates	(37,394	)		15,098			(538,214	)
	Acquisitions of new reserves	31,470			683			202,995
	Extensions and discoveries	89,656			27,259			489,302
	Sales of reserves in place	(20,269	)		(3,287	)		(548	)
	Production	(15,868	)		(2,094	)		(93,549	)
	As of December 31, 2012(2)	262,045			67,994			1,415,042
	Revisions of previous estimates	(13,969	)		3,717			(53,432	)
	Acquisitions of new reserves	43			13			363
	Extensions and discoveries	40,570			18,686			359,918
	Sales of reserves in place	(131,769	)		(29,067	)		(228,229	)
	Production	(14,279	)		(2,291	)		(103,233	)
	As of December 31, 2013(2)	142,641			59,052			1,390,429
	Proved developed reserves
	As of December 31, 2010	73,111			18,854			784,292
	As of December 31, 2011	101,578			17,150			670,382
	As of December 31, 2012	136,605			33,785			896,701
	As of December 31, 2013	83,893			35,807			951,609
	Proved undeveloped reserves
	As of December 31, 2010	131,912			28,237			978,373
	As of December 31, 2011	112,872			13,185			684,674
	As of December 31, 2012	125,440			34,209			518,341
	As of December 31, 2013	58,748			23,245			438,820
	____________________
	-1	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
	-2	Includes proved reserves attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 as shown in the table below:
		December 31,
		2013			2012			2011
	Oil (MBbl)	13,569			17,340			17,018
	NGL (MBbl)	4,737			5,132			1,782
	Natural gas (MMcf)	69,693			94,543			45,500
Calculation of Weighted Average Per Unit Prices (Unaudited)	'
	The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
		At December 31,
		2013				2012				2011
	Oil (per barrel)	$	95.67			$	91.65			$	91.35
	NGL (per barrel)	$	31.4			$	32.64			$	46.33
	Natural gas (per Mcf)	$	3.65			$	2.29			$	4.06
Standardized Measure of Discounted Future Cash Flows (Unaudited)	'
	The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).
		At December 31,
		2013				2012				2011
	Future cash inflows from production	$	19,937,484			$	29,482,544			$	26,494,942
	Future production costs	(6,843,713		)		(8,899,465		)		(7,392,104		)
	Future development costs(1)	(2,546,680		)		(4,021,051		)		(2,977,993		)
	Future income tax expenses	(2,283,541		)		(3,721,509		)		(4,043,953		)
	Undiscounted future net cash flows	8,263,550				12,840,519				12,080,892
	10% annual discount	(4,245,939		)		(7,000,151		)		(6,864,555		)
	Standardized measure of discounted future net cash flows(2)	$	4,017,611			$	5,840,368			$	5,216,337
	____________________
	-1	Includes abandonment costs.
	-2	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 respectively.
Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited)	'
	The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
	Present value as of December 31, 2010	$	3,683,515
	Changes during the year
	Revenues less production and other costs	(857,848		)
	Net changes in prices, production and other costs	1,264,736
	Development costs incurred	575,546
	Net changes in future development costs	87,080
	Extensions and discoveries	1,812,167
	Revisions of previous quantity estimates	(345,965		)
	Accretion of discount	455,501
	Net change in income taxes	(833,841		)
	Purchases of reserves in-place	44,934
	Sales of reserves in-place	(558,257		)
	Timing differences and other(1)	(111,231		)
	Net change for the year	1,532,822
	Present value as of December 31, 2011(2)	5,216,337
	Changes during the year
	Revenues less production and other costs	(1,234,918		)
	Net changes in prices, production and other costs	(2,555,391		)
	Development costs incurred	766,943
	Net changes in future development costs	(45,397		)
	Extensions and discoveries	2,092,423
	Revisions of previous quantity estimates	(530,755		)
	Accretion of discount	678,200
	Net change in income taxes	11,433
	Purchases of reserves in-place	1,708,301
	Sales of reserves in-place	(410,415		)
	Timing differences and other(1)	143,607
	Net change for the year	624,031
	Present value as of December 31, 2012(2)	5,840,368
	Changes during the year
	Revenues less production and other costs	(1,271,559		)
	Net changes in prices, production and other costs	271,566
	Development costs incurred	474,275
	Net changes in future development costs	(207,729		)
	Extensions and discoveries	1,406,102
	Revisions of previous quantity estimates	(296,418		)
	Accretion of discount	711,385
	Net change in income taxes	477,328
	Purchases of reserves in-place	1,628
	Sales of reserves in-place	(3,172,187		)
	Timing differences and other(1)	(217,148		)
	Net change for the year	(1,822,757		)
	Present value as of December 31, 2013(2)	$	4,017,611
	____________________
	-1	The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.
	-2	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012, and 2011 respectively.
Noncontrolling Interest	'
Reserve Quantities [Line Items]	'
Summary of Changes in Estimated Oil, Natural Gas and NGL Reserves (Unaudited)	'
		Includes proved reserves attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 as shown in the table below:
		December 31,
		2013			2012			2011
	Oil (MBbl)	13,569			17,340			17,018
	NGL (MBbl)	4,737			5,132			1,782
	Natural gas (MMcf)	69,693			94,543			45,500

Quarterly_Financial_Results_Un1

Quarterly Financial Results (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Financial Results (Unaudited)	'
	The Company’s operating results for each quarter of 2013 and 2012 are summarized below (in thousands, except per share data).
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	2013
	Total revenues	$	511,690		$	512,987		$	493,603		$	465,108
	(Loss) income from operations(1)(2)(3)	$	(359,526	)	$	86,458		$	6,088		$	97,979
	Net (loss) income(1)(2)(3)	$	(531,259	)	$	24,685		$	(57,002	)	$	49,097
	(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(1)(2)(3)	$	(493,221	)	$	(34,317	)	$	(87,074	)	$	5,198
	(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders(4)
	Basic	$	(1.03	)	$	(0.07	)	$	(0.18	)	$	0.01
	Diluted	$	(1.03	)	$	(0.07	)	$	(0.18	)	$	0.01
	2012
	Total revenues	$	381,635		$	478,434		$	532,798		$	1,338,098
	(Loss) income from operations(5)(6)	$	(151,656	)	$	762,413		$	(75,871	)	$	(209,690	)
	Net (loss) income(5)(6)(7)	$	(216,224	)	$	917,076		$	(159,752	)	$	(294,529	)
	(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(5)(6)(7)	$	(232,059	)	$	804,191		$	(184,301	)	$	(301,785	)
	(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders(4)
	Basic	$	(0.58	)	$	1.74		$	(0.39	)	$	(0.63	)
	Diluted	$	(0.58	)	$	1.46		$	(0.39	)	$	(0.63	)
	____________________
	-1	Includes a $10.6 million impairment of various drilling assets and a $2.9 million impairment of a corporate asset in the second quarter of 2013 and a $2.1 million and $10.0 million impairment of certain midstream inventory, natural gas compressors, gas treating plants and a CO2 compression station in the second and fourth quarters of 2013, respectively.
	-2	Includes loss (gain) on commodity derivative contracts of $40.9 million, $(103.7) million, $132.8 million and $(22.9) million for the first, second, third and fourth quarters, respectively.
	-3	Includes loss on sale of Permian Properties of $398.9 million in the first quarter of 2013.
	-4	(Loss applicable) income available per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of (loss applicable) income available per share to common stockholders for each of the four quarters may not equal the fiscal year amount.
	-5	Includes a $235.4 million goodwill impairment and a $79.3 million impairment of gas treating plants and CO2 compression facilities in the fourth quarter of 2012.
	-6	Includes loss (gain) on commodity derivative contracts of $254.6 million, $(669.9) million, $193.5 million and $(19.6) million for the first, second, third and fourth quarters, respectively.
	-7	Includes adjustments of $(4.8) million retrospectively applied to the second quarter of 2012 as a result of measurement period adjustments made to the preliminary purchase price allocation for the Dynamic Acquisition in the fourth quarter of 2012.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies Summary of Significant Accounting Policies - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	contracts
Significant Accounting Policies [Line Items]	'	'	'
Capitalized costs	$1,335,416,000	$3,964,170,000	$1,774,303,000
Restricted deposit - pending sale	0	255,000,000	'
Natural gas balancing liability	2,600,000	3,600,000	'
Construction contracts using completed-contract method (in number of contracts)	2	'	'
Advertising expense	5,100,000	11,800,000	4,800,000
Maximum	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Maximum reserves sold from cost center not expected to result in significant alteration	25.00%	'	'
Internal Costs	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Capitalized costs	74,700,000	61,300,000	37,100,000
Buildings | Maximum	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Property, plant and equipment, useful life	'39 years	'	'
Buildings | Minimum	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Property, plant and equipment, useful life	'10 years	'	'
Equipment | Maximum	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Property, plant and equipment, useful life	'30 years	'	'
Equipment | Minimum	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Property, plant and equipment, useful life	'3 years	'	'
Oil And Gas Unproved Properties	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Interest capitalized during period	11,700,000	10,100,000	1,000,000
Midstream And Corporate Assets	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Interest capitalized during period	$4,900,000	$4,700,000	$2,000,000

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Disclosure of Cash Flow Information	'	'	'
Cash paid for interest, net of amounts capitalized	($274,850)	($257,152)	($224,127)
Cash paid for income taxes	-4,610	-1,324	-2,083
Supplemental Disclosure of Noncash Investing and Financing Activities	'	'	'
Deposit on pending sale	-255,000	255,000	0
Change in accrued capital expenditures	72,848	-27,610	-89,388
Adjustment to oil and natural gas properties for contract loss	0	50,000	25,000
Asset retirement costs capitalized	5,078	7,479	5,716
Common stock issued in connection with acquisition	$0	$542,138	$0

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Dynamic Acquisition - Final Valuation of Assets Acquired and Liabilities Assumed (Details) (USD $)	12 Months Ended			0 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Apr. 17, 2012
				Dynamic Acquisition
Consideration(1)	'	'	'	'
Shares of SandRidge common stock issued	'	'	'	73,962	[1]
SandRidge common stock price	'	'	'	$7.33	[1]
Fair value of common stock issued	'	'	'	$542,138	[1]
Cash consideration	'	'	'	680,000	[1],[2]
Cash balance adjustment(3)	'	'	'	13,091	[1],[3]
Total purchase price	'	'	'	1,235,229	[1]
Fair Value of Liabilities Assumed	'	'	'	'
Current liabilities	'	'	'	129,363
Asset retirement obligations(4)	'	'	'	315,922	[4]
Long-term deferred tax liability(5)	'	'	'	100,288	[5]
Other long-term 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	[6]
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)	$0	($122,696)	$0	($122,696)	[7]
[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.
[7]	The bargain purchase gain resulted 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.

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures - Dynamic Acquisition - Final Valuation of Assets Acquired and Liabilities Assumed (Parenthetical) (Details) (USD $)	12 Months Ended			0 Months Ended				0 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Apr. 17, 2012		Dec. 31, 2013	Dec. 31, 2012	Apr. 17, 2012	Apr. 17, 2012	Apr. 17, 2012
				Dynamic Acquisition		8.125% Senior Notes due 2022	8.125% Senior Notes due 2022	8.125% Senior Notes due 2022	Oil	Natural Gas
								Dynamic Acquisition	Dynamic Acquisition	Dynamic Acquisition
Business Acquisition [Line Items]	'	'	'	'		'	'	'	'	'
Issuance of common stock in acquisition (in shares)	'	'	'	73,962	[1]	'	'	'	'	'
Cash consideration	'	'	'	$680,000	[1],[2]	'	'	'	'	'
SandRidge common stock price (in dollars per share)	'	'	'	$7.33	[1]	'	'	'	'	'
Face amount of Senior Notes issued	0	1,850,344	2,033,000	'		'	'	750,000	'	'
Long-term debt, fixed interest rate	'	'	'	'		8.13%	8.13%	8.13%	'	'
Cash balance adjustment	'	'	'	$13,091	[1],[3]	'	'	'	'	'
Commodity average price (in dollars per bbl for oil/dollars per mcf for natural gas)	'	'	'	'		'	'	'	113.62	3.83
Weighted average commodity prices, basis of price determination	'	'	'	'The commodity prices utilized were based upon commodity strip prices 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.		'	'	'	'	'
Commodity prices period valuation before escalation	'	'	'	'4 years		'	'	'	'	'
Annual escalation factor for forward commodity strip prices beginning the fifth year through end of production	'	'	'	2.00%		'	'	'	'	'
[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.

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Dynamic Acquisition - Unaudited Pro Forma Results of Operations (Details) (Dynamic Acquisition, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Dynamic Acquisition	'		'
Business Acquisition [Line Items]	'		'
Revenues	$2,908,899	[1]	$1,932,945	[2]
Net income	39,563	[1]	509,644	[2]
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	($120,962)	[1]	$399,278	[2]
(Loss) earnings per common share	'		'
Basic (in dollars per share)	($0.25)	[1]	$0.84	[2]
Diluted (in dollars per share)	($0.25)	[1]	$0.80	[2]
[1]	Pro forma net income, loss applicable to SandRidge Energy, Inc. common stockholders and loss per common share exclude a $122.7 million bargain purchase gain, a $100.3 million partial valuation allowance release included in income tax benefit, $10.9 million of fees incurred to secure financing for the Dynamic Acquisition included in interest expense and $13.0 million of transaction costs incurred and included in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2012.
[2]	Pro forma net income, income available to SandRidge Energy, Inc. common stockholders and earnings per common share include a $122.7 million bargain purchase gain, a $100.3 million partial valuation allowance release, $10.9 million of fees incurred to secure financing and $13.0 million of transaction costs.

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures - Dynamic Acquisition - Unaudited Pro Forma Results of Operations (Parenthetical) (Details) (USD $)	12 Months Ended			0 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Apr. 17, 2012		Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011
				Dynamic Acquisition		Dynamic Acquisition	Pro Forma	Pro Forma
							Dynamic Acquisition	Dynamic Acquisition
Business Acquisition [Line Items]	'	'	'	'		'	'	'
Bargain purchase gain	$0	$122,696,000	$0	$122,696,000	[1]	'	($122,696,000)	$122,696,000
Valuation allowance release	3,842,000	-100,288,000	-6,986,000	'		-100,288,000	100,288,000	-100,288,000
Fees to secure financing for acquisition	'	'	'	'		'	-10,900,000	10,900,000
Acquisition related costs	'	'	'	'		$13,000,000	($13,000,000)	$13,000,000
[1]	The bargain purchase gain resulted 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.

Acquisitions_and_Divestitures_5

Acquisitions and Divestitures - Gulf of Mexico Property Acquisitions - Final Valuation of Assets Acquired and Liabilities Assumed (Details) (Gulf of Mexico Properties, USD $)	0 Months Ended
In Thousands, unless otherwise specified	Jun. 20, 2012
Gulf of Mexico Properties	'
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 obligations	-55,443
Total identifiable net assets	$43,282

Acquisitions_and_Divestitures_6

Acquisitions and Divestitures - Gulf of Mexico Property Acquisitions - Unaudited Pro Forma Results of Operations (Details) (Gulf of Mexico Properties, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Gulf of Mexico Properties	'	'
Business Acquisition [Line Items]	'	'
Revenues	$2,759,381	$1,502,325
Net income	247,035	191,073
Income available to SandRidge Energy, Inc. common stockholders	$86,510	$81,167
Earnings per common share	'	'
Basic (in dollars per share)	$0.19	$0.20
Diluted (in dollars per share)	$0.19	$0.20

Acquisitions_and_Divestitures_7

Acquisitions and Divestitures - Permian Propertites Disposal - Revenue and Expense Information (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Disposal, Revenue and Expense Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

$465,108

$493,603

$512,987

$511,690

$1,338,098

$532,798

$478,434

$381,635

$1,983,388

$2,730,965

$1,415,213

Direct operating expenses

'

'

'

'

'

'

'

'

682,830

1,431,672

498,563

Permian Properties

'

'

'

'

'

'

'

'

'

'

'

Disposal, Revenue and Expense Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

68,027

[1]

566,075

614,666

Direct operating expenses

'

'

'

'

'

'

'

'

$17,453

[1]

$130,337

$144,066

[1]

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

Acquisitions_and_Divestitures_8

Acquisitions and Divestitures - Drilling and Completion Costs Associated with Sale of Working Interests (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Drilling Carry Transaction Activities [Line Items]	'
Total Drilling Carry	$1,000,000
Drilling Carry Recorded	794,400
Drilling Carry Remaining	205,600
Atinum MidCon I, LLC	'
Drilling Carry Transaction Activities [Line Items]	'
Total Drilling Carry	250,000
Drilling Carry Recorded	250,000
Drilling Carry Remaining	0
Repsol E&P USA, Inc.	'
Drilling Carry Transaction Activities [Line Items]	'
Total Drilling Carry	750,000
Drilling Carry Recorded	544,400
Drilling Carry Remaining	$205,600

Acquisitions_and_Divestitures_9

Acquisitions and Divestitures - Additional Information (Details) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Share data in Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 17, 2012

Dec. 31, 2013

Dec. 31, 2012

Jun. 20, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jul. 31, 2011

Aug. 31, 2011

Nov. 30, 2011

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dynamic Acquisition

Dynamic Acquisition

Dynamic Acquisition

Gulf of Mexico Properties

Gulf of Mexico Properties

Gulf of Mexico Properties

2011 Divestitures

Wolfberry

New Mexico

East Texas

Tertiary

Permian Properties

Atinum MidCon I, LLC and Repsol E&P USA, Inc.

Atinum MidCon I, LLC and Repsol E&P USA, Inc.

Mississippian Properties

Noncontrolling Interest

Permian Properties

Business Acquisitions and Dispositions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (loss) on divestiture

'

'

'

'

'

'

'

'

'

$0

'

'

'

$0

($398,900,000)

'

'

$0

($71,700,000)

Proceeds from sale of oil and natural gas properties

'

'

'

'

'

'

'

'

'

'

151,600,000

199,000,000

225,400,000

130,800,000

2,600,000,000

'

'

'

'

Percentage of equity interests acquired

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase price of acquired entity

'

'

'

1,235,229,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash consideration

'

'

'

680,000,000

[1],[2]

'

'

43,282,000

'

'

'

'

'

'

'

'

'

'

'

'

Issuance of common stock in acquisition (in shares)

'

'

'

73,962

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue of acquiree since acquisition date

'

'

'

'

'

365,000,000

'

'

26,200,000

'

'

'

'

'

'

'

'

'

'

Earnings of acquiree since acquisition date

'

'

'

'

'

81,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisition related costs

'

'

'

'

'

13,000,000

'

'

200,000

'

'

'

'

'

'

'

'

'

'

Measurement period adjustments to the preliminary purchase price allocation

'

'

'

'

0

'

'

-4,800,000

'

'

'

'

'

'

'

'

'

'

'

Goodwill

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

Earnings on oil and gas properties

'

'

'

'

'

'

'

'

19,100,000

'

'

'

'

'

'

'

'

'

'

Cumulative proceeds from sale of working interest subject to drilling carry

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000,000

'

Total Drilling Carry

1,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000,000

'

Drilling carry recorded as reduction of capital expenditures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

408,000,000

367,600,000

'

'

Bargain purchase gain

$0

($122,696,000)

$0

($122,696,000)

[3]

'

'

$0

'

'

'

'

'

'

'

'

'

'

'

'

[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]

The bargain purchase gain resulted 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.

Variable_Interest_Entities_Gre

Variable Interest Entities - Grey Ranch, L.P. - Assets and Liabilities Included in Consolidated Balance Sheets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Variable Interest Entity [Line Items]	'	'	'	'
Cash and cash equivalents	$814,663,000	$309,766,000	$207,681,000	$5,863,000
Accounts receivable, net	349,218,000	445,506,000	'	'
Prepaid expenses	39,253,000	31,319,000	'	'
Other current assets	21,831,000	19,043,000	'	'
Total current assets	1,241,823,000	1,142,885,000	'	'
Other property, plant and equipment, net	566,222,000	582,375,000	'	'
Accounts payable and accrued expenses	812,488,000	766,544,000	'	'
Grey Ranch Plant, L.P	'	'	'	'
Variable Interest Entity [Line Items]	'	'	'	'
Cash and cash equivalents	132,000	1,080,000	'	'
Accounts receivable, net	16,000	20,000	'	'
Prepaid expenses	32,000	64,000	'	'
Other current assets	109,000	109,000	'	'
Total current assets	289,000	1,273,000	'	'
Other property, plant and equipment, net	1,163,000	1,246,000	'	'
Total assets	1,452,000	2,519,000	'	'
Accounts payable and accrued expenses	129,000	274,000	'	'
Total liabilities	$129,000	$274,000	'	'

Variable_Interest_Entities_Roy

Variable Interest Entities - Royalty Trusts - Initial Public Offering (Details) (USD $)

1 Months Ended

1 Months Ended

1 Months Ended

In Thousands, except Share data, unless otherwise specified

Apr. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Mississippian Trust I

Mississippian Trust I

Mississippian Trust I

Permian Trust

Permian Trust

Permian Trust

Mississippian Trust II

Mississippian Trust II

Mississippian Trust II

Variable Interest Entity [Line Items]

'

'

'

'

'

'

'

'

'

Net proceeds of offering (in millions)

$336,893

'

'

$580,635

'

'

$587,087

'

'

Total outstanding common units (in shares)

21,000,000

'

'

39,375,000

'

'

37,293,750

'

'

Total outstanding subordinated units (in shares)

7,000,000

'

'

13,125,000

'

'

12,431,250

'

'

Beneficial interest owned by Company

38.40%

[1]

26.90%

26.90%

34.30%

[1]

28.50%

30.50%

39.90%

[1]

37.60%

39.90%

Liquidation date

31-Dec-30

[2]

'

'

31-Mar-31

[2]

'

'

31-Dec-31

[2]

'

'

[1]

Subsequent to the initial public offerings, the Company sold common units of the Royalty Trusts 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 the Royalty Trust unitholders.

Variable_Interest_Entities_Roy1

Variable Interest Entities - Royalty Trusts - Initial Public Offering (Parenthetical) (Details) (Royalty Trusts)	12 Months Ended
	Dec. 31, 2013
Royalty Trusts	'
Variable Interest Entity [Line Items]	'
Percentage of royalty interest conveyed to company at trust termination	50.00%
Percentage of royalty interest sold at trust termination	50.00%

Variable_Interest_Entities_Roy2

Variable Interest Entities - Royalty Trusts - Distributions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Variable Interest Entity [Line Items]	'		'		'
Distributions to third-party unitholders	$206,470		$181,727		$60,200
Royalty Trusts	'		'		'
Variable Interest Entity [Line Items]	'		'		'
Total distributions	299,674	[1]	274,979	[2]	91,162
Distributions to third-party unitholders	$206,470	[1]	$181,727	[2]	$57,449
[1]	Subordination thresholds were not met for the Mississippian Trust I’s second and third quarter 2013 distributions or for the Permian Trust’s second quarter 2013 distribution, resulting in reduced distributions to the Company on its subordinated units for these periods.
[2]	The Company received incentive distributions from the Mississippian Trust I during the first and second quarters of 2012 and the third quarter of 2011.

Variable_Interest_Entities_Roy3

Variable Interest Entities - Royalty Trusts - Open Oil and Natural Gas Commodity Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2013
	MBbls
Oil price swaps | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	8,813
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	92.98
Oil price swaps | January 2015 - December 2015	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	7,979
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	86.13
Natural gas collars | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	937
Collar range, minimum	4
Collar range, maximum	7.78
Natural gas collars | January 2015 - December 2015	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	1,010
Collar range, minimum	4
Collar range, maximum	8.55
Royalty Trusts | Oil price swaps | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	1,862
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	100.7
Royalty Trusts | Oil price swaps | January 2015 - December 2015	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	630
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	101.03
Royalty Trusts | Natural gas collars | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	937
Collar range, minimum	4
Collar range, maximum	7.78
Royalty Trusts | Natural gas collars | January 2015 - December 2015	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	1,010
Collar range, minimum	4
Collar range, maximum	8.55
Royalty Trusts | Novated Contract | Oil price swaps | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	991
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	100.79
Royalty Trusts | Novated Contract | Oil price swaps | January 2015 - March 2015	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	141
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	100.9

Variable_Interest_Entities_Roy4

Variable Interest Entities - Royalty Trusts - Assets and Liabilities Included in Consolidated Balance Sheets (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
Variable Interest Entity [Line Items]	'		'		'	'
Cash and cash equivalents	$814,663,000		$309,766,000		$207,681,000	$5,863,000
Accounts receivable	349,218,000		445,506,000		'	'
Derivative contracts	12,779,000		71,022,000		'	'
Total current assets	1,241,823,000		1,142,885,000		'	'
Investment in royalty interests(2)	11,504,422,000		13,128,784,000		9,658,689,000	'
Less: accumulated depletion	-5,762,969,000		-5,231,182,000		-4,791,534,000	'
Investment in royalty interests, net	5,741,453,000		7,897,602,000		4,867,155,000	'
Derivative contracts	14,126,000		23,617,000		'	'
Accounts payable and accrued expenses	812,488,000		766,544,000		'	'
Royalty Trusts	'		'		'	'
Variable Interest Entity [Line Items]	'		'		'	'
Cash and cash equivalents	7,912,000	[1]	7,445,000	[1]	'	'
Accounts receivable	22,540,000		28,596,000		'	'
Derivative contracts	4,983,000		10,286,000		'	'
Total current assets	35,435,000		46,327,000		'	'
Investment in royalty interests(2)	1,325,942,000	[2]	1,325,942,000	[2]	'	'
Less: accumulated depletion	-186,095,000		-103,746,000		'	'
Investment in royalty interests, net	1,139,847,000		1,222,196,000		'	'
Derivative contracts	1,476,000		7,660,000		'	'
Total assets	1,176,758,000		1,276,183,000		'	'
Accounts payable and accrued expenses	3,393,000		1,101,000		'	'
Total liabilities	$3,393,000		$1,101,000		'	'
[1]	Includes $3.0 million held by the trustee at December 31, 2013 and 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 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 at the time of conveyance.

Variable_Interest_Entities_Roy5

Variable Interest Entities - Royalty Trusts - Assets and Liabilities Included in Consolidated Balance Sheets (Parenthetical) (Details) (Royalty Trusts, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Royalty Trusts	'	'
Variable Interest Entity [Line Items]	'	'
Reserves for future expenses	$3	$3

Variable_Interest_Entities_Roy6

Variable Interest Entities - Royalty Trusts - Ownership Interest (Details)

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2012

Mississippian Trust I

Mississippian Trust I

Mississippian Trust I

Permian Trust

Permian Trust

Permian Trust

Mississippian Trust II

Mississippian Trust II

Mississippian Trust II

Variable Interest Entity [Line Items]

'

'

'

'

'

'

'

'

'

Beneficial interest owned by Company

26.90%

26.90%

38.40%

[1]

28.50%

30.50%

34.30%

[1]

37.60%

39.90%

39.90%

[1]

[1]

Subsequent to the initial public offerings, the Company sold common units of the Royalty Trusts 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.

Variable_Interest_Entities_PGC

Variable Interest Entities - PGC - Amounts due to/from the Company (Details) (Pinon Gathering Company LLC, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Pinon Gathering Company LLC	'	'
Variable Interest Entity [Line Items]	'	'
Accounts receivable due from PGC	$741	$1,976
Accounts payable due to PGC	$3,634	$5,053

Variable_Interest_Entities_Add

Variable Interest Entities - Additional Information (Details) (USD $)

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Grey Ranch Plant, L.P

Grey Ranch Plant, L.P

Grey Ranch Plant Genpar, LLC (Genpar)

Royalty Trusts

Royalty Trusts

Mississippian Trust I

Mississippian Trust I

Mississippian Trust I

Permian Trust

Permian Trust

Permian Trust

Mississippian Trust II

Mississippian Trust II

Mississippian Trust II

Pinon Gathering Company LLC

Gas Gathering Agreement

Variable Interest Entity [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from the sale of royalty trust units

$28,985,000

$139,360,000

$0

'

'

'

$28,985,000

$139,360,000

'

'

'

'

'

'

'

'

'

'

Beneficial interest owned by Company

'

'

'

50.00%

'

50.00%

'

'

38.40%

[1]

26.90%

26.90%

34.30%

[1]

28.50%

30.50%

39.90%

[1]

37.60%

39.90%

'

Contributions from noncontrolling interest owners

1,579,000

'

'

1,579,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling interest ownership percentage

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling interest, limited partnerships

'

'

'

700,000

1,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage ownership of another VIE

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

Total liabilities

'

'

'

129,000

274,000

0

3,393,000

1,101,000

'

'

'

'

'

'

'

'

'

'

Initial offering period

'

'

'

'

'

'

'

'

'April 2011

'

'

'August 2011

'

'

'April 2012

'

'

'

Percentage of subordinated units to total units

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

Royalty Trust subordinated units distributions

'

'

'

'

'

'

'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.

'

'

'

'

'

'

'

'

'

'

'

Percentage of cash available in excess of target distribution paid for incentive distribution

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

Royalty Trust incentive distributions

'

'

'

'

'

'

'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.

'

'

'

'

'

'

'

'

'

'

'

Outstanding balance under loan commitment

'

'

'

'

'

'

0

0

'

'

'

'

'

'

'

'

'

'

Development period deadline under development agreement latest date

'

'

'

'

'

'

'

'

'

31-Dec-15

'

'

31-Mar-16

'

'

31-Dec-16

'

'

Period drilling obligation to Royalty Trust fulfilled

'

'

'

'

'

'

'

'

'

'In the second quarter of 2013

'

'

'

'

'

'

'

'

Maximum amount recoverable by trusts under the lien

'

'

'

'

'

'

124,600,000

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling interest in VIEs

'

'

'

'

'

'

$1,300,000,000

$1,500,000,000

'

'

'

'

'

'

'

'

'

'

Gas gathering and operations and maintenance agreement end date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30-Jun-29

[1]

Subsequent to the initial public offerings, the Company sold common units of the Royalty Trusts 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.

Fair_Value_Measurements_Signif

Fair Value Measurements - Significant Unobservable Inputs (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Significant Unobservable Inputs	'	'	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis	$0	($512)	($4,252)	($222,554)
Oil basis swaps | Fair Value Measurements Level 3	'	'	'	'
Significant Unobservable Inputs	'	'	'	'
Derivative, weighted average forward price (in dollars per barrel)	'	14.74	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis	$0	($512)	'	'
Minimum | Oil basis swaps | Fair Value Measurements Level 3	'	'	'	'
Significant Unobservable Inputs	'	'	'	'
Derivative, forward price (in dollars per barrel)	'	10	'	'
Maximum | Oil basis swaps | Fair Value Measurements Level 3	'	'	'	'
Significant Unobservable Inputs	'	'	'	'
Derivative, forward price (in dollars per barrel)	'	21.98	'	'

Fair_Value_Measurements_Assets

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) (Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	$68,568		$132,934
Liabilities measured at fair value	54,831		74,647
Restricted deposits	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	27,955		27,947
Commodity derivatives contracts	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	26,905		94,639
Liabilities measured at fair value	54,831		72,252
Investments	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	13,708		10,348
Interest rate swap	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Liabilities measured at fair value	'		2,395
Fair Value Measurements Level 1	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	41,663		38,295
Liabilities measured at fair value	0		0
Fair Value Measurements Level 1 | Restricted deposits	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	27,955		27,947
Fair Value Measurements Level 1 | Commodity derivatives contracts	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0		0
Liabilities measured at fair value	0		0
Fair Value Measurements Level 1 | Investments	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	13,708		10,348
Fair Value Measurements Level 1 | Interest rate swap	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Liabilities measured at fair value	'		0
Fair Value Measurements Level 2	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	50,274		130,220
Liabilities measured at fair value	78,200		109,716
Fair Value Measurements Level 2 | Restricted deposits	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0		0
Fair Value Measurements Level 2 | Commodity derivatives contracts	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	50,274		130,220
Liabilities measured at fair value	78,200		107,321
Fair Value Measurements Level 2 | Investments	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0		0
Fair Value Measurements Level 2 | Interest rate swap	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Liabilities measured at fair value	'		2,395
Fair Value Measurements Level 3	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0		183
Liabilities measured at fair value	0		695
Fair Value Measurements Level 3 | Restricted deposits	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0		0
Fair Value Measurements Level 3 | Commodity derivatives contracts	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0		183
Liabilities measured at fair value	0		695
Fair Value Measurements Level 3 | Investments	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0		0
Fair Value Measurements Level 3 | Interest rate swap	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Liabilities measured at fair value	'		0
Netting	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	-23,369	[1]	-35,764	[1]
Liabilities measured at fair value	-23,369	[1]	-35,764	[1]
Netting | Restricted deposits	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0	[1]	0	[1]
Netting | Commodity derivatives contracts	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	-23,369	[1]	-35,764	[1]
Liabilities measured at fair value	-23,369	[1]	-35,764	[1]
Netting | Investments	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Assets measured at fair value	0	[1]	0	[1]
Netting | Interest rate swap	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Liabilities measured at fair value	'		$0	[1]
[1]	Represents the impact of netting assets and liabilities with counterparties with which the right of offset exists.

Fair_Value_Measurements_Reconc

Fair Value Measurements - Reconciliation of Financial Assets and Liabilities Measured at Fair Value on Recurring Basis using Significant Unobservable Inputs (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation	'	'	'
Beginning balance of Level 3	($512)	($4,252)	($222,554)
Gain (loss) on derivative contracts	-133	-5,460	40,907
Purchases	'	5,697	'
Cash paid on settlements	645	3,503	60,127
Transfers(1)	'	'	117,268	[1]
Ending balance of Level 3	0	-512	-4,252
Commodity derivatives contracts	'	'	'
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation	'	'	'
Beginning balance of Level 3	-512	-4,252	-205,860
Gain (loss) on derivative contracts	-133	-5,460	44,075
Purchases	'	5,697	'
Cash paid on settlements	645	3,503	50,713
Transfers(1)	'	'	106,820	[1]
Ending balance of Level 3	0	-512	-4,252
Interest rate swaps	'	'	'
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation	'	'	'
Beginning balance of Level 3	0	0	-16,694
Gain (loss) on derivative contracts	0	0	-3,168
Purchases	'	0	'
Cash paid on settlements	0	0	9,414
Transfers(1)	'	'	10,448	[1]
Ending balance of Level 3	$0	$0	$0
[1]	Fair values related to the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap were transferred from Level 3 to Level 2 in the fourth quarter of 2011 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the years ended December 31, 2013 and 2012, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

Fair_Value_Measurements_Reconc1

Fair Value Measurements - Reconciliation of Financial Assets and Liabilities Measured at Fair Value on Recurring Basis using Significant Unobservable Inputs (Parenthetical) (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]	'	'	'
Fair value, level 3 transfers out description	'Fair values related to the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap were transferred from Level 3 to Level 2 in the fourth quarter of 2011 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value.	'During the years ended December 31, 2013 and 2012, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.	'During the years ended December 31, 2013 and 2012, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

Fair_Value_Measurements_Estima

Fair Value Measurements - Estimated Fair Value and Carrying Value of Senior Notes (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Carrying value	$3,194,907		$4,301,083
9.875% Senior Notes due 2016	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Carrying value	0	[1]	356,657	[1]
8.0% Senior Notes due 2018	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Carrying value	0		750,000
8.75% Senior Notes due 2020	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Carrying value	444,736	[2]	444,127	[2]
7.5% Senior Notes due 2021	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Carrying value	1,178,922	[3]	1,179,328	[3]
8.125% Senior Notes due 2022	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Carrying value	750,000		750,000
7.5% Senior Notes due 2023	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Carrying value	821,249	[4]	820,971	[4]
Fair Value Measurements Level 2 | 9.875% Senior Notes due 2016	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Fair value	0	[1]	392,913	[1]
Fair Value Measurements Level 2 | 8.0% Senior Notes due 2018	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Fair value	0		790,313
Fair Value Measurements Level 2 | 8.75% Senior Notes due 2020	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Fair value	486,000	[2]	490,500	[2]
Fair Value Measurements Level 2 | 7.5% Senior Notes due 2021	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Fair value	1,230,813	[3]	1,257,250	[3]
Fair Value Measurements Level 2 | 8.125% Senior Notes due 2022	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Fair value	795,000		823,125
Fair Value Measurements Level 2 | 7.5% Senior Notes due 2023	'		'
Fair Value Assets And Liabilities Measured On Recurring Basis	'		'
Fair value	$837,375	[4]	$882,750	[4]
[1]	Carrying value is net of $8,843 discount at December 31, 2012.
[2]	Carrying value is net of $5,264 and $5,873 discount at December 31, 2013 and 2012, respectively.
[3]	Carrying value includes a premium, applicable to notes issued in August 2012, of $3,922 and $4,328 at December 31, 2013 and 2012, respectively.
[4]	Carrying value is net of $3,751 and $4,029 discount at December 31, 2013 and 2012, respectively.

Fair_Value_Measurements_Estima1

Fair Value Measurements - Estimated Fair Value and Carrying Value of Senior Notes (Parenthetical) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
9.875% Senior Notes due 2016	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis	'	'
Long-term debt, fixed interest rate	9.88%	9.88%
Debt maturity date	'2016	'2016
Long term debt, discount	'	$8,843
8.0% Senior Notes due 2018	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis	'	'
Long-term debt, fixed interest rate	8.00%	8.00%
Debt maturity date	'2018	'2018
8.75% Senior Notes due 2020	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis	'	'
Long-term debt, fixed interest rate	8.75%	8.75%
Debt maturity date	'2020	'2020
Long term debt, discount	5,264	5,873
7.5% Senior Notes due 2021	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis	'	'
Long-term debt, fixed interest rate	7.50%	7.50%
Debt maturity date	'2021	'2021
Long term debt, premium	3,922	4,328
8.125% Senior Notes due 2022	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis	'	'
Long-term debt, fixed interest rate	8.13%	8.13%
Debt maturity date	'2022	'2022
7.5% Senior Notes due 2023	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis	'	'
Long-term debt, fixed interest rate	7.50%	7.50%
Debt maturity date	'2023	'2023
Long term debt, discount	3,751	$4,029

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Details) (Commodity derivatives contracts, Fair Value Measurements Level 3, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Commodity derivatives contracts | Fair Value Measurements Level 3	'
Loss (gain) on derivative contracts	$0.50

Accounts_Receivable_Summary_of

Accounts Receivable - Summary of Accounts Receivable (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Accounts Receivable, Net, Current [Abstract]	'	'	'	'
Oil, natural gas and NGL sales	$166,157	$215,450	'	'
Joint interest billing	168,596	202,405	'	'
Oil and natural gas services	17,904	21,186	'	'
Insurance receivable	2,500	4,590	'	'
Related party	0	978	'	'
Other	5,122	6,532	'	'
Accounts receivable, gross	360,279	451,141	'	'
Less: allowance for doubtful accounts	-11,061	-5,635	-3,906	-1,503
Total accounts receivable, net	$349,218	$445,506	'	'

Accounts_Receivable_Balance_an

Accounts Receivable - Balance and Activity in Allowance for Doubtful Accounts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Allowance for Doubtful Accounts Receivable [Roll Forward]	'		'		'
Allowance for doubtful accounts at January 1	$5,635		$3,906		$1,503
Additions charged to costs and expenses(1)	5,497	[1]	1,735	[1]	2,511	[1]
Deductions(2)	-71	[2]	-6	[2]	-108	[2]
Allowance for doubtful accounts at December 31	$11,061		$5,635		$3,906
[1]	Includes $2.7 million of allowance for receivables deemed uncollectible at December 31, 2013 primarily due to bankruptcy status of customers.
[2]	Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established.

Accounts_Receivable_Accounts_R

Accounts Receivable Accounts Receivable - Balance and Activity in Allowance for Doubtful Accounts (Parenthetical) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'		'
Additions charged to costs and expenses(1)	$5,497	[1]	$1,735	[1]	$2,511	[1]
Customer in Bankruptcy	'		'		'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'		'		'
Additions charged to costs and expenses(1)	$2,700		'		'
[1]	Includes $2.7 million of allowance for receivables deemed uncollectible at December 31, 2013 primarily due to bankruptcy status of customers.

Property_Plant_and_Equipment_D

Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified
Oil and natural gas properties	'		'		'
Proved	$10,972,816	[1]	$12,262,921	[1]	$8,969,296
Unproved	531,606		865,863		689,393
Total oil and natural gas properties	11,504,422		13,128,784		9,658,689
Less: accumulated depreciation, depletion and impairment	-5,762,969		-5,231,182		-4,791,534
Net oil and natural gas properties capitalized costs	5,741,453		7,897,602		4,867,155
Land	18,423		17,927		'
Non-oil and natural gas equipment	600,603	[2]	643,370	[2]	'
Buildings and structures	233,405	[3]	205,349	[3]	'
Total	852,431		866,646		'
Less accumulated depreciation and amortization	-286,209		-284,271		'
Other property, plant and equipment, net	566,222		582,375		'
Total property, plant and equipment, net	$6,307,675		$8,479,977		'
[1]	Includes cumulative capitalized interest of approximately $23.4 million and $11.7 million at December 31, 2013 and 2012, respectively.
[2]	Includes cumulative capitalized interest of approximately $4.3 million at both December 31, 2013 and 2012.
[3]	Includes cumulative capitalized interest of approximately $12.0 million and $7.1 million at December 31, 2013 and 2012, respectively.

Property_Plant_and_Equipment_P

Property, Plant and Equipment (Parenthetical) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Oil and gas proved properties	'	'
Property, Plant and Equipment [Line Items]	'	'
Cumulative capitalized interest	$23.40	$11.70
Non-oil and natural gas equipment	'	'
Property, Plant and Equipment [Line Items]	'	'
Cumulative capitalized interest	4.3	4.3
Building and structures	'	'
Property, Plant and Equipment [Line Items]	'	'
Cumulative capitalized interest	$12	$7.10

Property_Plant_and_Equipment_C

Property, Plant and Equipment - Capitalized Costs of Unproved Properties Excluded from Amortization (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
In Thousands, unless otherwise specified			Year Cost Incurred 2013		Year Cost Incurred 2012		Year Cost Incurred 2011		Year Cost Incurred 2010 and Prior
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'		'		'		'		'
Property acquisition, cumulative	$515,849		'		'		'		$75,434
Property acquisition	'		114,252		291,999		34,164		'
Exploration, cumulative	61,327	[1]	'		'		'		3,486	[1]
Exploration	'		48,764	[1]	5,479	[1]	3,598	[1]	'
Total costs incurred, cumulative	577,176		'		'		'		78,920
Total costs incurred	'		$163,016		$297,478		$37,762		'
[1]	Includes $45.6 million of pipe inventory costs incurred ($42.6 million in 2013, $2.8 million in 2012 and $0.2 million in 2010 and prior years).

Property_Plant_and_Equipment_C1

Property, Plant and Equipment - Capitalized Costs of Unproved Properties Excluded from Amortization (Parenthetical) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
In Millions, unless otherwise specified		Year Cost Incurred 2013	Year Cost Incurred 2012	Year Cost Incurred 2010 and Prior
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'	'	'	'
Pipe inventory costs, cumulative	$45.60	'	'	$0.20
Pipe inventory costs, period costs	'	$42.60	$2.80	'

Property_Plant_and_Equipment_A

Property, Plant and Equipment - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Abstract]	'	'	'
Cumulative full cost ceiling limitation impairment charges	$3,500,000,000	$3,500,000,000	'
Full cost ceiling impairments	$0	$0	$0
Average depreciation and depletion rate (per Boe)	16.81	16.93	13.57
Expected completion of evaluation activities on majority of unproved properties	'10 years	'	'

Impairment_Additional_Informat

Impairment - Additional Information (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2012

Gas Treating Plants and CO2 Compression Facilities

Gas Treating Plants and other Midstream Assets

Gas Treating Plants and other Midstream Assets

Gas Treating Plants and other Midstream Assets

Rigs

Drilling Assets

Drilling Assets

Corporate Asset

Software Costs

Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset impairment charges

'

$26,280,000

$316,004,000

$2,825,000

$79,300,000

$10,000,000

$2,100,000

$12,200,000

$0

$10,600,000

$11,100,000

$2,900,000

$1,300,000

Assets held-for-sale

'

'

'

'

'

'

'

'

'

6,200,000

5,900,000

'

'

Goodwill impairment loss

$235,400,000

'

$235,400,000

'

'

'

'

'

'

'

'

'

'

Other_Assets_Details

Other Assets (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]	'		'
Debt issuance costs, net of amortization(1)	$61,923	[1]	$83,643	[1]
Restricted deposits	27,955		27,947
Notes receivable on asset retirement obligations	11,640		11,433
Investments	13,708		10,348
Other	5,945		10,881
Total other assets	$121,171		$144,252
[1]	In 2013, the unamortized debt issuance costs associated with the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018 were written off at the time the Company redeemed these notes. See Note 12 for discussion of the senior note redemptions.

Accounts_Payable_and_Accrued_E2

Accounts Payable and Accrued Expenses (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts Payable and Accrued Liabilities, Current [Abstract]	'	'
Accounts payable and other accrued expenses	$341,008	$461,067
Accrued interest	80,740	92,125
Production payable	127,647	97,245
Drilling advances	184,203	68,742
Payroll and benefits	59,785	29,811
Convertible perpetual preferred stock dividends	16,572	16,572
Related party	2,533	982
Total accounts payable and accrued expenses	$812,488	$766,544

Construction_Contracts_Additio

Construction Contracts - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Construction Contracts [Line Items]	'	'	'
Billings and contract loss in excess of costs incurred	$0	$15,546,000	'
Construction contract revenue	23,349,000	796,323,000	0
Construction contract costs	23,349,000	796,323,000	0
Costs in excess of billings and contract loss	4,079,000	11,229,000	'
Century Plant	'	'	'
Construction Contracts [Line Items]	'	'	'
Construction agreement description	'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 plant for the purpose of separating and removing CO2 from the delivered natural gas stream	'	'
Construction contract price	'	796,323,000	'
Cumulative loss on construction contracts	'	180,000,000	'
Billings and contract loss in excess of costs incurred	'	15,546,000	'
Treating agreement contract term	'30 years	'	'
Construction contract revenue	'	796,323,000	'
Construction contract costs	'	796,323,000	'
Costs in excess of billings and contract loss	4,079,000	'	'
Transmission Expansion Projects	'	'	'
Construction Contracts [Line Items]	'	'	'
Construction agreement description	'In the second quarter of 2013, the Company substantially completed the construction of a series of electrical transmission expansion and upgrade projects in northern Oklahoma for a third party. The Company constructed these projects for a contract price of $23.3 million, which included agreed upon change orders.	'	'
Construction contract price	23,349,000	'	'
Construction contract revenue	23,349,000	'	'
Construction contract costs	23,349,000	'	'
Costs in excess of billings and contract loss	'	$11,229,000	'

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'		'
Debt	$3,194,907		$4,301,083
Less: current maturities of long-term debt	0		0
Long-term debt	3,194,907		4,301,083
Senior credit facility	'		'
Debt Instrument [Line Items]	'		'
Debt	0		0
9.875% Senior Notes due 2016, net of $8,843 discount at December 31, 2012	'		'
Debt Instrument [Line Items]	'		'
Debt	0	[1]	356,657	[1]
8.0% Senior Notes due 2018	'		'
Debt Instrument [Line Items]	'		'
Debt	0		750,000
8.75% Senior Notes due 2020, net of $5,264 and $5,873 discount, respectively	'		'
Debt Instrument [Line Items]	'		'
Debt	444,736	[2]	444,127	[2]
7.5% Senior Notes due 2021, including a premium of $3,922 and $4,328, respectively	'		'
Debt Instrument [Line Items]	'		'
Debt	1,178,922	[3]	1,179,328	[3]
8.125% Senior Notes due 2022	'		'
Debt Instrument [Line Items]	'		'
Debt	750,000		750,000
7.5% Senior Notes due 2023, net of $3,751 and $4,029 discount, respectively	'		'
Debt Instrument [Line Items]	'		'
Debt	$821,249	[4]	$820,971	[4]
[1]	Carrying value is net of $8,843 discount at December 31, 2012.
[2]	Carrying value is net of $5,264 and $5,873 discount at December 31, 2013 and 2012, respectively.
[3]	Carrying value includes a premium, applicable to notes issued in August 2012, of $3,922 and $4,328 at December 31, 2013 and 2012, respectively.
[4]	Carrying value is net of $3,751 and $4,029 discount at December 31, 2013 and 2012, respectively.

LongTerm_Debt_Parenthetical_De

Long-Term Debt (Parenthetical) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
9.875% Senior Notes due 2016, net of $8,843 discount at December 31, 2012	'	'
Debt Instrument [Line Items]	'	'
Debt maturity date	'2016	'2016
Long-term debt, fixed interest rate	9.88%	9.88%
Long term debt, discount	'	$8,843
8.0% Senior Notes due 2018	'	'
Debt Instrument [Line Items]	'	'
Debt maturity date	'2018	'2018
Long-term debt, fixed interest rate	8.00%	8.00%
8.75% Senior Notes due 2020, net of $5,264 and $5,873 discount, respectively	'	'
Debt Instrument [Line Items]	'	'
Debt maturity date	'2020	'2020
Long-term debt, fixed interest rate	8.75%	8.75%
Long term debt, discount	5,264	5,873
7.5% Senior Notes due 2021, including a premium of $3,922 and $4,328, respectively	'	'
Debt Instrument [Line Items]	'	'
Debt maturity date	'2021	'2021
Long-term debt, fixed interest rate	7.50%	7.50%
Long term debt, premium	3,922	4,328
8.125% Senior Notes due 2022	'	'
Debt Instrument [Line Items]	'	'
Debt maturity date	'2022	'2022
Long-term debt, fixed interest rate	8.13%	8.13%
7.5% Senior Notes due 2023, net of $3,751 and $4,029 discount, respectively	'	'
Debt Instrument [Line Items]	'	'
Debt maturity date	'2023	'2023
Long-term debt, fixed interest rate	7.50%	7.50%
Long term debt, discount	3,751	$4,029

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 31, 2013

Aug. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Mar. 31, 2011

Dec. 31, 2011

Sep. 30, 2012

Dec. 31, 2012

Aug. 31, 2012

Dec. 31, 2012

Apr. 30, 2012

Aug. 31, 2012

Dec. 31, 2013

Aug. 31, 2012

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Aug. 31, 2012

Senior credit facility

Senior credit facility

Senior credit facility

Senior credit facility

Senior credit facility

Senior credit facility

Senior credit facility

Senior Notes

Senior Notes Outstanding

8.0% Senior Notes due 2018

8.0% Senior Notes due 2018

8.0% Senior Notes due 2018

9.875% Senior Notes due 2016

9.875% Senior Notes due 2016

9.875% Senior Notes due 2016

9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018

8.125% Senior Notes due 2022

8.125% Senior Notes due 2022

7.5% Senior Notes due 2023

7.5% Senior Notes due 2023

7.5% Senior Notes due 2021

7.5% Senior Notes due 2021

7.5% Senior Notes due 2021

8.625% Senior Notes Due 2015

Senior Floating Rate Notes due 2014

Senior Floating Rate Notes due 2014

2012 Activity

2012 Activity

2012 Activity

2012 Activity

2012 Activity

2012 Activity

2012 Activity

2011 Activity

Addition to LIBOR per annum

Addition to LIBOR per annum

Addition to federal funds rate

Addition to Eurodollar rate per annum

Applicable margin to base rate per annum

Applicable margin to base rate per annum

Prior to additional debt issuance

Minimum

Maximum

2012 Senior Notes

2012 Senior Notes

8.125% Senior Notes due 2022

7.5% Senior Notes due 2023

7.5% Senior Notes due 2023

7.5% Senior Notes due 2021

7.5% Senior Notes due 2021

8.625% Senior Notes Due 2015

Senior credit facility

Senior credit facility

Senior credit facility

Senior credit facility

Senior credit facility

Senior credit facility

Senior credit facility

LIBOR

LIBOR

Eurodollar Rate

Minimum

Maximum

Minimum

Maximum

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt, debt to EBITDA, ratio maximum

'

'

'

'

'

'

'

'

'

4.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current assets to current liabilities, ratio minimum

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt, debt to EBITDA ratio, total funded debt determination

'

'

'

$10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt maturity date

'

'

'

'March 2017

'

'

'

'

'

'

'

'

'2018

'

'2018

'2016

'

'2016

'

'2022

'2022

'2023

'2023

'2021

'2021

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, financial covenants compliance

'

'

'

'As of and during the year ended December 31, 2013, the Company was in compliance with all applicable financial covenants under the senior credit facility.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, collateral

'

'

'

'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.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, minimum collateral amount of proved oil and gas reserves representing the discounted present value of reserves used in borrowing base determination

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, basis spread on variable rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.63%

'

'

'

'

'

'

'

'

'

1.75%

2.75%

0.50%

1.00%

0.75%

1.75%

'

Line of credit facility, unused capacity, commitment fee percentage

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, increase (decrease), net

'

'

'

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, average annual interest rates

'

'

'

'

'

2.69%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility maximum borrowings capacity

'

'

'

'

'

'

775,000,000

775,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000,000

Line of credit facility, amount outstanding

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, letters of credit outstanding

'

'

'

29,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt issuance cost, cumulative

'

'

'

'

'

'

'

'

'

'

'

70,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

41,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, covenant compliance

'

'

'

'

'

'

'

'

'

'

'As of and during the year ended December 31, 2013, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Fixed Rate Notes.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument issuance date, month and year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'April 2012

'

'August 2012

'

'

'

'

'

'

'

'

'

'

Debt instrument, face amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

900,000,000

'

'

'

'

'

750,000,000

'

825,000,000

'

275,000,000

'

'

'

'

'

'

'

'

Long-term debt, fixed interest rate

'

'

'

'

'

'

'

'

'

'

'

'

8.00%

'

8.00%

9.88%

'

9.88%

'

8.13%

8.13%

7.50%

7.50%

7.50%

7.50%

'

'

'

'

'

'

'

'

'

'

'

8.63%

'

'

'

'

'

'

'

Debt tender offer, aggregate principal amount tendered

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

650,000,000

'

'

'

'

'

'

'

Proceeds from debt, net of issuance costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100,000,000

'

730,100,000

'

'

'

'

'

'

'

'

'

'

'

'

Premium paid to purchase notes and unamortized debt issuance cost in relation to the notes

-82,005,000

-3,075,000

-38,232,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-82,005,000

'

'

'

'

'

'

'

-38,232,000

'

-3,075,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument redemption price per principal amount

'

'

'

'

'

'

'

'

'

'

'

'

'

1,052.77

'

'

1,061.34

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt tender offer, aggregate principal amount

'

'

'

'

'

'

'

'

'

'

'

'

'

750,000,000

'

'

365,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Selling price of Senior Notes issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

99.50%

'

101.63%

'

'

'

'

'

'

'

'

'

Percentage of aggregate senior notes outstanding principal amount purchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, repurchased face amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt maturities, repayments of principal in the next twelve months

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt maturities, in years two and three

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt maturities, in years four and five

'

'

'

'

'

'

'

'

'

'

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Interest Rate Description

'

'

'

'(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.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivatives_Fair_Value_of_Deri

Derivatives - Fair Value of Derivative Contracts (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	$50,274	$130,403
Derivative liabilities	-78,200	-110,411
Total net derivative contracts	-27,926	19,992
Current assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	18,368	91,346
Current assets | Oil price swaps	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	15,887	88,052
Current assets | Oil basis swaps	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	0	183
Current assets | Natural gas price swaps	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	1,598	0
Current assets | Oil collars - three way	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	706	0
Current assets | Natural gas collars	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	177	3,111
Noncurrent assets	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	31,906	39,057
Noncurrent assets | Oil price swaps	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	19,376	37,983
Noncurrent assets | Oil collars - three way	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	12,189	190
Noncurrent assets | Natural gas collars	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	341	884
Current liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-39,856	-35,184
Current liabilities | Oil price swaps	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-38,396	-31,991
Current liabilities | Oil basis swaps	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	0	-695
Current liabilities | Natural gas price swaps	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-1,460	0
Current liabilities | Oil collars - two way	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	0	-103
Current liabilities | Interest rate swap	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	0	-2,395
Noncurrent liabilities	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-38,344	-75,227
Noncurrent liabilities | Oil price swaps	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-38,344	-67,900
Noncurrent liabilities | Oil collars - three way	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	$0	($7,327)

Derivatives_Offsetting_Assets_

Derivatives - Offsetting Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
ASSETS	'	'
Derivative assets, gross amounts	$50,274	$130,403
Derivative assets, gross amounts offset	-23,369	-35,764
Derivative assets, amounts net of offset	26,905	94,639
Derivative assets, current	12,779	71,022
Derivative assets, noncurrent	14,126	23,617
Derivative assets, financial collateral	0	0
Derivative assets, net amount	26,905	94,639
LIABILITIES	'	'
Derivative liabilities, gross amounts	78,200	110,411
Derivative liabilities, gross amounts offset	-23,369	-35,764
Derivative liabilities, current	34,267	14,860
Derivative liabilities, noncurrent	20,564	59,787
Derivative liabilities, amount net of offset	54,831	74,647
Derivative liabilities, financial collateral	-54,831	-74,647
Derivative liabilities, net amount	0	0
Current assets	'	'
ASSETS	'	'
Derivative assets, gross amounts	18,368	91,346
Derivative assets, gross amounts offset	-5,589	-20,324
Derivative assets, financial collateral	0	0
Derivative assets, net amount	12,779	71,022
Noncurrent assets	'	'
ASSETS	'	'
Derivative assets, gross amounts	31,906	39,057
Derivative assets, gross amounts offset	-17,780	-15,440
Derivative assets, financial collateral	0	0
Derivative assets, net amount	14,126	23,617
Current liabilities	'	'
LIABILITIES	'	'
Derivative liabilities, gross amounts	39,856	35,184
Derivative liabilities, gross amounts offset	-5,589	-20,324
Derivative liabilities, financial collateral	-34,267	-14,860
Derivative liabilities, net amount	0	0
Noncurrent liabilities	'	'
LIABILITIES	'	'
Derivative liabilities, gross amounts	38,344	75,227
Derivative liabilities, gross amounts offset	-17,780	-15,440
Derivative liabilities, financial collateral	-20,564	-59,787
Derivative liabilities, net amount	$0	$0

Derivatives_Open_Commodity_Der

Derivatives - Open Commodity Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2013
	MMcf
Natural gas price swaps | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	35,490
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	4.2
Oil price swaps | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	8,813
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	92.98
Oil price swaps | January 2015 - December 2015	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	7,979
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	86.13
Oil collars - three way | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	8,213
Oil collars - three way | January 2014 - December 2014 | Sold Put	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Collar range, minimum	70
Oil collars - three way | January 2014 - December 2014 | Purchased Put	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Collar range, minimum	90.2
Oil collars - three way | January 2014 - December 2014 | Sold Call	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Collar range, maximum	100
Oil collars - three way | January 2015 - December 2015	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	2,920
Oil collars - three way | January 2015 - December 2015 | Sold Put	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Collar range, minimum	73.13
Oil collars - three way | January 2015 - December 2015 | Purchased Put	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Collar range, minimum	90.82
Oil collars - three way | January 2015 - December 2015 | Sold Call	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Collar range, maximum	103.13
Natural gas collars | January 2014 - December 2014	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	937
Collar range, minimum	4
Collar range, maximum	7.78
Natural gas collars | January 2015 - December 2015	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Notional (Oil in MBbl/Natural Gas in MMcf)	1,010
Collar range, minimum	4
Collar range, maximum	8.55

Derivatives_Additional_Informa

Derivatives - Additional Information (Details) (USD $)

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Apr. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Mississippian Trust I

Permian Trust

Mississippian Trust II

Senior Floating Rate Notes due 2014

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Interest rate swaps

Interest rate swaps

Interest rate swaps

Cash

Cash

Cash

Cash

Cash

Cash

Cash

Noncash

Fixed To Floating Interest Rate Swap Through April 1st 2013

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Interest rate swaps

Interest rate swaps

Interest rate swaps

Commodity Derivatives

Derivative Contracts Early Settlements

Amendment

Derivative Instruments and Hedging Activities Disclosures [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, maturity date

'

'

'

'

'

'

1-Apr-13

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative liability, notional amount

'

'

'

'

'

'

$350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, fixed interest rate

'

'

'

'

'

'

6.69%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative agreement effective date

'

'

'

1-Apr-11

1-Aug-11

1-Apr-12

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commodity derivative contracts covering volumes of oil and gas production, date

'

'

'

31-Dec-15

31-Mar-15

31-Dec-14

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss (gain) on derivative contracts

47,123,000

-241,419,000

-44,075,000

'

'

'

'

-22,900,000

132,800,000

-103,700,000

40,900,000

-19,600,000

193,500,000

-669,900,000

254,600,000

47,123,000

-241,419,000

-44,075,000

'

'

'

-3,200,000

-100,700,000

37,600,000

29,600,000

'

'

'

117,100,000

Interest expense

$270,234,000

$303,349,000

$237,332,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$10,000

$1,200,000

$3,200,000

'

'

'

'

$2,400,000

$9,200,000

$9,400,000

'

Asset_Retirement_Obligations_R

Asset Retirement Obligations - Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'		'
Asset retirement obligations at January 1	$498,410		$128,116		$119,877
Liability incurred upon acquiring and drilling wells	5,078		7,479		5,716
Liability assumed in acquisition(1)	0	[1]	371,365	[1]	0	[1]
Revisions in estimated cash flows	-3,077		34,654		7,574
Liability settled or disposed in current period(2)	-113,071	[2]	-72,200	[2]	-14,419	[2]
Accretion(3)	36,777	[3]	28,996	[3]	9,368	[3]
Asset retirement obligations at December 31	424,117		498,410		128,116
Less: current portion	87,063		118,504		32,906
Asset retirement obligations, net of current	$337,054		$379,906		$95,210
[1]	Represents asset retirement obligations assumed in the acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.
[2]	Year ended December 31, 2013 includes $45.3 million for the decommissioning of various platforms, pipeline and associated wells in the Gulf of Mexico and $15.2 million of asset retirement obligations disposed in conjunction with the sale of the Permian Properties. Years ended December 31, 2013 and 2012 include the settlement of plugging and abandonment obligations associated with properties in the Gulf of Mexico. Year ended December 31, 2011 includes amounts related to the Permian Basin and east Texas properties sold during 2011.
[3]	Years ended December 31, 2013 and 2012 include accretion attributable to asset retirement obligations assumed in the acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.

Asset_Retirement_Obligations_R1

Asset Retirement Obligations - Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations (Parenthetical) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]	'		'		'
Asset retirement obligation, liabilities settled	($113,071)	[1]	($72,200)	[1]	($14,419)	[1]
Gulf of Mexico Properties | Platforms, pipelines and associated wells	'		'		'
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]	'		'		'
Asset retirement obligation, liabilities settled	-45,300		'		'
Permian Properties	'		'		'
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]	'		'		'
Asset retirement obligation, liabilities settled	($15,200)		'		'
[1]	Year ended December 31, 2013 includes $45.3 million for the decommissioning of various platforms, pipeline and associated wells in the Gulf of Mexico and $15.2 million of asset retirement obligations disposed in conjunction with the sale of the Permian Properties. Years ended December 31, 2013 and 2012 include the settlement of plugging and abandonment obligations associated with properties in the Gulf of Mexico. Year ended December 31, 2011 includes amounts related to the Permian Basin and east Texas properties sold during 2011.

Commitments_and_Contingencies_1

Commitments and Contingencies - Future Minimum Lease Payments under Noncancelable Operating Leases (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Years ending December 31	'
2014	$3,239
2015	2,988
2016	2,640
2017	1,756
2018	215
Total future obligation	$10,838

Commitments_and_Contingencies_2

Commitments and Contingencies - Oil and Natural Gas Transportation and Throughput Agreements (Details) (Transportation and Throughput Agreements, USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Transportation and Throughput Agreements	'
Years ending December 31	'
2014	$19,947
2015	11,794
2016	11,346
2017	11,315
2018	11,315
Thereafter	2,790
Total future obligation	$68,507

Commitments_and_Contingencies_3

Commitments and Contingencies - Natural Gas Gathering Agreement (Details) (Gas Gathering Agreement, USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Gas Gathering Agreement	'
Years ending December 31	'
2014	$42,542
2015	42,334
2016	42,272
2017	41,991
2018	41,825
Thereafter	100,559
Total future obligation	$311,523

Commitments_and_Contingencies_4

Commitments and Contingencies - Additional Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Total rental expense under operating leases	$3,600,000	$2,600,000	$1,500,000
Permian Trust	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Development period deadline under development agreement latest date	31-Mar-16	'	'
Mississippian Trust II	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Development period deadline under development agreement latest date	31-Dec-16	'	'
Permian Trust and Mississippian Trust II	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Estimated remaining drilling obligation	137,000,000	'	'
Gas Gathering Agreement | Pinon Gathering Company LLC	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Agreement expiration date	30-Jun-29	'	'
Treating Agreement	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Contract agreement, term	'30 years	'	'
Minimum delivery required (in Bcf)	3,200	'	'
Estimated minimum delivery required remaining (in Bcf)	3,000	'	'
Initial shortfall price, per Mcf	0.25	'	'
Shortfall price, per Mcf, final year of agreement	0.7	'	'
Accrued shortfall	32,700,000	'	'
Treating Agreement | Minimum	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Range of projected shortfall in one year	30,000,000	'	'
Treating Agreement | Maximum	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Range of projected shortfall in one year	37,000,000	'	'
Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd.	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Plaintiffs investment under participation agreement	16,000,000	'	'
General Land Office of the State of Texas	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Loss contingency, damages sought, value	13,000,000	'	'
Wesley West Minerals, Ltd and Longfellow Ranch Partners, LP	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Loss contingency, damages sought, value	45,500,000	'	'
Rig Commitments	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'
Minimum future commitments, 2014	20,300,000	'	'
Minimum future commitments, 2015	$1,100,000	'	'

Equity_Preferred_Stock_Details

Equity - Preferred Stock (Details)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Stockholders Equity Note [Line Items]	'	'
Shares authorized (in shares)	50,000	50,000
Shares oustanding at end of period (in shares)	7,650	7,650
8.5% Convertible perpetual preferred stock	'	'
Stockholders Equity Note [Line Items]	'	'
Shares oustanding at end of period (in shares)	2,650	2,650
6.0% Convertible perpetual preferred stock	'	'
Stockholders Equity Note [Line Items]	'	'
Shares oustanding at end of period (in shares)	2,000	2,000
7.0% Convertible perpetual preferred stock	'	'
Stockholders Equity Note [Line Items]	'	'
Shares oustanding at end of period (in shares)	3,000	3,000

Equity_Preferred_Stock_Terms_D

Equity - Preferred Stock Terms (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
8.5% Convertible perpetual preferred stock	'
Class of Stock [Line Items]	'
Preferred stock, dividend rate, percentage	8.50%
Liquidation preference per share	$100
Annual dividend per share	$8.50
Conversion rate per share to common stock	12.4805
Conversion date to common stock at Company's option(1)	20-Feb-14	[1]
6.0% Convertible perpetual preferred stock	'
Class of Stock [Line Items]	'
Preferred stock, dividend rate, percentage	6.00%
Liquidation preference per share	$100
Annual dividend per share	$6
Conversion rate per share to common stock	9.2115
Conversion date to common stock at Company's option(1)	21-Dec-14	[1]
7.0% Convertible perpetual preferred stock	'
Class of Stock [Line Items]	'
Preferred stock, dividend rate, percentage	7.00%
Liquidation preference per share	$100
Annual dividend per share	$7
Conversion rate per share to common stock	12.8791
Conversion date to common stock at Company's option(1)	20-Nov-15	[1]
[1]	Conversion is dependent on certain factors, including the Company’s stock trading above specified prices for a set period.

Equity_Preferred_Stock_Dividen

Equity - Preferred Stock Dividends (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Class of Stock [Line Items]	'	'	'
Dividends Paid	$38,953	$38,953	$39,011
Dividends Unpaid	16,572	16,572	16,572
Total	55,525	55,525	55,583
8.5% Convertible perpetual preferred stock	'	'	'
Class of Stock [Line Items]	'	'	'
Dividends Paid	14,078	14,078	14,078
Dividends Unpaid	8,447	8,447	8,447
Total	22,525	22,525	22,525
6.0% Convertible perpetual preferred stock	'	'	'
Class of Stock [Line Items]	'	'	'
Dividends Paid	6,500	6,500	6,500
Dividends Unpaid	5,500	5,500	5,500
Total	12,000	12,000	12,000
7.0% Convertible perpetual preferred stock	'	'	'
Class of Stock [Line Items]	'	'	'
Dividends Paid	18,375	18,375	18,433
Dividends Unpaid	2,625	2,625	2,625
Total	$21,000	$21,000	$21,058

Equity_Common_Stock_Details

Equity - Common Stock (Details)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]	'	'
Shares authorized (in shares)	800,000	800,000
Shares outstanding at end of period (in shares)	490,290	490,359
Shares held in treasury (in shares)	1,319	1,219

Equity_Treasury_Stock_Activity

Equity - Treasury Stock Activity (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity, Class of Treasury Stock [Line Items]	'	'	'
Value of shares withheld for taxes	$30,126	$11,312	$10,834
Treasury Stock	'	'	'
Equity, Class of Treasury Stock [Line Items]	'	'	'
Number of shares withheld for taxes	5,679	1,547	1,176
Value of shares withheld for taxes	$30,126	$11,312	$10,834

Equity_Restricted_Stock_Activi

Equity - Restricted Stock Activity (Details) (Restricted Stock, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock	'	'	'
Restricted Shares	'	'	'
Unvested restricted shares outstanding, beginning of year	15,328,000	13,386,000	9,476,000
Granted	7,462,000	7,604,000	8,003,000
Vested	-13,395,000	-4,394,000	-3,270,000
Forfeited/Canceled	-1,752,000	-1,268,000	-823,000
Unvested restricted shares outstanding, end of year	7,643,000	15,328,000	13,386,000
Weighted-Average Grant Date Fair Value	'	'	'
Unvested restricted shares outstanding, beginning of year	$8.07	$9.34	$10.89
Granted	$6.32	$7.46	$8.95
Vested	$7.85	$10.73	$12.91
Forfeited/Canceled	$7.33	$8.54	$9.17
Unvested restricted shares outstanding, end of year	$6.92	$8.07	$9.34

Equity_Additional_Information_

Equity - Additional Information (Details) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Apr. 17, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

8.5% Convertible perpetual preferred stock

6.0% Convertible perpetual preferred stock

7.0% Convertible perpetual preferred stock

Dynamic Acquisition

Stockholder Rights Plan

Restricted Stock

Restricted Stock

Restricted Stock

Restricted Stock

Treasury Stock

Treasury Stock

Treasury Stock

Series A Junior Participating Preferred Stock

Separation of Former Executives

Right

Stockholders Equity Note [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, dividend rate, percentage

'

'

'

8.50%

6.00%

7.00%

'

'

'

'

'

'

'

'

'

Preferred stock, shares authorized (in shares)

50,000,000

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, par value (in dollars per share)

$0.00

$0.00

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, shares designated

7,700,000

7,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, conversion term

'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. After a 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 convertible perpetual preferred stock is not redeemable by the Company at any time.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Issuance of common stock in acquisition (in shares)

'

'

'

'

'

'

73,962,000

[1]

'

'

'

'

'

'

'

'

Number of Rights issued per common share

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

Right expiration date

'

'

'

'

'

'

'

29-Apr-13

'

'

'

'

'

'

'

Stockholder settlement gross

'

$5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Shareholder receivable, number of annual installments

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional paid-in capital—stockholder receivable

-3,750,000

-5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Incentive compensation plans, vesting period (in years)

'

'

'

'

'

'

'

'

'4 years

'

'

'

'

'

'

Stock-based compensation

'

'

'

'

'

'

'

'

82,800,000

39,700,000

36,000,000

48,500,000

'

'

'

Stock based compensation, capitalized

'

'

'

'

'

'

'

'

5,500,000

7,500,000

7,600,000

'

'

'

'

Total fair value of awards vested during the period

'

'

'

'

'

'

'

'

71,600,000

32,100,000

30,200,000

'

'

'

'

Unrecognized compensation cost related to unvested awards

'

'

'

'

'

'

'

'

37,000,000

'

'

'

'

'

'

Unrecognized compensation cost related to unvested awards, weighted average period of recognition

'

'

'

'

'

'

'

'

'2 years 3 months 0 days

'

'

'

'

'

'

Shares available for grant under existing incentive compensation plans

'

'

'

'

'

'

'

'

9,600,000

'

'

'

'

'

'

Retirement of treasury stock

$0

$0

$0

'

'

'

'

'

'

'

'

'

($30,126,000)

($11,312,000)

($10,834,000)

Retirement of treasury stock (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

5,679,000

1,547,000

1,176,000

[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.

Incentive_Retirement_and_Defer2

Incentive, Retirement and Deferred Compensation Plans - Performance Unit Fair Value Assumptions (Details) (Performance Units, USD $)	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013
Performance Units	'	'
Employee Compensation Plans [Line Items]	'	'
Expected price volatility range, minimum	27.00%	'
Expected price volatility range, maximum	44.80%	'
Risk-free interest rate	0.40%	'
Fair value per unit (at grant date)	'	$69.38
Fair value per unit (at December 31, 2013)	$97.06	'

Incentive_Retirement_and_Defer3

Incentive, Retirement and Deferred Compensation Plans - Additional Information (Details) (USD $)

1 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Performance Units

Performance Units

Performance Units

Performance Units

Final Payments Under Existing Cash Bonus Program

Management Annual Incentive Plan

Management Annual Incentive Plan

Annual Incentive Plan

Retirement Plan

Retirement Plan

Retirement Plan

Retirement Plan

Deferred Compensation Plan

Deferred Compensation Plan

Deferred Compensation Plan

Deferred Compensation Plan

Minimum

Maximum

Minimum

Maximum

Maximum

Maximum

Employee Compensation Plans [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments to employees

'

'

'

'

$10.90

'

'

'

'

'

'

'

'

'

'

'

Incentive plans, payout percentages of target values

'

'

50.00%

200.00%

'

0.00%

200.00%

'

'

'

'

'

'

'

'

'

Accrued bonuses

'

'

'

'

'

'

'

30.2

'

'

'

'

'

'

'

'

Award, grants in period

31,142

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Award, accrued liability

'

1.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock-based compensation

'

1.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock based compensation, capitalized

'

0.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Performance units, vested in period

'

12,178

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total fair value of awards vested during the period

'

1.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Performance units, forfeited in period

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost related to unvested awards

'

1.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost related to unvested awards, weighted average period of recognition

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retirement plan, employer matching contribution, percent of match

'

'

'

'

'

'

'

'

100.00%

100.00%

100.00%

'

'

'

'

'

Retirement plan, employer matching contribution, percent of employees' gross pay

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

Retirement plan, cost recognized

'

'

'

'

'

'

'

'

11

11.4

7.4

'

'

'

'

'

Deferred compensation plan, employer match percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

Deferred compensation plan, compensation expense

'

'

'

'

'

'

'

'

'

'

'

'

$2.70

$3.50

$3.10

'

Income_Taxes_Benefit_Provision

Income Taxes - (Benefit) Provision for Income Taxes (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current	'	'	'
Federal	$3,842	($72)	$618
State	1,842	-2	551
Current, total	5,684	-74	1,169
Deferred	'	'	'
Federal	0	-97,410	-6,447
State	0	-2,878	-539
Deferred, total	0	-100,288	-6,986
Total provision (benefit)	5,684	-100,362	-5,817
Noncontrolling Interest	'	'	'
Deferred	'	'	'
Total provision (benefit)	308	304	109
Parent Company	'	'	'
Deferred	'	'	'
Total provision (benefit)	$5,376	($100,666)	($5,926)

Income_Taxes_Reconciliation_of

Income Taxes - Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate to Company's Actual Income Tax Benefit (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation Of Provision Of Income Taxes [Line Items]	'	'	'
Total provision (benefit)	$5,684	($100,362)	($5,817)
Parent Company	'	'	'
Reconciliation Of Provision Of Income Taxes [Line Items]	'	'	'
Computed at federal statutory rate	-178,078	51,173	54,800
State taxes, net of federal benefit	-886	8,913	5,231
Non-deductible expenses	2,589	7,247	6,394
Stock-based compensation	7,611	7,172	8,229
Net effects of consolidating the non-controlling interests’ tax provisions	-13,901	-37,047	-19,120
Bargain purchase gain	0	-42,944	0
Impairment of non-deductible goodwill	0	71,885	0
Change in valuation allowance	188,599	-66,429	-51,631
Valuation allowance release	0	-100,288	-5,290
Other	-558	-348	-4,539
Total provision (benefit)	$5,376	($100,666)	($5,926)

Income_Taxes_Deferred_Tax_Asse

Income Taxes - Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax liabilities	'		'
Investments(1)	$301,447	[1]	$334,331	[1]
Property, plant and equipment	180,140		198,424
Derivative contracts	0		24,819
Total deferred tax liabilities	481,587		557,574
Deferred tax assets	'		'
Derivative contracts	3,692		0
Allowance for doubtful accounts	20,358		17,713
Net operating loss carryforwards	973,675		859,328
Litigation settlement	355		7,200
Compensation and benefits	24,895		13,935
Alternative minimum tax credits and other carryforwards	46,624		42,242
Asset retirement obligations	147,626		172,229
Under-delivery obligation	15,012		0
Other	2,801		2,193
Total deferred tax assets	1,235,038		1,114,840
Valuation allowance	-753,451		-557,266
Net deferred tax liability	$0		$0
[1]	Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. See Note 4 for further discussion of the Royalty Trusts.

Income_Taxes_Unrecognized_Tax_

Income Taxes - Unrecognized Tax Benefits (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Balance at beginning of period	$1,330	$1,758
Changes to unrecognized tax benefits related to the current year	262	0
Changes to unrecognized tax benefits related to a prior year	-210	-428
Balance at end of period	$1,382	$1,330

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Details) (USD $)

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jul. 16, 2010

Dec. 31, 2008

Dec. 31, 2012

Jun. 30, 2011

Jul. 16, 2010

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dynamic Acquisition

Arena Acquisition

Arena Acquisition

Beginning Year

Minimum

Maximum

Ending Year

Beginning tax year

Beginning tax year as result of federal NOL carryforwards

Income Taxes [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reversal of deferred tax asset valuation allowance

($3,842,000)

$100,288,000

$6,986,000

'

'

$100,288,000

$6,986,000

'

'

'

'

'

'

'

Alternative minimum tax credits, not subject to expiration

13,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Federal net operating loss carryovers, subject to expiration

2,600,000,000

'

'

629,800,000

298,400,000

'

'

119,900,000

'

'

'

'

'

'

Operating loss carryforwards expiration year

'

'

'

'

'

'

'

'

'2023

'

'

'2033

'

'

Unrecognized excess tax benefits from stock based compensation

16,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized tax benefits

1,382,000

1,330,000

1,758,000

'

'

'

'

'

'

'

'

'

'

'

Unrecognized tax benefits that would affect the effective tax rate if recognized

900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized tax benefits, accrued gross interest

-100,000

30,000

100,000

'

'

'

'

'

'

'

'

'

'

'

Unrecognized tax benefits, accrued liability

100,000

200,000

'

'

'

'

'

'

'

'

'

'

'

'

Open tax year

'

'

'

'

'

'

'

'

'

'

'

'

'2010

'2003

Number of tax years open for state tax audit (in years)

'

'

'

'

'

'

'

'

'

'3 years

'5 years

'

'

'

Decrease in gross unrecognized tax benefits balance within next twelve months

$800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Earnings_Per_Share_Calculation

Earnings Per Share - Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Per Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Income (Loss), Basic

$5,198

[1],[2],[3]

($87,074)

[1],[2],[3]

($34,317)

[1],[2],[3]

($493,221)

[1],[2],[3]

($301,785)

[4],[5],[6]

($184,301)

[4],[5],[6]

$804,191

[4],[5],[6]

($232,059)

[4],[5],[6]

($609,414)

$86,046

$52,482

Weighted average shares, basic (in shares)

'

'

'

'

'

'

'

'

481,148

453,595

398,851

Basic earnings per share (in dollars)

$0.01

[7]

($0.18)

[7]

($0.07)

[7]

($1.03)

[7]

($0.63)

[7]

($0.39)

[7]

$1.74

[7]

($0.58)

[7]

($1.27)

$0.19

$0.13

Effect of dilutive securities

'

'

'

'

'

'

'

'

'

'

'

Restricted stock (in dollars)

'

'

'

'

'

'

'

'

0

[8]

0

0

Restricted stock (in shares)

'

'

'

'

'

'

'

'

'

2,420

7,794

Income (Loss), Diluted

'

'

'

'

'

'

'

'

($609,414)

$86,046

$52,482

Weighted average shares, diluted (in shares)

'

'

'

'

'

'

'

'

481,148

456,015

406,645

Diluted earnings per share (in dollars)

$0.01

[7]

($0.18)

[7]

($0.07)

[7]

($1.03)

[7]

($0.63)

[7]

($0.39)

[7]

$1.46

[7]

($0.58)

[7]

($1.27)

$0.19

$0.13

[1]

Includes loss (gain) on commodity derivative contracts of $40.9 million, $(103.7) million, $132.8 million and $(22.9) million for the first, second, third and fourth quarters, respectively.

[2]

Includes a $10.6 million impairment of various drilling assets and a $2.9 million impairment of a corporate asset in the second quarter of 2013 and a $2.1 million and $10.0 million impairment of certain midstream inventory, natural gas compressors, gas treating plants and a CO2 compression station in the second and fourth quarters of 2013, respectively.

[3]

Includes loss on sale of Permian Properties of $398.9 million in the first quarter of 2013.

[4]

Includes loss (gain) on commodity derivative contracts of $254.6 million, $(669.9) million, $193.5 million and $(19.6) million for the first, second, third and fourth quarters, respectively.

[5]

Includes a $235.4 million goodwill impairment and a $79.3 million impairment of gas treating plants and CO2 compression facilities in the fourth quarter of 2012.

[6]

Includes adjustments of $(4.8) million retrospectively applied to the second quarter of 2012 as a result of measurement period adjustments made to the preliminary purchase price allocation for the Dynamic Acquisition in the fourth quarter of 2012.

[7]

(Loss applicable) income available per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of (loss applicable) income available per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

[8]

Restricted stock awards covering 0.5 million shares were excluded from the computation of loss per share because their effect would have been antidilutive.

Earnings_Per_Share_Calculation1

Earnings Per Share - Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share (Parenthetical) (Details)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Antidilutive securities excluded from computation of earnings per share	0.5

Earnings_Per_Share_Additional_

Earnings Per Share - Additional Information (Details)	12 Months Ended
	Dec. 31, 2013
8.5% Convertible perpetual preferred stock	'
Earnings Per Share Disclosure [Line Items]	'
Preferred stock, dividend rate, percentage	8.50%
6.0% Convertible perpetual preferred stock	'
Earnings Per Share Disclosure [Line Items]	'
Preferred stock, dividend rate, percentage	6.00%
7.0% Convertible perpetual preferred stock	'
Earnings Per Share Disclosure [Line Items]	'
Preferred stock, dividend rate, percentage	7.00%

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Details) (USD $)	12 Months Ended			3 Months Ended	12 Months Ended
Share data in Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
				Former Chairman and CEO Severance	Former Chairman and CEO Severance	Employee Severance	Annual Sponsorship Amount	Lease with Related Party	Annual Lease Obligation to Related Party	Leasehold Improvements under Lease with Related Party
Related Party Transaction [Line Items]	'	'	'	'	'	'	'	'	'	'
Sales to related parties	$1,600,000	$12,800,000	$21,500,000	'	'	'	'	'	'	'
Employee termination benefits	122,505,000	0	0	'	57,900,000	23,200,000	'	'	'	'
Severance liability	'	'	'	'	4,600,000	'	'	'	'	'
Severance, Number of monthly installments	'	'	'	'	36	'	'	'	'	'
Severance, compensation cost of accelerated shares	'	'	'	36,800,000	'	'	'	'	'	'
Severance, number of accelerated shares	'	'	'	6.3	'	'	'	'	'	'
Sponsorship fees	'	'	'	'	'	'	3,300,000	'	'	'
Contract term (in years)	'	'	'	'	'	'	'	'3 years	'	'
Related party transaction amounts	'	'	'	'	'	'	'	'	$500,000	$3,300,000

Subsequent_Events_Royalty_Trus

Subsequent Events - Royalty Trust Distributions (Details) (Royalty Trust Distributions, USD $)	Jan. 30, 2014
In Thousands, unless otherwise specified
Royalty Trusts	'
Subsequent Event [Line Items]	'
Total distribution	$68,345
Amount to be distributed to third-party unitholders	53,118
Mississippian Trust I	'
Subsequent Event [Line Items]	'
Total distribution	10,508
Amount to be distributed to third-party unitholders	10,242
Permian Trust	'
Subsequent Event [Line Items]	'
Total distribution	33,677
Amount to be distributed to third-party unitholders	25,239
Mississippian Trust II	'
Subsequent Event [Line Items]	'
Total distribution	24,160
Amount to be distributed to third-party unitholders	$17,637

Subsequent_Events_Gulf_Propert

Subsequent Events - Gulf Properties Pro Forma Financial Information (Unaudited) (Details) (Gulf of Mexico Properties, Subsequent Event, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013
Gulf of Mexico Properties | Subsequent Event	'
Subsequent Event [Line Items]	'
Revenues	$1,356,152
Net loss(1)	-1,068,664	[1]
Loss attributable to SandRidge Energy, Inc. common stockholders(1)	($1,028,055)	[1]
(Loss) earnings per common share	'
Basic	($2.25)	[1]
Diluted	($2.25)	[1]
[1]	Includes pro forma ceiling impairment of $441.0 million, including $80.0 million allocated to noncontrolling interest and $361.0 million attributable to SandRidge Energy, Inc., for the year ended December 31, 2013.

Subsequent_Events_Subsequent_E

Subsequent Events Subsequent Events - Gulf Properties Pro Forma Financial Information (Unaudited) (Parenthetical) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Subsequent Event [Line Items]	'	'	'
Full cost ceiling impairments	$0	$0	$0
Subsequent Event | Gulf of Mexico Properties | Pro Forma	'	'	'
Subsequent Event [Line Items]	'	'	'
Full cost ceiling impairments	441	'	'
Subsequent Event | Gulf of Mexico Properties | Pro Forma | Noncontrolling Interest	'	'	'
Subsequent Event [Line Items]	'	'	'
Full cost ceiling impairments	80	'	'
Subsequent Event | Gulf of Mexico Properties | Pro Forma | Parent Company	'	'	'
Subsequent Event [Line Items]	'	'	'
Full cost ceiling impairments	$361	'	'

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Details) (USD $)

3 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

2 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Jan. 09, 2014

Jan. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 25, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Feb. 28, 2014

Feb. 25, 2014

Permian Trust

Permian Trust

Permian Trust

Royalty Trusts

Royalty Trusts

Subsequent Event

Royalty Trust Distributions

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Gulf of Mexico Properties

Gulf of Mexico Properties

Cash

Cash

Cash

Cash

Cash

Asset Retirement Obligations

Permian Trust

Royalty Trusts

Subsequent Event

Subsequent Event

Commodity Derivatives

Commodity Derivatives

Commodity Derivatives

Derivative Contracts Early Settlements

Derivative Contracts Early Settlements

Gulf of Mexico Properties

MMBoe

Commodity Derivatives

Gulf of Mexico Properties

Subsequent Event

Commodity Derivatives

Subsequent Event

Subsequent Event [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from the sale of royalty trust units

'

'

'

'

'

'

'

'

$28,985,000

$139,360,000

$0

'

'

'

$28,985,000

$139,360,000

$22,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Beneficial interest owned by Company

'

'

'

'

'

'

'

'

'

'

'

28.50%

30.50%

34.30%

[1]

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Subsequent event, description

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'On January 30, 2014, the Royalty Trusts announced quarterly distributions for the three-month period ended December 31, 2013. The following distributions will be paid on February 28, 2014 to holders of record as of the close of business on February 14, 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected distribution date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'February 28, 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distributions record date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'February 14, 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sale of oil and natural gas properties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

750,000,000

'

'

'

'

'

'

'

Asset retirement obligation assumed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

370,000,000

Fair value of guarantee as of year end

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,000,000

'

'

'

'

'

'

'

Restricted deposits

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

27,900,000

'

'

'

'

'

'

'

Consideration receivable, current

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14,000,000

'

'

'

'

'

'

'

Loss (gain) on derivative contracts

'

'

'

'

'

'

'

'

47,123,000

-241,419,000

-44,075,000

'

'

'

'

'

'

'

-22,900,000

132,800,000

-103,700,000

40,900,000

-19,600,000

193,500,000

-669,900,000

254,600,000

47,123,000

-241,419,000

-44,075,000

'

'

-3,200,000

-100,700,000

37,600,000

29,600,000

69,600,000

'

Production, MMBoe

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.1

'

'

'

'

'

'

Total revenues

465,108,000

493,603,000

512,987,000

511,690,000

1,338,098,000

532,798,000

478,434,000

381,635,000

1,983,388,000

2,730,965,000

1,415,213,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

627,200,000

'

'

'

'

'

'

Total expenses

'

'

'

'

'

'

'

'

$2,152,389,000

$2,405,769,000

$986,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$492,000,000

'

'

'

'

'

'

[1]

Subsequent to the initial public offerings, the Company sold common units of the Royalty Trusts 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.

Business_Segment_Information_S

Business Segment Information - Summarized Financial Information Concerning Segments (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

$465,108

$493,603

$512,987

$511,690

$1,338,098

$532,798

$478,434

$381,635

$1,983,388

$2,730,965

$1,415,213

Income (loss) from operations

97,979

[1],[2],[3]

6,088

[1],[2],[3]

86,458

[1],[2],[3]

-359,526

[1],[2],[3]

-209,690

[4],[5]

-75,871

[4],[5]

762,413

[4],[5]

-151,656

[4],[5]

-169,001

325,196

429,013

Interest income (expense), net

'

'

'

'

'

'

'

'

-270,234

-303,349

-237,332

Bargain purchase gain

'

'

'

'

'

'

'

'

0

122,696

0

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

-82,005

-3,075

-38,232

Other income (expense), net

'

'

'

'

'

'

'

'

12,445

4,741

3,122

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-508,795

146,209

156,571

Capital expenditures

'

'

'

'

'

'

'

'

1,423,883

[6]

2,173,982

[6]

1,816,494

[6]

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

666,645

657,830

380,244

Total assets

7,684,795

'

'

'

9,790,731

'

'

'

7,684,795

9,790,731

'

Exploration and Production

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

1,834,160

2,571,141

1,237,300

Income (loss) from operations

'

'

'

'

'

'

'

'

62,509

[7]

518,144

[7]

521,117

[7]

Interest income (expense), net

'

'

'

'

'

'

'

'

1,168

1,286

509

Bargain purchase gain

'

'

'

'

'

'

'

'

'

122,696

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

0

0

Other income (expense), net

'

'

'

'

'

'

'

'

5,487

1,868

3,601

Income (loss) before income taxes

'

'

'

'

'

'

'

'

69,164

643,994

525,227

Capital expenditures

'

'

'

'

'

'

'

'

1,319,012

[6]

1,951,490

[6]

1,697,691

[6]

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

605,242

598,101

328,753

Total assets

6,157,225

'

'

'

8,681,056

'

'

'

6,157,225

8,681,056

'

Drilling and Oil Field Services

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

66,641

116,633

103,298

Income (loss) from operations

'

'

'

'

'

'

'

'

-40,155

[8]

11,911

[8]

10,341

[8]

Interest income (expense), net

'

'

'

'

'

'

'

'

0

0

-95

Bargain purchase gain

'

'

'

'

'

'

'

'

'

0

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

0

0

Other income (expense), net

'

'

'

'

'

'

'

'

0

0

0

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-40,155

11,911

10,246

Capital expenditures

'

'

'

'

'

'

'

'

7,125

[6]

27,527

[6]

25,674

[6]

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

33,291

34,677

32,582

Total assets

158,737

'

'

'

199,523

'

'

'

158,737

199,523

'

Midstream Services

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

79,460

38,835

65,181

Income (loss) from operations

'

'

'

'

'

'

'

'

-21,567

[9]

-73,027

[9]

-12,975

[9]

Interest income (expense), net

'

'

'

'

'

'

'

'

-209

-559

-611

Bargain purchase gain

'

'

'

'

'

'

'

'

'

0

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

0

0

Other income (expense), net

'

'

'

'

'

'

'

'

-3,222

0

-485

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-24,998

-73,586

-14,071

Capital expenditures

'

'

'

'

'

'

'

'

55,706

[6]

80,413

[6]

38,514

[6]

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

7,972

7,188

4,650

Total assets

188,165

'

'

'

151,492

'

'

'

188,165

151,492

'

All Other

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

3,127

4,356

9,434

Income (loss) from operations

'

'

'

'

'

'

'

'

-169,788

[10]

-131,832

[10]

-89,470

[10]

Interest income (expense), net

'

'

'

'

'

'

'

'

-271,193

-304,076

-237,135

Bargain purchase gain

'

'

'

'

'

'

'

'

'

0

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

-82,005

-3,075

-38,232

Other income (expense), net

'

'

'

'

'

'

'

'

10,180

2,873

6

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-512,806

-436,110

-364,831

Capital expenditures

'

'

'

'

'

'

'

'

42,040

[6]

114,552

[6]

54,615

[6]

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

20,140

17,864

14,259

Total assets

1,180,668

'

'

'

758,660

'

'

'

1,180,668

758,660

'

Operating Segments

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

2,205,052

3,071,904

1,822,497

Operating Segments | Exploration and Production

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

1,834,480

2,571,544

1,237,565

Operating Segments | Drilling and Oil Field Services

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

187,456

379,345

390,485

Operating Segments | Midstream Services

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

179,989

116,659

183,912

Operating Segments | All Other

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

3,127

4,356

10,535

Intersegment Eliminations

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

-221,664

-340,939

-407,284

Intersegment Eliminations | Exploration and Production

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

-320

-403

-265

Intersegment Eliminations | Drilling and Oil Field Services

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

-120,815

-262,712

-287,187

Intersegment Eliminations | Midstream Services

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

-100,529

-77,824

-118,731

Intersegment Eliminations | All Other

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

$0

$0

($1,101)

[1]

Includes loss (gain) on commodity derivative contracts of $40.9 million, $(103.7) million, $132.8 million and $(22.9) million for the first, second, third and fourth quarters, respectively.

[2]

Includes a $10.6 million impairment of various drilling assets and a $2.9 million impairment of a corporate asset in the second quarter of 2013 and a $2.1 million and $10.0 million impairment of certain midstream inventory, natural gas compressors, gas treating plants and a CO2 compression station in the second and fourth quarters of 2013, respectively.

[3]

Includes loss on sale of Permian Properties of $398.9 million in the first quarter of 2013.

[4]

Includes loss (gain) on commodity derivative contracts of $254.6 million, $(669.9) million, $193.5 million and $(19.6) million for the first, second, third and fourth quarters, respectively.

[5]

Includes a $235.4 million goodwill impairment and a $79.3 million impairment of gas treating plants and CO2 compression facilities in the fourth quarter of 2012.

[6]

On an accrual basis and exclusive of acquisitions.

[7]

Income from operations includes impairment of the Company’s goodwill of $235.4 million for the year ended December 31, 2012.

[8]

For the year ended December 31, 2013, loss from operations includes impairment of $11.1 million on certain drilling assets.

[9]

For the years ended December 31, 2013 and 2012, loss from operations includes impairments of the Company’s gas treating plants in west Texas and other midstream assets of $3.9 million and $59.7 million, respectively.

[10]

For the year ended December 31, 2013, loss from operations includes a $2.9 million impairment of a corporate asset and an $8.3 million impairment of the Company’s CO2 compression facilities. For the year ended December 31, 2012, loss from operations includes a $19.6 million impairment of the Company’s CO2 compression facilities.

Business_Segment_Information_S1

Business Segment Information - Summarized Financial Information Concerning Segments (Parenthetical) (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Exploration and Production

Drilling Assets

Drilling Assets

Drilling Assets

Gas Treating Plants and other Midstream Assets

Gas Treating Plants and other Midstream Assets

Gas Treating Plants and other Midstream Assets

Gas Treating Plants and other Midstream Assets

Gas Treating Plants

Corporate Asset

Corporate Asset

CO2 Compression Facilities

CO2 Compression Facilities

Drilling and Oil Field Services

Midstream Services

Midstream Services

All Other

All Other

All Other

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill impairment loss

$235,400,000

'

$235,400,000

'

$235,400,000

'

'

'

'

'

'

'

'

'

'

'

'

Asset impairment charges

'

$26,280,000

$316,004,000

$2,825,000

'

$10,600,000

$11,100,000

$11,100,000

$10,000,000

$2,100,000

$12,200,000

$3,900,000

$59,700,000

$2,900,000

$2,900,000

$8,300,000

$19,600,000

Business_Segment_Information_M

Business Segment Information - Major Customers (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue, Major Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales	$465,108	$493,603	$512,987	$511,690	$1,338,098	$532,798	$478,434	$381,635	$1,983,388	$2,730,965	$1,415,213
Occidental Petroleum Corporation	'	'	'	'	'	'	'	'	'	'	'
Revenue, Major Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	'	829,081	'
Percentage of revenue	'	'	'	'	'	'	'	'	'	30.40%	'
Plains Marketing, L.P.	'	'	'	'	'	'	'	'	'	'	'
Revenue, Major Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	491,258	426,339	276,285
Percentage of revenue	'	'	'	'	'	'	'	'	24.80%	15.60%	19.50%
Enterprise Crude Oil, LLC	'	'	'	'	'	'	'	'	'	'	'
Revenue, Major Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	'	394,162	319,277
Percentage of revenue	'	'	'	'	'	'	'	'	'	14.40%	22.60%
Shell Trading (US) Company	'	'	'	'	'	'	'	'	'	'	'
Revenue, Major Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	347,422	'	'
Percentage of revenue	'	'	'	'	'	'	'	'	17.50%	'	'
Atlas Pipeline Mid-Continent West OK LLC	'	'	'	'	'	'	'	'	'	'	'
Revenue, Major Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sales	'	'	'	'	'	'	'	'	$211,838	'	'
Percentage of revenue	'	'	'	'	'	'	'	'	10.70%	'	'

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information - Schedule of Condensed Cash Flow Revisions for Prior Periods (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	$868,630	$783,160	$458,954
Net cash provided by (used in) financing activities	-1,434,089	1,874,870	645,193
Parent	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	-239,026	285,567	702,369
Net cash provided by (used in) financing activities	744,303	435,250	-499,795
Parent | Condensed Cash Flow Revision	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	'	945,448	288,415
Net cash provided by (used in) financing activities	'	-945,448	-288,415
Guarantors	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	852,026	264,717	-221,992
Net cash provided by (used in) financing activities	-2,011,552	774,581	173,163
Guarantors | Condensed Cash Flow Revision	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	'	-809,099	-172,927
Net cash provided by (used in) financing activities	'	809,099	172,927
Non-Guarantors	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	254,723	162,281	-9,005
Net cash provided by (used in) financing activities	-275,764	462,684	926,853
Non-Guarantors | Condensed Cash Flow Revision	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	'	-136,349	-115,488
Net cash provided by (used in) financing activities	'	$136,349	$115,488

Condensed_Consolidating_Financ3

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors' (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Current assets	'	'	'	'
Cash and cash equivalents	$814,663	$309,766	$207,681	$5,863
Accounts receivable, net	349,218	445,506	'	'
Intercompany accounts receivable	0	0	'	'
Derivative contracts	12,779	71,022	'	'
Prepaid expenses	39,253	31,319	'	'
Restricted deposit	0	255,000	'	'
Other current assets	25,910	30,272	'	'
Total current assets	1,241,823	1,142,885	'	'
Property, plant and equipment, net	6,307,675	8,479,977	'	'
Investment in subsidiaries	0	0	'	'
Derivative contracts	14,126	23,617	'	'
Other assets	121,171	144,252	'	'
Total assets	7,684,795	9,790,731	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	812,488	766,544	'	'
Intercompany accounts payable	0	0	'	'
Derivative contracts	34,267	14,860	'	'
Asset retirement obligations	87,063	118,504	32,906	'
Deposit on pending sale	0	255,000	'	'
Other current liabilities	'	15,546	'	'
Total current liabilities	933,818	1,170,454	'	'
Long-term debt	3,194,907	4,301,083	'	'
Derivative contracts	20,564	59,787	'	'
Asset retirement obligations	337,054	379,906	95,210	'
Other long-term obligations	22,825	17,046	'	'
Total liabilities	4,509,168	5,928,276	'	'
Equity	'	'	'	'
SandRidge Energy, Inc. stockholders' equity	1,825,810	2,368,853	'	'
Noncontrolling interest	1,349,817	1,493,602	'	'
Total equity	3,175,627	3,862,455	2,548,950	1,547,483
Total liabilities and equity	7,684,795	9,790,731	'	'
Parent	'	'	'	'
Current assets	'	'	'	'
Cash and cash equivalents	805,505	300,228	204,015	1,441
Accounts receivable, net	0	0	'	'
Intercompany accounts receivable	153,325	2,162,471	'	'
Derivative contracts	0	0	'	'
Prepaid expenses	0	0	'	'
Restricted deposit	'	0	'	'
Other current assets	1,376	1,375	'	'
Total current assets	960,206	2,464,074	'	'
Property, plant and equipment, net	0	0	'	'
Investment in subsidiaries	5,237,057	5,425,907	'	'
Derivative contracts	0	0	'	'
Other assets	61,923	83,642	'	'
Total assets	6,259,186	7,973,623	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	207,572	261,215	'	'
Intercompany accounts payable	967,365	975,578	'	'
Derivative contracts	0	2,394	'	'
Asset retirement obligations	0	0	'	'
Deposit on pending sale	'	0	'	'
Other current liabilities	'	0	'	'
Total current liabilities	1,174,937	1,239,187	'	'
Long-term debt	3,200,809	4,306,985	'	'
Derivative contracts	0	0	'	'
Asset retirement obligations	0	0	'	'
Other long-term obligations	1,382	1,329	'	'
Total liabilities	4,377,128	5,547,501	'	'
Equity	'	'	'	'
SandRidge Energy, Inc. stockholders' equity	1,882,058	2,426,122	'	'
Noncontrolling interest	0	0	'	'
Total equity	1,882,058	2,426,122	'	'
Total liabilities and equity	6,259,186	7,973,623	'	'
Guarantors	'	'	'	'
Current assets	'	'	'	'
Cash and cash equivalents	1,013	922	437	564
Accounts receivable, net	326,345	411,197	'	'
Intercompany accounts receivable	982,524	397,238	'	'
Derivative contracts	7,796	60,736	'	'
Prepaid expenses	39,165	31,135	'	'
Restricted deposit	'	255,000	'	'
Other current assets	24,410	24,188	'	'
Total current assets	1,381,253	1,180,416	'	'
Property, plant and equipment, net	5,181,128	7,236,685	'	'
Investment in subsidiaries	-102,848	-86,235	'	'
Derivative contracts	12,650	15,957	'	'
Other assets	65,123	66,512	'	'
Total assets	6,537,306	8,413,335	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	601,074	492,866	'	'
Intercompany accounts payable	180,910	1,594,180	'	'
Derivative contracts	44,032	30,664	'	'
Asset retirement obligations	87,063	118,504	'	'
Deposit on pending sale	'	255,000	'	'
Other current liabilities	'	15,546	'	'
Total current liabilities	913,079	2,506,760	'	'
Long-term debt	0	0	'	'
Derivative contracts	28,673	85,241	'	'
Asset retirement obligations	337,054	379,710	'	'
Other long-term obligations	21,443	15,717	'	'
Total liabilities	1,300,249	2,987,428	'	'
Equity	'	'	'	'
SandRidge Energy, Inc. stockholders' equity	5,237,057	5,425,907	'	'
Noncontrolling interest	0	0	'	'
Total equity	5,237,057	5,425,907	'	'
Total liabilities and equity	6,537,306	8,413,335	'	'
Non-Guarantors	'	'	'	'
Current assets	'	'	'	'
Cash and cash equivalents	8,145	8,616	3,229	3,858
Accounts receivable, net	22,873	34,309	'	'
Intercompany accounts receivable	70,107	683,406	'	'
Derivative contracts	14,748	28,484	'	'
Prepaid expenses	88	184	'	'
Restricted deposit	'	0	'	'
Other current assets	124	4,709	'	'
Total current assets	116,085	759,708	'	'
Property, plant and equipment, net	1,182,132	1,298,877	'	'
Investment in subsidiaries	0	0	'	'
Derivative contracts	9,585	33,114	'	'
Other assets	27	0	'	'
Total assets	1,307,829	2,091,699	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	3,842	12,463	'	'
Intercompany accounts payable	57,018	671,673	'	'
Derivative contracts	0	0	'	'
Asset retirement obligations	0	0	'	'
Deposit on pending sale	'	0	'	'
Other current liabilities	'	0	'	'
Total current liabilities	60,860	684,136	'	'
Long-term debt	0	0	'	'
Derivative contracts	0	0	'	'
Asset retirement obligations	0	196	'	'
Other long-term obligations	0	0	'	'
Total liabilities	60,860	684,332	'	'
Equity	'	'	'	'
SandRidge Energy, Inc. stockholders' equity	1,246,969	1,407,367	'	'
Noncontrolling interest	0	0	'	'
Total equity	1,246,969	1,407,367	'	'
Total liabilities and equity	1,307,829	2,091,699	'	'
Eliminations	'	'	'	'
Current assets	'	'	'	'
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	0	'	'
Intercompany accounts receivable	-1,205,956	-3,243,115	'	'
Derivative contracts	-9,765	-18,198	'	'
Prepaid expenses	0	0	'	'
Restricted deposit	'	0	'	'
Other current assets	0	0	'	'
Total current assets	-1,215,721	-3,261,313	'	'
Property, plant and equipment, net	-55,585	-55,585	'	'
Investment in subsidiaries	-5,134,209	-5,339,672	'	'
Derivative contracts	-8,109	-25,454	'	'
Other assets	-5,902	-5,902	'	'
Total assets	-6,419,526	-8,687,926	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	0	0	'	'
Intercompany accounts payable	-1,205,293	-3,241,431	'	'
Derivative contracts	-9,765	-18,198	'	'
Asset retirement obligations	0	0	'	'
Deposit on pending sale	'	0	'	'
Other current liabilities	'	0	'	'
Total current liabilities	-1,215,058	-3,259,629	'	'
Long-term debt	-5,902	-5,902	'	'
Derivative contracts	-8,109	-25,454	'	'
Asset retirement obligations	0	0	'	'
Other long-term obligations	0	0	'	'
Total liabilities	-1,229,069	-3,290,985	'	'
Equity	'	'	'	'
SandRidge Energy, Inc. stockholders' equity	-6,540,274	-6,890,543	'	'
Noncontrolling interest	1,349,817	1,493,602	'	'
Total equity	-5,190,457	-5,396,941	'	'
Total liabilities and equity	($6,419,526)	($8,687,926)	'	'

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors' (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Condensed Financial Statements, Captions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

$465,108

$493,603

$512,987

$511,690

$1,338,098

$532,798

$478,434

$381,635

$1,983,388

$2,730,965

$1,415,213

Expenses

'

'

'

'

'

'

'

'

'

'

'

Direct operating expenses

'

'

'

'

'

'

'

'

682,830

1,431,672

498,563

General and administrative

'

'

'

'

'

'

'

'

330,425

241,682

148,643

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

666,645

657,830

380,244

Impairment

'

'

'

'

'

'

'

'

26,280

316,004

2,825

Depreciation, depletion, amortization, accretion and impairment

'

'

'

'

'

'

'

'

'

'

383,069

Loss (gain) on derivative contracts

'

'

'

'

'

'

'

'

47,123

-241,419

-44,075

Loss on sale of assets

'

'

'

'

'

'

'

'

399,086

3,089

-2,044

Total expenses

'

'

'

'

'

'

'

'

2,152,389

2,405,769

986,200

Income (loss) from operations

97,979

[1],[2],[3]

6,088

[1],[2],[3]

86,458

[1],[2],[3]

-359,526

[1],[2],[3]

-209,690

[4],[5]

-75,871

[4],[5]

762,413

[4],[5]

-151,656

[4],[5]

-169,001

325,196

429,013

Equity earnings from subsidiaries

'

'

'

'

'

'

'

'

0

0

0

Interest income (expense), net

'

'

'

'

'

'

'

'

-270,234

-303,349

-237,332

Gain on sale of subsidiary

'

'

'

'

'

'

'

'

'

0

'

Bargain purchase gain

'

'

'

'

'

'

'

'

0

122,696

0

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

-82,005

-3,075

-38,232

Other income (expense), net

'

'

'

'

'

'

'

'

12,445

4,741

3,122

(Loss) income before income taxes

'

'

'

'

'

'

'

'

-508,795

146,209

156,571

Income tax expense (benefit)

'

'

'

'

'

'

'

'

5,684

-100,362

-5,817

Net (loss) income

49,097

[1],[2],[3]

-57,002

[1],[2],[3]

24,685

[1],[2],[3]

-531,259

[1],[2],[3]

-294,529

[4],[5],[6]

-159,752

[4],[5],[6]

917,076

[4],[5],[6]

-216,224

[4],[5],[6]

-514,479

246,571

162,388

Less: net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

39,410

105,000

54,323

Net income attributable to SandRidge Energy, Inc.

'

'

'

'

'

'

'

'

-553,889

141,571

108,065

Parent

'

'

'

'

'

'

'

'

'

'

'

Condensed Financial Statements, Captions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

0

0

0

Expenses

'

'

'

'

'

'

'

'

'

'

'

Direct operating expenses

'

'

'

'

'

'

'

'

0

0

0

General and administrative

'

'

'

'

'

'

'

'

329

515

416

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

0

0

'

Impairment

'

'

'

'

'

'

'

'

0

0

'

Depreciation, depletion, amortization, accretion and impairment

'

'

'

'

'

'

'

'

'

'

0

Loss (gain) on derivative contracts

'

'

'

'

'

'

'

'

0

0

0

Loss on sale of assets

'

'

'

'

'

'

'

'

0

'

'

Total expenses

'

'

'

'

'

'

'

'

329

515

416

Income (loss) from operations

'

'

'

'

'

'

'

'

-329

-515

-416

Equity earnings from subsidiaries

'

'

'

'

'

'

'

'

-188,850

426,264

379,177

Interest income (expense), net

'

'

'

'

'

'

'

'

-271,193

-303,510

-236,109

Gain on sale of subsidiary

'

'

'

'

'

'

'

'

'

55,585

'

Bargain purchase gain

'

'

'

'

'

'

'

'

'

0

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

-82,005

-3,075

-38,232

Other income (expense), net

'

'

'

'

'

'

'

'

0

0

0

(Loss) income before income taxes

'

'

'

'

'

'

'

'

-542,377

174,749

104,420

Income tax expense (benefit)

'

'

'

'

'

'

'

'

5,244

-100,808

-5,984

Net (loss) income

'

'

'

'

'

'

'

'

-547,621

275,557

110,404

Less: net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

0

Net income attributable to SandRidge Energy, Inc.

'

'

'

'

'

'

'

'

-547,621

275,557

110,404

Guarantors

'

'

'

'

'

'

'

'

'

'

'

Condensed Financial Statements, Captions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

1,675,481

2,435,064

1,285,854

Expenses

'

'

'

'

'

'

'

'

'

'

'

Direct operating expenses

'

'

'

'

'

'

'

'

655,101

1,393,006

475,578

General and administrative

'

'

'

'

'

'

'

'

323,808

234,954

144,574

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

581,435

570,786

'

Impairment

'

'

'

'

'

'

'

'

15,038

236,671

'

Depreciation, depletion, amortization, accretion and impairment

'

'

'

'

'

'

'

'

'

'

351,708

Loss (gain) on derivative contracts

'

'

'

'

'

'

'

'

24,702

-198,732

-33,749

Loss on sale of assets

'

'

'

'

'

'

'

'

291,743

'

'

Total expenses

'

'

'

'

'

'

'

'

1,891,827

2,236,685

938,111

Income (loss) from operations

'

'

'

'

'

'

'

'

-216,346

198,379

347,743

Equity earnings from subsidiaries

'

'

'

'

'

'

'

'

3,075

20,667

28,751

Interest income (expense), net

'

'

'

'

'

'

'

'

959

725

-197

Gain on sale of subsidiary

'

'

'

'

'

'

'

'

'

0

'

Bargain purchase gain

'

'

'

'

'

'

'

'

'

122,696

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

0

0

Other income (expense), net

'

'

'

'

'

'

'

'

23,462

83,797

2,880

(Loss) income before income taxes

'

'

'

'

'

'

'

'

-188,850

426,264

379,177

Income tax expense (benefit)

'

'

'

'

'

'

'

'

0

0

0

Net (loss) income

'

'

'

'

'

'

'

'

-188,850

426,264

379,177

Less: net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

0

Net income attributable to SandRidge Energy, Inc.

'

'

'

'

'

'

'

'

-188,850

426,264

379,177

Non-Guarantors

'

'

'

'

'

'

'

'

'

'

'

Condensed Financial Statements, Captions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

308,300

404,418

268,427

Expenses

'

'

'

'

'

'

'

'

'

'

'

Direct operating expenses

'

'

'

'

'

'

'

'

29,143

146,416

158,697

General and administrative

'

'

'

'

'

'

'

'

6,288

7,635

4,670

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

85,210

87,044

'

Impairment

'

'

'

'

'

'

'

'

11,242

79,333

'

Depreciation, depletion, amortization, accretion and impairment

'

'

'

'

'

'

'

'

'

'

31,361

Loss (gain) on derivative contracts

'

'

'

'

'

'

'

'

22,421

-42,687

-10,326

Loss on sale of assets

'

'

'

'

'

'

'

'

107,343

'

'

Total expenses

'

'

'

'

'

'

'

'

261,647

277,741

184,402

Income (loss) from operations

'

'

'

'

'

'

'

'

46,653

126,677

84,025

Equity earnings from subsidiaries

'

'

'

'

'

'

'

'

0

0

0

Interest income (expense), net

'

'

'

'

'

'

'

'

0

-564

-1,026

Gain on sale of subsidiary

'

'

'

'

'

'

'

'

'

0

'

Bargain purchase gain

'

'

'

'

'

'

'

'

'

0

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

0

0

Other income (expense), net

'

'

'

'

'

'

'

'

-3,728

0

242

(Loss) income before income taxes

'

'

'

'

'

'

'

'

42,925

126,113

83,241

Income tax expense (benefit)

'

'

'

'

'

'

'

'

440

446

167

Net (loss) income

'

'

'

'

'

'

'

'

42,485

125,667

83,074

Less: net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

0

Net income attributable to SandRidge Energy, Inc.

'

'

'

'

'

'

'

'

42,485

125,667

83,074

Eliminations

'

'

'

'

'

'

'

'

'

'

'

Condensed Financial Statements, Captions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Total revenues

'

'

'

'

'

'

'

'

-393

-108,517

-139,068

Expenses

'

'

'

'

'

'

'

'

'

'

'

Direct operating expenses

'

'

'

'

'

'

'

'

-1,414

-107,750

-135,712

General and administrative

'

'

'

'

'

'

'

'

0

-1,422

-1,017

Depreciation, depletion, amortization and accretion

'

'

'

'

'

'

'

'

0

0

'

Impairment

'

'

'

'

'

'

'

'

0

0

'

Depreciation, depletion, amortization, accretion and impairment

'

'

'

'

'

'

'

'

'

'

0

Loss (gain) on derivative contracts

'

'

'

'

'

'

'

'

0

0

0

Loss on sale of assets

'

'

'

'

'

'

'

'

0

'

'

Total expenses

'

'

'

'

'

'

'

'

-1,414

-109,172

-136,729

Income (loss) from operations

'

'

'

'

'

'

'

'

1,021

655

-2,339

Equity earnings from subsidiaries

'

'

'

'

'

'

'

'

185,775

-446,931

-407,928

Interest income (expense), net

'

'

'

'

'

'

'

'

0

0

0

Gain on sale of subsidiary

'

'

'

'

'

'

'

'

'

-55,585

'

Bargain purchase gain

'

'

'

'

'

'

'

'

'

0

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

0

0

Other income (expense), net

'

'

'

'

'

'

'

'

-7,289

-79,056

0

(Loss) income before income taxes

'

'

'

'

'

'

'

'

179,507

-580,917

-410,267

Income tax expense (benefit)

'

'

'

'

'

'

'

'

0

0

0

Net (loss) income

'

'

'

'

'

'

'

'

179,507

-580,917

-410,267

Less: net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

39,410

105,000

54,323

Net income attributable to SandRidge Energy, Inc.

'

'

'

'

'

'

'

'

$140,097

($685,917)

($464,590)

[1]

Includes loss (gain) on commodity derivative contracts of $40.9 million, $(103.7) million, $132.8 million and $(22.9) million for the first, second, third and fourth quarters, respectively.

[2]

Includes a $10.6 million impairment of various drilling assets and a $2.9 million impairment of a corporate asset in the second quarter of 2013 and a $2.1 million and $10.0 million impairment of certain midstream inventory, natural gas compressors, gas treating plants and a CO2 compression station in the second and fourth quarters of 2013, respectively.

[3]

Includes loss on sale of Permian Properties of $398.9 million in the first quarter of 2013.

[4]

Includes loss (gain) on commodity derivative contracts of $254.6 million, $(669.9) million, $193.5 million and $(19.6) million for the first, second, third and fourth quarters, respectively.

[5]

Includes a $235.4 million goodwill impairment and a $79.3 million impairment of gas treating plants and CO2 compression facilities in the fourth quarter of 2012.

[6]

Includes adjustments of $(4.8) million retrospectively applied to the second quarter of 2012 as a result of measurement period adjustments made to the preliminary purchase price allocation for the Dynamic Acquisition in the fourth quarter of 2012.

Condensed_Consolidating_Financ5

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors' (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	$868,630	$783,160	$458,954
Cash flows from investing activities	'	'	'
Capital expenditures for property, plant and equipment	-1,496,731	-2,146,372	-1,727,106
Acquisitions, net of cash received	-17,028	-840,740	-34,628
Proceeds from sale of assets	2,584,115	431,167	859,405
Other	-17,028	0	-34,628
Net cash provided by (used in) investing activities	1,070,356	-2,555,945	-902,329
Cash flows from financing activities	'	'	'
Proceeds from borrowings	0	1,850,344	2,033,000
Repayments of borrowings	-1,115,500	-366,029	-2,130,293
Premium on debt redemption	-61,997	-844	-30,338
Proceeds from issuance of royalty trust units	0	587,086	917,528
Proceeds from the sale of royalty trust units	28,985	139,360	0
Distributions to unitholders	-206,470	-181,727	-60,200
Dividends paid—preferred	-55,525	-55,525	-56,742
Intercompany (advances) borrowings, net	0	0	0
Other	5,403	-98,639	-58,100
Net cash (used in) provided by financing activities	-1,434,089	1,874,870	645,193
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	504,897	102,085	201,818
CASH AND CASH EQUIVALENTS, beginning of year	309,766	207,681	5,863
CASH AND CASH EQUIVALENTS, end of year	814,663	309,766	207,681
Parent	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	-239,026	285,567	702,369
Cash flows from investing activities	'	'	'
Capital expenditures for property, plant and equipment	0	0	0
Acquisitions, net of cash received	'	-693,091	'
Proceeds from sale of assets	0	129,830	0
Other	0	-61,343	0
Net cash provided by (used in) investing activities	0	-624,604	0
Cash flows from financing activities	'	'	'
Proceeds from borrowings	'	1,850,344	2,033,000
Repayments of borrowings	-1,115,500	-350,000	-2,123,000
Premium on debt redemption	-61,997	'	'
Proceeds from issuance of royalty trust units	'	0	0
Proceeds from the sale of royalty trust units	'	0	'
Distributions to unitholders	0	0	0
Dividends paid—preferred	-55,525	-55,525	-56,742
Intercompany (advances) borrowings, net	2,009,146	-945,448	-288,415
Other	-31,821	-64,121	-64,638
Net cash (used in) provided by financing activities	744,303	435,250	-499,795
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	505,277	96,213	202,574
CASH AND CASH EQUIVALENTS, beginning of year	300,228	204,015	1,441
CASH AND CASH EQUIVALENTS, end of year	805,505	300,228	204,015
Guarantors	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	852,026	264,717	-221,992
Cash flows from investing activities	'	'	'
Capital expenditures for property, plant and equipment	-1,496,731	-2,112,547	-1,726,131
Acquisitions, net of cash received	'	-147,649	'
Proceeds from sale of assets	2,566,742	942,675	1,776,907
Other	89,606	278,708	-2,074
Net cash provided by (used in) investing activities	1,159,617	-1,038,813	48,702
Cash flows from financing activities	'	'	'
Proceeds from borrowings	'	0	0
Repayments of borrowings	0	0	-6,302
Premium on debt redemption	0	'	'
Proceeds from issuance of royalty trust units	'	0	0
Proceeds from the sale of royalty trust units	'	0	'
Distributions to unitholders	0	0	0
Dividends paid—preferred	0	0	0
Intercompany (advances) borrowings, net	-2,018,212	809,099	172,927
Other	6,660	-34,518	6,538
Net cash (used in) provided by financing activities	-2,011,552	774,581	173,163
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	91	485	-127
CASH AND CASH EQUIVALENTS, beginning of year	922	437	564
CASH AND CASH EQUIVALENTS, end of year	1,013	922	437
Non-Guarantors	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	254,723	162,281	-9,005
Cash flows from investing activities	'	'	'
Capital expenditures for property, plant and equipment	0	-33,825	-975
Acquisitions, net of cash received	'	-587,086	'
Proceeds from sale of assets	17,373	1,333	26
Other	3,197	0	-917,528
Net cash provided by (used in) investing activities	20,570	-619,578	-918,477
Cash flows from financing activities	'	'	'
Proceeds from borrowings	'	0	0
Repayments of borrowings	0	-16,029	-991
Premium on debt redemption	0	'	'
Proceeds from issuance of royalty trust units	'	587,086	917,528
Proceeds from the sale of royalty trust units	'	0	'
Distributions to unitholders	-299,675	-274,980	-96,664
Dividends paid—preferred	0	0	0
Intercompany (advances) borrowings, net	9,066	136,349	115,488
Other	14,845	30,258	-8,508
Net cash (used in) provided by financing activities	-275,764	462,684	926,853
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	-471	5,387	-629
CASH AND CASH EQUIVALENTS, beginning of year	8,616	3,229	3,858
CASH AND CASH EQUIVALENTS, end of year	8,145	8,616	3,229
Eliminations	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net cash (used in) provided by operating activities	907	70,595	-12,418
Cash flows from investing activities	'	'	'
Capital expenditures for property, plant and equipment	0	0	0
Acquisitions, net of cash received	'	587,086	'
Proceeds from sale of assets	0	-642,671	-917,528
Other	-109,831	-217,365	884,974
Net cash provided by (used in) investing activities	-109,831	-272,950	-32,554
Cash flows from financing activities	'	'	'
Proceeds from borrowings	'	0	0
Repayments of borrowings	0	0	0
Premium on debt redemption	0	'	'
Proceeds from issuance of royalty trust units	'	0	0
Proceeds from the sale of royalty trust units	'	139,360	'
Distributions to unitholders	93,205	93,253	36,464
Dividends paid—preferred	0	0	0
Intercompany (advances) borrowings, net	0	0	0
Other	15,719	-30,258	8,508
Net cash (used in) provided by financing activities	108,924	202,355	44,972
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	0	0	0
CASH AND CASH EQUIVALENTS, beginning of year	0	0	0
CASH AND CASH EQUIVALENTS, end of year	$0	$0	$0

Supplemental_Information_on_Oi2

Supplemental Information on Oil and Natural Gas Producing Activities - Capitalized Costs Related to Oil, Natural Gas and NGL Producing Activities (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified
Oil and natural gas properties	'		'		'
Proved	$10,972,816	[1]	$12,262,921	[1]	$8,969,296
Unproved	531,606		865,863		689,393
Total oil and natural gas properties	11,504,422		13,128,784		9,658,689
Less: accumulated depreciation, depletion and impairment	-5,762,969		-5,231,182		-4,791,534
Net oil and natural gas properties capitalized costs	$5,741,453		$7,897,602		$4,867,155
[1]	Includes cumulative capitalized interest of approximately $23.4 million and $11.7 million at December 31, 2013 and 2012, respectively.

Supplemental_Information_on_Oi3

Supplemental Information on Oil and Natural Gas Producing Activities - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Acquisitions of properties	'		'		'
Proved	$21,130		$1,761,556		$58,190
Unproved	100,242		377,185		320,361
Exploration(1)	82,775	[1]	120,438	[1]	98,849	[1]
Development(2)	1,131,269	[2]	1,704,991	[2]	1,296,903	[2]
Total costs incurred	$1,335,416		$3,964,170		$1,774,303
[1]	Includes seismic costs of $6.7 million, $15.3 million and $4.9 million for 2013, 2012 and 2011, respectively.
[2]	Includes loss on the construction of the Century Plant of $50.0 million and $25.0 million for 2012 and 2011, respectively. See Note 11.

Supplemental_Information_on_Oi4

Supplemental Information on Oil and Natural Gas Producing Activities - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Parenthetical) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration(1)	$82,775	[1]	$120,438	[1]	$98,849	[1]
Development(2)	1,131,269	[2]	1,704,991	[2]	1,296,903	[2]
Seismic Costs	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration(1)	6,700		15,300		4,900
Contract Loss | Century Plant	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Development(2)	'		$50,000		$25,000
[1]	Includes seismic costs of $6.7 million, $15.3 million and $4.9 million for 2013, 2012 and 2011, respectively.
[2]	Includes loss on the construction of the Century Plant of $50.0 million and $25.0 million for 2012 and 2011, respectively. See Note 11.

Supplemental_Information_on_Oi5

Supplemental Information on Oil and Natural Gas Producing Activities - Results of Operations from Oil, Natural Gas and NGL Producing Activities (Unaudited) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract]	'		'		'
Revenues	$1,820,278		$1,759,282		$1,226,794
Expenses	'		'		'
Production costs	548,719		524,364		368,946
Depreciation and depletion	567,732		568,029		317,246
Accretion of asset retirement obligations	36,777		28,996		9,368
Total expenses	1,153,228		1,121,389		695,560
Income before income taxes	667,050		637,893		531,234
Benefit of income taxes(1)	-7,471	[1]	-437,595	[1]	-20,134	[1]
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$674,521		$1,075,488		$551,368
[1]	Reflects the Company’s effective tax rate, including the partial valuation allowance releases.

Supplemental_Information_on_Oi6

Supplemental Information on Oil and Natural Gas Producing Activities - Summary of Changes in Estimated Oil and Natural Gas Reserves (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
	MBbls		MBbls		MBbls		MBbls
Oil Reserves	'		'		'		'
Proved Developed and Undeveloped Reserves	'		'		'		'
Proved developed and undeveloped reserves, beginning balance (in MBbls for Oil and NGLs/MMcf for Natural Gas)	262,045	[1]	214,450	[1]	205,023		'
Revisions of previous estimates (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-13,969		-37,394		-6,159		'
Acquisitions of new reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	43		31,470		1,309		'
Extensions and discoveries (in MBbls for Oil and NGLs/MMcf for Natural Gas)	40,570		89,656		52,406		'
Sales of reserves in place (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-131,769		-20,269		-28,137		'
Production (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-14,279		-15,868		-9,992		'
Proved developed and undeveloped reserves, ending balance (in MBbls for Oil and NGLs/MMcf for Natural Gas)	142,641	[1]	262,045	[1]	214,450	[1]	'
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	83,893		136,605		101,578		73,111
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	58,748		125,440		112,872		131,912
Natural Gas Liquids	'		'		'		'
Proved Developed and Undeveloped Reserves	'		'		'		'
Proved developed and undeveloped reserves, beginning balance (in MBbls for Oil and NGLs/MMcf for Natural Gas)	67,994	[1]	30,335	[1]	47,091		'
Revisions of previous estimates (in MBbls for Oil and NGLs/MMcf for Natural Gas)	3,717		15,098		-3,119		'
Acquisitions of new reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	13		683		224		'
Extensions and discoveries (in MBbls for Oil and NGLs/MMcf for Natural Gas)	18,686		27,259		3,171		'
Sales of reserves in place (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-29,067		-3,287		-15,194		'
Production (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-2,291		-2,094		-1,838		'
Proved developed and undeveloped reserves, ending balance (in MBbls for Oil and NGLs/MMcf for Natural Gas)	59,052	[1]	67,994	[1]	30,335	[1]	'
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	35,807		33,785		17,150		18,854
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	23,245		34,209		13,185		28,237
Natural Gas Reserves	'		'		'		'
Proved Developed and Undeveloped Reserves	'		'		'		'
Proved developed and undeveloped reserves, beginning balance (in MBbls for Oil and NGLs/MMcf for Natural Gas)	1,415,042	[1],[2]	1,355,056	[1],[2]	1,762,665	[2]	'
Revisions of previous estimates (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-53,432	[2]	-538,214	[2]	-164,845	[2]	'
Acquisitions of new reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	363	[2]	202,995	[2]	2,906	[2]	'
Extensions and discoveries (in MBbls for Oil and NGLs/MMcf for Natural Gas)	359,918	[2]	489,302	[2]	299,848	[2]	'
Sales of reserves in place (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-228,229	[2]	-548	[2]	-476,212	[2]	'
Production (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-103,233	[2]	-93,549	[2]	-69,306	[2]	'
Proved developed and undeveloped reserves, ending balance (in MBbls for Oil and NGLs/MMcf for Natural Gas)	1,390,429	[1],[2]	1,415,042	[1],[2]	1,355,056	[1],[2]	'
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	951,609	[2]	896,701	[2]	670,382	[2]	784,292	[2]
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	438,820	[2]	518,341	[2]	684,674	[2]	978,373	[2]
[1]	Includes proved reserves attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 as shown in the table below: December 31, 2013 2012 2011Oil (MBbl)13,569 17,340 17,018NGL (MBbl)4,737 5,132 1,782Natural gas (MMcf)69,693 94,543 45,500
[2]	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Supplemental_Information_on_Oi7

Supplemental Information on Oil and Natural Gas Producing Activities - Summary of Changes in Estimated Oil and Natural Gas Reserves (Unaudited) (Parenthetical) (Details)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
	MBbls		MBbls		MBbls		MBbls
Oil Reserves	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	142,641	[1]	262,045	[1]	214,450	[1]	205,023
Natural Gas Liquids	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	59,052	[1]	67,994	[1]	30,335	[1]	47,091
Natural Gas Reserves	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	1,390,429	[1],[2]	1,415,042	[1],[2]	1,355,056	[1],[2]	1,762,665	[2]
Noncontrolling Interest | Oil Reserves	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	13,569		17,340		17,018		'
Noncontrolling Interest | Natural Gas Liquids	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	4,737		5,132		1,782		'
Noncontrolling Interest | Natural Gas Reserves	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	69,693		94,543		45,500		'
[1]	Includes proved reserves attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 as shown in the table below: December 31, 2013 2012 2011Oil (MBbl)13,569 17,340 17,018NGL (MBbl)4,737 5,132 1,782Natural gas (MMcf)69,693 94,543 45,500
[2]	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Supplemental_Information_on_Oi8

Supplemental Information on Oil and Natural Gas Producing Activities - Summary of Changes in Estimated Oil and Natural Gas Reserves - Noncontrolling Interests (Unaudited) (Parenthetical) (Details)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
	MBbls		MBbls		MBbls		MBbls
Oil Reserves	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved Developed and Undeveloped Reserves, Net	142,641	[1]	262,045	[1]	214,450	[1]	205,023
Natural Gas Liquids	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved Developed and Undeveloped Reserves, Net	59,052	[1]	67,994	[1]	30,335	[1]	47,091
Natural Gas Reserves	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved Developed and Undeveloped Reserves, Net	1,390,429	[1],[2]	1,415,042	[1],[2]	1,355,056	[1],[2]	1,762,665	[2]
Noncontrolling Interest | Oil Reserves	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved Developed and Undeveloped Reserves, Net	13,569		17,340		17,018		'
Noncontrolling Interest | Natural Gas Liquids	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved Developed and Undeveloped Reserves, Net	4,737		5,132		1,782		'
Noncontrolling Interest | Natural Gas Reserves	'		'		'		'
Reserve Quantities [Line Items]	'		'		'		'
Proved Developed and Undeveloped Reserves, Net	69,693		94,543		45,500		'
[1]	Includes proved reserves attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 as shown in the table below: December 31, 2013 2012 2011Oil (MBbl)13,569 17,340 17,018NGL (MBbl)4,737 5,132 1,782Natural gas (MMcf)69,693 94,543 45,500
[2]	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Supplemental_Information_on_Oi9

Supplemental Information on Oil and Natural Gas Producing Activities - Calculation of Weighted Average Per Unit Prices (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil Reserves	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Weighted Average Sales Price (per barrel for Oil and NGLs/per Mcf for Natural Gas)	95.67	91.65	91.35
Natural Gas Liquids	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Weighted Average Sales Price (per barrel for Oil and NGLs/per Mcf for Natural Gas)	31.4	32.64	46.33
Natural Gas	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Weighted Average Sales Price (per barrel for Oil and NGLs/per Mcf for Natural Gas)	3.65	2.29	4.06

Recovered_Sheet1

Supplemental Information on Oil and Natural Gas Producing Activities - Standardized Measure of Discounted Future Cash Flows (Unaudited) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]	'		'		'
Future cash inflows from production	$19,937,484		$29,482,544		$26,494,942
Future production costs	-6,843,713		-8,899,465		-7,392,104
Future development costs(1)	-2,546,680	[1]	-4,021,051	[1]	-2,977,993	[1]
Future income tax expenses	-2,283,541		-3,721,509		-4,043,953
Undiscounted future net cash flows	8,263,550		12,840,519		12,080,892
10% annual discount	-4,245,939		-7,000,151		-6,864,555
Standardized measure of discounted future net cash flows(2)	$4,017,611	[2]	$5,840,368	[2]	$5,216,337	[2]
[1]	Includes abandonment costs.
[2]	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 respectively.

Recovered_Sheet2

Supplemental Information on Oil and Natural Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows (Unaudited) (Parenthetical) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Standardized measure of discounted future net cash flows	$4,017,611	[1]	$5,840,368	[1]	$5,216,337	[1]
Noncontrolling Interest	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Standardized measure of discounted future net cash flows	$781,600		$952,700		$932,800
[1]	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 respectively.

Recovered_Sheet3

Supplemental Information on Oil and Natural Gas Producing Activities - Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]	'		'		'
Present value, beginning balance	$5,840,368	[1]	$5,216,337	[1]	$3,683,515
Changes during the year	'		'		'
Revenues less production and other costs	-1,271,559		-1,234,918		-857,848
Net changes in prices, production and other costs	271,566		-2,555,391		1,264,736
Development costs incurred	474,275		766,943		575,546
Net changes in future development costs	-207,729		-45,397		87,080
Extensions and discoveries	1,406,102		2,092,423		1,812,167
Revisions of previous quantity estimates	-296,418		-530,755		-345,965
Accretion of discount	711,385		678,200		455,501
Net change in income taxes	477,328		11,433		-833,841
Purchases of reserves in-place	1,628		1,708,301		44,934
Sales of reserves in-place	-3,172,187		-410,415		-558,257
Timing differences and other	-217,148	[2]	143,607	[2]	-111,231	[2]
Net change for the year	-1,822,757		624,031		1,532,822
Present value, ending balance	$4,017,611	[1]	$5,840,368	[1]	$5,216,337	[1]
[1]	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012, and 2011 respectively.
[2]	The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

Recovered_Sheet4

Supplemental Information on Oil and Natural Gas Producing Activities - Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited) (Parenthetical) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
In Thousands, unless otherwise specified
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'		'
Present value	$4,017,611	[1]	$5,840,368	[1]	$5,216,337	[1]	$3,683,515
Noncontrolling Interest	'		'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'		'
Present value	$781,600		$952,700		$932,800		'
[1]	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012, and 2011 respectively.

Recovered_Sheet5

Supplemental Information on Oil and Natural Gas Producing Activities - Additional Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Reserve Quantities [Line Items]	'		'		'
Percentage of proved reserves estimated by the Company	13.90%		'		'
Standardized measure of discounted future net cash flows	$4,017,611	[1]	$5,840,368	[1]	$5,216,337	[1]
Oil Reserves	'		'		'
Reserve Quantities [Line Items]	'		'		'
Change in proved reserves (in MBbls for Oil/MMcf for Natural Gas)	'		67,900		37,600
Revisions of previous estimates (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-13,969		-37,394		-6,159
Extensions and discoveries (in MBbls for Oil and NGLs/MMcf for Natural Gas)	40,570		89,656		52,406
Proved developed and undeveloped reserves, production (in MBbls for Oil/MMcf for Natural Gas)	-14,279		-15,868		-9,992
Natural Gas Reserves	'		'		'
Reserve Quantities [Line Items]	'		'		'
Change in proved reserves (in MBbls for Oil/MMcf for Natural Gas)	'		60,500		68,600
Revisions of previous estimates (in MBbls for Oil and NGLs/MMcf for Natural Gas)	-53,432	[2]	-538,214	[2]	-164,845	[2]
Extensions and discoveries (in MBbls for Oil and NGLs/MMcf for Natural Gas)	359,918	[2]	489,302	[2]	299,848	[2]
Proved developed and undeveloped reserves, production (in MBbls for Oil/MMcf for Natural Gas)	-103,233	[2]	-93,549	[2]	-69,306	[2]
Natural Gas Liquids	'		'		'
Reserve Quantities [Line Items]	'		'		'
Change in proved reserves (in MBbls for Oil/MMcf for Natural Gas)	'		40,900		'
Revisions of previous estimates (in MBbls for Oil and NGLs/MMcf for Natural Gas)	3,717		15,098		-3,119
Extensions and discoveries (in MBbls for Oil and NGLs/MMcf for Natural Gas)	18,686		27,259		3,171
Proved developed and undeveloped reserves, production (in MBbls for Oil/MMcf for Natural Gas)	-2,291		-2,094		-1,838
Permian properties and east Texas properties	'		'		'
Reserve Quantities [Line Items]	'		'		'
Proved reserves, sales of minerals in place (in MMBoe)	'		'		122.7
Tertiary	'		'		'
Reserve Quantities [Line Items]	'		'		'
Proved reserves, sales of minerals in place (in MMBoe)	'		23.6		'
Permian Properties	'		'		'
Reserve Quantities [Line Items]	'		'		'
Proved reserves (in MMBoe)	198.9		'		'
Proved developed reserves as a percentage of total proved reserves	55.00%		'		'
Standardized measure of discounted future net cash flows	$2,500,000		'		'
Mid-Continent and Permian Basin | Oil Reserves	'		'		'
Reserve Quantities [Line Items]	'		'		'
Revisions of previous estimates (in MBbls for Oil and NGLs/MMcf for Natural Gas)	'		-22,300		'
Extensions and discoveries (in MBbls for Oil and NGLs/MMcf for Natural Gas)	'		'		52,406
Mid-Continent and Permian Basin | Natural Gas Reserves	'		'		'
Reserve Quantities [Line Items]	'		'		'
Extensions and discoveries (in MBbls for Oil and NGLs/MMcf for Natural Gas)	'		489,302	[2]	299,848	[2]
Mid-Continent	'		'		'
Reserve Quantities [Line Items]	'		'		'
Extensions and discoveries (in MMBoe)	119.2		'		'
[1]	Includes approximately $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 respectively.
[2]	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Quarterly_Financial_Results_Un2

Quarterly Financial Results (Unaudited) (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'		'		'		'		'		'		'		'		'	'	'
Total revenues	$465,108		$493,603		$512,987		$511,690		$1,338,098		$532,798		$478,434		$381,635		$1,983,388	$2,730,965	$1,415,213
(Loss) income from operations	97,979	[1],[2],[3]	6,088	[1],[2],[3]	86,458	[1],[2],[3]	-359,526	[1],[2],[3]	-209,690	[4],[5]	-75,871	[4],[5]	762,413	[4],[5]	-151,656	[4],[5]	-169,001	325,196	429,013
Net (loss) income	49,097	[1],[2],[3]	-57,002	[1],[2],[3]	24,685	[1],[2],[3]	-531,259	[1],[2],[3]	-294,529	[4],[5],[6]	-159,752	[4],[5],[6]	917,076	[4],[5],[6]	-216,224	[4],[5],[6]	-514,479	246,571	162,388
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$5,198	[1],[2],[3]	($87,074)	[1],[2],[3]	($34,317)	[1],[2],[3]	($493,221)	[1],[2],[3]	($301,785)	[4],[5],[6]	($184,301)	[4],[5],[6]	$804,191	[4],[5],[6]	($232,059)	[4],[5],[6]	($609,414)	$86,046	$52,482
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders	'		'		'		'		'		'		'		'		'	'	'
Basic (in dollars)	$0.01	[7]	($0.18)	[7]	($0.07)	[7]	($1.03)	[7]	($0.63)	[7]	($0.39)	[7]	$1.74	[7]	($0.58)	[7]	($1.27)	$0.19	$0.13
Diluted (in dollars)	$0.01	[7]	($0.18)	[7]	($0.07)	[7]	($1.03)	[7]	($0.63)	[7]	($0.39)	[7]	$1.46	[7]	($0.58)	[7]	($1.27)	$0.19	$0.13
[1]	Includes loss (gain) on commodity derivative contracts of $40.9 million, $(103.7) million, $132.8 million and $(22.9) million for the first, second, third and fourth quarters, respectively.
[2]	Includes a $10.6 million impairment of various drilling assets and a $2.9 million impairment of a corporate asset in the second quarter of 2013 and a $2.1 million and $10.0 million impairment of certain midstream inventory, natural gas compressors, gas treating plants and a CO2 compression station in the second and fourth quarters of 2013, respectively.
[3]	Includes loss on sale of Permian Properties of $398.9 million in the first quarter of 2013.
[4]	Includes loss (gain) on commodity derivative contracts of $254.6 million, $(669.9) million, $193.5 million and $(19.6) million for the first, second, third and fourth quarters, respectively.
[5]	Includes a $235.4 million goodwill impairment and a $79.3 million impairment of gas treating plants and CO2 compression facilities in the fourth quarter of 2012.
[6]	Includes adjustments of $(4.8) million retrospectively applied to the second quarter of 2012 as a result of measurement period adjustments made to the preliminary purchase price allocation for the Dynamic Acquisition in the fourth quarter of 2012.
[7]	(Loss applicable) income available per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of (loss applicable) income available per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

Quarterly_Financial_Results_Un3

Quarterly Financial Results (Unaudited) Quarterly Financial Results (Unaudited) (Parenthetical) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Goodwill impairment loss	'	'	'	'	$235,400,000	'	'	'	'	$235,400,000	'
Asset impairment charges	'	'	'	'	'	'	'	'	26,280,000	316,004,000	2,825,000
Loss (gain) on derivative contracts	'	'	'	'	'	'	'	'	47,123,000	-241,419,000	-44,075,000
Drilling Assets	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Asset impairment charges	'	'	10,600,000	'	'	'	'	'	11,100,000	'	'
Gas Treating Plants and CO2 Compression Facilities	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Asset impairment charges	'	'	'	'	79,300,000	'	'	'	'	'	'
Corporate Asset	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Asset impairment charges	'	'	2,900,000	'	'	'	'	'	'	'	'
Gas Treating Plants and other Midstream Assets	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Asset impairment charges	10,000,000	'	2,100,000	'	'	'	'	'	12,200,000	'	'
Dynamic Acquisition	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Business combination, measurement period adjustment	'	'	'	'	'	'	-4,800,000	'	'	'	'
Exploration and Production	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Goodwill impairment loss	'	'	'	'	'	'	'	'	'	235,400,000	'
Commodity Derivatives	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Loss (gain) on derivative contracts	-22,900,000	132,800,000	-103,700,000	40,900,000	-19,600,000	193,500,000	-669,900,000	254,600,000	47,123,000	-241,419,000	-44,075,000
Permian Properties	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Gain (loss) on divestiture	'	'	'	'	'	'	'	'	($398,900,000)	'	'