Memorial Resource Development 10-Q 11 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Trading Symbol	MRD
Entity Registrant Name	MEMORIAL RESOURCE DEVELOPMENT CORP.
Entity Central Index Key	1599222
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		190,776,618

UNAUDITED_CONDENSED_CONSOLIDAT

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$4,512	$5,958
Accounts receivable:
Oil and natural gas sales	61,649	82,263
Joint interest owners and other	56,750	49,313
Affiliates	1,976
Short-term derivative instruments	357,060	340,056
Prepaid expenses and other current assets	32,133	28,027
Total current assets	514,080	505,617
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	5,014,671	4,844,529
Other	35,882	33,815
Accumulated depreciation, depletion and impairment	-1,683,953	-1,340,688
Property and equipment, net	3,366,600	3,537,656
Long-term derivative instruments	578,153	435,369
Restricted investments	78,787	77,361
Other long-term assets	36,602	37,544
Total assets	4,574,222	4,593,547
Current liabilities:
Accounts payable	42,069	25,772
Accounts payable - affiliates		624
Revenues payable	58,331	57,352
Accrued liabilities	217,669	199,000
Short-term derivative instruments	3,300	3,289
Total current liabilities	321,369	286,037
Noncurrent liabilities:
Asset retirement obligations	124,476	122,531
Long-term derivative instruments	555
Deferred tax liabilities	111,790	95,017
Other long-term liabilities	7,566	8,585
Total liabilities	3,063,801	2,890,583
Commitments and contingencies (Note 15)
Stockholders' equity (deficit):
Preferred stock, $.01 par value: 50,000,000 shares authorized; no shares issued and outstanding
Common stock, $.01 par value: 600,000,000 shares authorized; 190,776,618 shares issued and outstanding at March 31, 2015; 193,435,414 shares issued and outstanding at December 31, 2014	1,908	1,935
Additional paid-in capital	1,234,194	1,367,346
Accumulated earnings (deficit)	-788,736	-786,871
Total stockholders' equity	447,366	582,410
Noncontrolling interests	1,063,055	1,120,554
Total equity	1,510,421	1,702,964
Total liabilities and equity	4,574,222	4,593,547
MRD [Member]
Noncurrent liabilities:
Long-term debt	744,000	783,000
MEMP [Member]
Noncurrent liabilities:
Long-term debt	1,754,045	1,595,413
Deferred tax liabilities		$29,200

UNAUDITED_CONDENSED_CONSOLIDAT1

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Preferred stock, par value	$0.01
Preferred stock, shares authorized	50,000,000
Preferred stock, shares issued	0
Preferred stock, shares outstanding	0
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	190,776,618	193,435,414
Common stock, shares outstanding	190,776,618	193,435,414

UNAUDITED_CONDENSED_STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues:
Oil & natural gas sales	$178,972	$203,710
Other revenues	869	911
Total revenues	179,841	204,621
Costs and expenses:
Lease operating	45,700	33,355
Gathering, processing, and transportation	22,983	14,120
Pipeline operating	446	489
Exploration	816	146
Production and ad valorem taxes	9,430	8,584
Depreciation, depletion, and amortization	91,798	57,679
Impairment of proved oil and natural gas properties	251,347
Incentive unit compensation expense (Note 12)	10,224	1,023
General and administrative	27,487	17,739
Accretion of asset retirement obligations	1,757	1,521
(Gain) loss on commodity derivative instruments	-253,649	59,482
(Gain) loss on sale of properties		-110
Other, net		-12
Total costs and expenses	208,339	194,016
Operating income (loss)	-28,498	10,605
Other income (expense):
Interest expense, net	-38,574	-34,052
Other, net	111	31
Total other income (expense)	-38,463	-34,021
Income (loss) before income taxes	-66,961	-23,416
Income tax benefit (expense)	-45,188	-100
Net income (loss)	-112,149	-23,516
Net income (loss) attributable to noncontrolling interest	-158,041	-31,888
Net income (loss) attributable to Memorial Resource Development Corp.	45,892	8,372
Net (income) loss allocated to members		-6,947
Net (income) loss allocated to previous owners		-1,425
Net (income) allocated to participating restricted stockholders	-277
Net income (loss) available to common stockholders	$45,615	$0
Earnings per common share: (Note 10)
Basic	$0.24
Diluted	$0.24
Weighted average common and common equivalent shares outstanding:
Basic	190,705
Diluted	190,705

UNAUDITED_CONDENSED_STATEMENTS1

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities:
Net income (loss)	($112,149)	($23,516)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	91,798	57,679
Impairment of proved oil and natural gas properties	251,347
(Gain) loss on derivatives	-251,208	59,993
Cash settlements (paid) received on expired derivative instruments	91,985	-13,309
Cash settlements on terminated derivatives	27,063
Premiums paid for derivatives	-27,063
Amortization of deferred financing costs	2,515	1,899
Accretion of senior notes net discount	599	713
Accretion of asset retirement obligations	1,757	1,521
Amortization of equity awards	3,827	1,295
(Gain) loss on sale of properties		-110
Non-cash compensation expense	10,224
Deferred income tax expense (benefit)	43,188
Changes in operating assets and liabilities:
Accounts receivable	13,719	-3,951
Prepaid expenses and other assets	-561	2,832
Payables and accrued liabilities	25,875	18,895
Other	-1,100
Net cash provided by operating activities	171,816	103,941
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	-3,305	-173,000
Additions to oil and gas properties	-160,994	-134,200
Additions to other property and equipment	-1,947	-31
Additions to restricted investments	-1,426	-826
Other		-304
Net cash used in investing activities	-167,672	-308,361
Cash flows from financing activities:
Advances on revolving credit facilities	270,000	343,000
Payments on revolving credit facilities	-148,000	-79,000
Deferred financing costs	-10	-1,162
Distributions to noncontrolling interests	-46,239	-31,085
Other	-7	-7
Net cash provided by financing activities	-5,590	166,218
Net change in cash and cash equivalents	-1,446	-38,202
Cash and cash equivalents, beginning of period	5,958	77,721
Cash and cash equivalents, end of period	4,512	39,519
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	39,203	8,838
Cash paid for taxes	2,055
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities	4,589	10,668
Assumptions of asset retirement obligations related to properties acquired or drilled	39	433
Accounts receivable related to acquisitions and divestitures		3,879
MEMP [Member]
Cash flows from financing activities:
Repurchase of MEMP senior notes	-2,914
Equity repurchases	-28,420
MRD [Member]
Cash flows from financing activities:
Equity repurchases	-50,000
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of assets		1,165
Distribution to NGP affiliates related to sale of assets		($66,693)

UNAUDITED_CONDENSED_STATEMENTS2

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY (USD $)	Total	MEMP [Member]	Member Equity [Member]	Common Stock [Member]	Additional paid in capital [Member]	Accumulated earnings (deficit) [Member]	Previous Owners [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member]
In Thousands							Member Equity [Member]		MEMP [Member]
Members' equity, beginning balance at Dec. 31, 2013			$237,186				$40,331
Noncontrolling interests, beginning balance at Dec. 31, 2013								580,615
Total equity, beginning balance at Dec. 31, 2013	858,132
Net income (loss)	-23,516		6,947				1,425	-31,888
Contribution related to sale of assets to NGP affiliate	1,165		1,165
Net book value of assets sold to NGP affiliate	-621		-621
Distributions	-31,085							-31,085
Net book value of assets acquired from NGP affiliates	3,303		45,059				-41,756
Distribution to NGP affiliates in connection with acquisition of assets	-66,693		-66,693
Amortization of MEMP equity awards	1,295							1,295
Other	333		-154					487
Members' equity, ending balance at Mar. 31, 2014			222,889
Noncontrolling interests, ending balance at Mar. 31, 2014								519,424
Total equity, ending balance at Mar. 31, 2014	742,313
Total stockholders equity, beginning balance at Dec. 31, 2014	582,410			1,935	1,367,346	-786,871
Noncontrolling interests, beginning balance at Dec. 31, 2014	1,120,554							1,120,554
Total equity, beginning balance at Dec. 31, 2014	1,702,964
Net income (loss)	-112,149					45,892		-158,041
Share repurchase	-47,785	-28,420		-28		-47,757			-28,420
Restricted stock awards				1	-1
Amortization of restricted stock awards	1,486				1,486
Contribution related to MRD Holdco incentive unit compensation expense (Note 12)	10,224				10,224
Net equity deemed contribution (distribution) related to MEMP property exchange (Note 1)					-172,869			172,869
Deferred tax effect of MEMP property exchange (Note 2)	28,020				28,020
Distributions	-46,239							-46,239
Amortization of MEMP equity awards	2,341							2,341
MEMP restricted units repurchased	-7							-7
Other	-14				-12			-2
Total stockholders equity, ending balance at Mar. 31, 2015	447,366			1,908	1,234,194	-788,736
Noncontrolling interests, ending balance at Mar. 31, 2015	1,063,055							1,063,055
Total equity, ending balance at Mar. 31, 2015	$1,510,421

Background_Organization_and_Ba

Background, Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Background, Organization and Basis of Presentation	Note 1. Background, Organization and Basis of Presentation
	Overview
	Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries.
	References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds.
	Previous Owners
	References to “the previous owners” for accounting and financial reporting purposes refer to the net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of certain acquisitions in 2010, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.
	Our unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI.
	Basis of Presentation
	The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP.
	Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.
	All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).
	We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties (See Note 14). Our reportable business segments are as follows:
	·	MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.
	·	MEMP—reflects the combined operations of MEMP and its subsidiaries.
	Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.0 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $172.9 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction. This amount represents $250.8 million of net book value related to the assets transferred to MEMP allocated to its limited partners less $77.9 million of cash allocated to its limited partners. Amounts allocated to MEMP GP eliminate in consolidation.
	Use of Estimates
	The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies
	A discussion of our critical accounting policies and estimates is included in our 2014 Form 10-K.
	Accrued liabilities
	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
		March 31,		December 31,
		2015		2014
	Accrued capital expenditures	$	84,939	$	80,350
	Accrued lease operating expense		17,996		16,403
	Accrued general and administrative expenses		10,098		8,516
	Accrued ad valorem and production taxes		10,390		8,870
	Accrued interest payable		36,815		24,797
	Accrued environmental		1,309		2,092
	Accrued current deferred income taxes		51,937		51,929
	Other miscellaneous, including operator advances		4,185		6,043
		$	217,669	$	199,000
	Income Tax
	Our predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes.  We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes.  As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. We reported no liability for unrecognized tax benefits as of March 31, 2015 and expect no significant change to the unrecognized tax benefits in the next twelve months.
	Our effective tax rate is negative 67.5% for the three months ended March 31, 2015, which differs from the statutory federal income tax rate of 35% primarily due to the following recurring items:
	·	84.0% reduction to the effective tax rate related to pass-through entities;
	·	10.6% reduction to the effective tax rate related to non-deductible incentive compensation; and
	·	8.1% reduction to the effective tax rate related to state income tax provision, net of federal benefit.
	We had a net noncurrent deferred income tax liability of $95.0 million at December 31, 2014, of which $29.2 million was attributable to certain oil and gas properties in East Texas that MEMP acquired from us in February 2015 as noted above.  A deferred income tax benefit of $1.2 million associated with these oil and gas properties was recorded during February 2015.  As such, a net deferred income tax liability of $28.0 million has been reduced through additional paid capital in our equity statement.
	New Accounting Pronouncements
	Presentation of Debt Issuance Cost. In April 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the impact of adopting this guidance to be material to the Company's financial statements and related disclosures.
	Amendments to Consolidation Analysis. In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures.
	Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures
	Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	2,580			$	2,462
	2015 Divestitures
	Subsequent event. On April 17, 2015, MRD sold certain oil and natural gas properties to a third party in Colorado and Wyoming for approximately $13.5 million (the “Rockies Divestiture”).
	2014 Acquisitions
	On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford (the “Eagle Ford Acquisition”). In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold.
	In July 2014, MEMP closed a third-party acquisition that was deemed significant to our consolidated financial statements. The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2014 as though this third-party acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
		For the Three Months Ended
		March 31,
		2014
		(In thousands)
	Revenues	$	252,019
	Net income (loss)		(14,817	)

Fair_Value_Measurements_of_Fin

Fair Value Measurements of Financial Instruments	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments
	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.
	The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at March 31, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The fair market values of the derivative financial instruments reflected on the balance sheets as of March 31, 2015 and December 31, 2014 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
	The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels:
		Fair Value Measurements at March 31, 2015 Using
		Quoted Prices in		Significant Other		Significant
		Active		Observable		Unobservable
		Market		Inputs		Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	1,022,706	$	—	$	1,022,706
	Interest rate derivatives		—		10		—		10
	Total assets	$	—	$	1,022,716	$	—	$	1,022,716
	Liabilities:
	Commodity derivatives	$	—	$	87,809	$	—	$	87,809
	Interest rate derivatives		—		3,549		—		3,549
	Total liabilities	$	—	$	91,358	$	—	$	91,358
		Fair Value Measurements at December 31, 2014 Using
		Quoted Prices in		Significant Other		Significant
		Active		Observable		Unobservable
		Market		Inputs		Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	845,759	$	—	$	845,759
	Interest rate derivatives		—		1,305		—		1,305
	Total assets	$	—	$	847,064	$	—	$	847,064
	Liabilities:
	Commodity derivatives	$	—	$	71,639	$	—	$	71,639
	Interest rate derivatives		—		3,289		—		3,289
	Total liabilities	$	—	$	74,928	$	—	$	74,928
	See Note 5 for additional information regarding our derivative instruments.
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:
	·	The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs.
	·	If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.
	·	Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.
	·	During the period ended March 31, 2015, MEMP recognized $251.3 million of impairments primarily related to certain properties located in East Texas, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable due to declining commodity prices. The carrying value of these properties after the $251.3 million impairment was approximately $157.6 million. MEMP did not record any impairments for the three months ended March 31, 2014.

Risk_Management_and_Derivative

Risk Management and Derivative Instruments	3 Months Ended
	Mar. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments
	Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.
	Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party.
	At March 31, 2015, MEMP had net derivative assets of $601.0 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $328.4 million related to its derivative instruments of which $113.4 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $272.6 million against amounts outstanding under its revolving credit facility at March 31, 2015. At March 31, 2015, MRD had net derivative assets of $330.5 million. After taking into effect netting arrangements, MRD had counterparty exposure of $248.7 million related to derivative instruments of which $66.6 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $81.8 million against amounts outstanding under its revolving credit facility at March 31, 2015. See Note 8 for additional information regarding our revolving credit facilities.
	Commodity Derivatives
	We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and the Company agrees to defer the premium paid or received until the time of settlement. Cash settlements received on settled derivative positions during the three months ended March 31, 2015 is net of deferred premiums of $1.8 million.
	In February 2015, MEMP restructured a portion of its commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives.
	We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.
	At March 31, 2015, the MRD Segment had the following open commodity positions:
		Remaining
		2015				2016				2017				2018
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		3,600,000				2,570,000				1,770,000				4,600,000
	Weighted-average fixed price	$	4.15			$	4.09			$	4.24			$	4.06
	Collar contracts:
	Average Monthly Volume (MMBtu)		130,000				1,100,000				1,050,000				—
	Weighted-average floor price	$	4			$	4			$	4			$	—
	Weighted-average ceiling price	$	4.64			$	4.71			$	5.06			$	—
	Purchased put option contracts:
	Average Monthly Volume (MMBtu)		3,366,667				4,100,000				3,450,000				2,850,000
	Weighted-average fixed price	$	3.75			$	3.75			$	3.75			$	3.75
	Weighted-average deferred premium paid	$	(0.33	)		$	(0.36	)		$	(0.35	)		$	(0.35	)
	Written call option contracts (1):
	Average Monthly Volume (MMBtu)		2,625,000				—				—				—
	Weighted-average sold strike price	$	3.75			$	—			$	—			$	—
	Weighted-average deferred premium received	$	0.08			$	—			$	—			$	—
	TGT Z1 basis swaps:
	Average Monthly Volume (MMBtu)		3,480,000				1,120,000				200,000				—
	Spread - Henry Hub	$	(0.10	)		$	(0.10	)		$	(0.08	)		$	—
	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		45,000				8,500				28,000				31,625
	Weighted-average fixed price	$	91.67			$	84.8			$	84.7			$	84.5
	Collar contracts:
	Average Monthly Volume (Bbls)		2,000				27,000				—				—
	Weighted-average floor price	$	85			$	80			$	—			$	—
	Weighted-average ceiling price	$	101.35			$	99.7			$	—			$	—
	Purchased put option contracts:
	Average Monthly Volume (Bbls)		30,333				—				—				—
	Weighted-average fixed price	$	85			$	—			$	—			$	—
	Weighted-average deferred premium paid	$	(3.80	)		$	—			$	—			$	—
	Written call option contracts (1):
	Average Monthly Volume (Bbls)		22,750				—				—				—
	Weighted-average sold strike price	$	85			$	—			$	—			$	—
	Weighted-average deferred premium received	$	0.48			$	—			$	—			$	—
	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		155,000				185,658				—				—
	Weighted-average fixed price	$	41.58			$	34.06			$	—			$	—
	-1	These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps.
	At March 31, 2015, the MEMP Segment had the following open commodity positions:
		Remaining
		2015				2016				2017				2018				2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		3,061,181				3,292,442				3,050,067				2,760,000				2,514,583
	Weighted-average fixed price	$	4.16			$	4.22			$	4.14			$	4.28			$	4.43
	Collar contracts:
	Average Monthly Volume (MMBtu)		350,000				—				—				—				—
	Weighted-average floor price	$	4.62			$	—			$	—			$	—			$	—
	Weighted-average ceiling price	$	5.8			$	—			$	—			$	—			$	—
	Call spreads (1):
	Average Monthly Volume (MMBtu)		80,000				—				—				—				—
Weighted-average sold strike price	$	5.25			$	—			$	—			$	—			$	—
Weighted-average bought strike price	$	6.75			$	—			$	—			$	—			$	—
Basis swaps:
Average Monthly Volume (MMBtu)		3,390,000				3,108,333				415,000				115,000				—
Spread	$	(0.12	)		$	(0.05	)		$	—			$	0.15			$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		273,864				279,813				301,600				312,000				160,000
Weighted-average fixed price	$	91.34			$	86.87			$	84.7			$	83.74			$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		5,000				—				—				—				—
Weighted-average floor price	$	80			$	—			$	—			$	—			$	—
Weighted-average ceiling price	$	94			$	—			$	—			$	—			$	—
Basis swaps:
Average Monthly Volume (Bbls)		97,333				95,000				—				—				—
Spread	$	(7.07	)		$	(9.56	)		$	—			$	—			$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		211,867				158,600				43,300				—				—
Weighted-average fixed price	$	42.3			$	40.36			$	37.55			$	—			$	—
-1	These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.
The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below:
	Remaining
	2015				2016				2017				2018
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,730,000				2,703,333				300,000				—
Spread - Henry Hub	$	(0.12	)		$	(0.07	)		$	(0.05	)		$	—
HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000				135,000				115,000				115,000
Spread - Henry Hub	$	(0.08	)		$	0.07			$	0.14			$	0.15
CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000				—				—				—
Spread - Henry Hub	$	(0.25	)		$	—			$	—			$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000				270,000				—				—
Spread - Henry Hub	$	(0.09	)		$	0.06			$	—			$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,333				55,000				—				—
Spread - Brent	$	(9.73	)		$	(13.35	)		$	—			$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000				40,000				—				—
Spread - WTI	$	(3.25	)		$	(4.34	)		$	—			$	—
Interest Rate Swaps
Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreements to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At March 31, 2015, we had the following interest rate swap open positions:
	Remaining
Credit Facility	2015				2016				2017				2018
MEMP:
Average Monthly Notional (in thousands)	$	386,111			$	400,000			$	400,000			$	100,000
Weighted-average fixed rate		1.247	%			0.943	%			1.612	%			1.946	%
Floating rate	1 Month LIBOR				1 Month LIBOR				1 Month LIBOR				1 Month LIBOR
Balance Sheet Presentation
The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at March 31, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements.
				Asset Derivatives								Liability Derivatives
				March 31,				December 31,				March 31,				December 31,
Type		Balance Sheet Location		2015				2014				2015				2014
				(In thousands)
Commodity contracts		Short-term derivative instruments		$	398,708			$	378,908			$	41,954			$	38,852
Interest rate swaps		Short-term derivative instruments			—				—				2,994				3,289
Gross fair value					398,708				378,908				44,948				42,141
Netting arrangements		Short-term derivative instruments			(41,648	)			(38,852	)			(41,648	)			(38,852	)
Net recorded fair value		Short-term derivative instruments		$	357,060			$	340,056			$	3,300			$	3,289
Commodity contracts		Long-term derivative instruments		$	623,998			$	466,851			$	45,855			$	32,787
Interest rate swaps		Long-term derivative instruments			10				1,305				555				—
Gross fair value					624,008				468,156				46,410				32,787
Netting arrangements		Long-term derivative instruments			(45,855	)			(32,787	)			(45,855	)			(32,787	)
Net recorded fair value		Long-term derivative instruments		$	578,153			$	435,369			$	555			$	—
(Gains) Losses on Derivatives
All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the three months ended March 31, 2015 and 2014 (in thousands):
				For the Three Months Ended
		Statements of		March 31,
		Operations Location		2015				2014
Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(253,649	)		$	59,482
Interest rate derivatives		Interest expense, net			2,441				511

Asset_Retirement_Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations
	Asset retirement obligations primarily relate to our portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2015 (in thousands):
	Asset retirement obligations at beginning of period	$	122,531
	Liabilities added from acquisitions or drilling		39
	Revisions		149
	Accretion expense		1,757
	Asset retirement obligations at end of period	$	124,476

Restricted_Investments

Restricted Investments	3 Months Ended
	Mar. 31, 2015
Schedule Of Investments [Abstract]
Restricted Investments	Note 7. Restricted Investments
	Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with offshore Southern California oil and gas properties owned by MEMP. The components of the restricted investment balance consisted of the following at the dates indicated:
		March 31,		December 31,
		2015		2014
		(In thousands)
	BOEM platform abandonment (See Note 15)	$	71,263	$	69,954
	BOEM lease bonds		794		794
	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,818		2,701
	California State Lands Commission pipeline right-of-way bond		3,005		3,005
	City of Long Beach pipeline facility permit		500		500
	Federal pipeline right-of-way bond		307		307
	Port of Long Beach pipeline license		100		100
	Restricted investments	$	78,787	$	77,361

Long_Term_Debt

Long Term Debt	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Long Term Debt	Note 8. Long Term Debt
	The following table presents our consolidated debt obligations at the dates indicated:
		March 31,			December 31,
		2015			2014
		(In thousands)
	MRD Segment:
	MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	144,000		$	183,000
	5.875% senior unsecured notes, due July 2022 (1)		600,000			600,000
	Subtotal		744,000			783,000
	MEMP Segment:
	MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		573,000			412,000
	7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2)		700,000			700,000
	6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3)		496,990			500,000
	Unamortized discounts		(15,945	)		(16,587	)
	Subtotal		1,754,045			1,595,413
	Total long-term debt	$	2,498,045		$	2,378,413
	-1	The estimated fair value of this fixed-rate debt was $564.0 million and $534.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	-2	The estimated fair value of this fixed-rate debt was $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	-3	The estimated fair value of this fixed-rate debt was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	Borrowing Base
	Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities’ borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for each credit facility was the following at the date indicated (in thousands):
		March 31,
		2015
	MRD Segment:
	MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	725,000
	MEMP Segment:
	MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		1,300,000
	Subsequent event. On April 13, 2015, MRD’s revolving credit facility borrowing base was re-affirmed at $725.0 million.
	Weighted-Average Interest Rates
	The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented:
		For the Three Months Ended
	Credit Facility	March 31,
		2015			2014
	MRD Segment:
	MRD revolving credit facility		1.87	%	n/a
	WildHorse Resources revolver terminated June 2014	n/a				3.97	%
	WildHorse Resources second lien terminated June 2014	n/a				6.44	%
	MEMP Segment:
	MEMP revolving credit facility		1.9	%		1.66	%
	Unamortized Deferred Financing Costs
	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:
		March 31,			December 31,
		2015			2014
		(In thousands)
	MRD Segment:
	MRD revolving credit facility	$	4,060		$	4,285
	MRD senior notes		12,041			12,455
	MEMP Segment:
	MEMP revolving credit facility		5,395			6,468
	2021 Senior Notes		12,779			13,308
	2022 Senior Notes		7,656			7,958
		$	41,931		$	44,474

Stockholders_Equity_and_Noncon

Stockholders' Equity and Noncontrolling Interests	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Stockholders' Equity and Noncontrolling Interests	Note 9. Stockholders’ Equity and Noncontrolling Interests
	Common Stock
	The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the three months ended March 31, 2015:
	Balance December 31, 2014	193,435,414
	Shares of common stock repurchased	(2,764,887	)
	Restricted common shares issued (Note 11)	115,302
	Restricted common shares forfeited	(9,211	)
	Balance March 31, 2015	190,776,618
	See Note 11 for additional information regarding restricted common shares. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.
	Share Repurchase Program
	MRD repurchased 2,764,887 shares of common stock under the December 2014 repurchase program for an aggregate price of $47.8 million through March 16, 2015, which exhausted the December 2014 repurchase program. MRD has retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding.
	Subsequent event. In April 2015, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which may be suspended or discontinued at any time. The amount, timing and price of purchases will depend on market conditions and other factors.
	Noncontrolling Interests
	Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries.
	Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC prior to our initial public offering. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings.
	During the three months ended March 31, 2015, MEMP repurchased 1,909,583 common units under its repurchase program for an aggregate price of $28.4 million. MEMP has retired all common units repurchased and those common units are no longer issued or outstanding.

Earnings_per_Share

Earnings per Share	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Earnings per Share	Note 10. Earnings per Share
	The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts):
		For the Three
		Months Ended
		March 31,
		2015
	Numerator:
	Net income (loss) available to common stockholders	$	45,615
	Denominator:
	Weighted average common shares outstanding		190,705
	Basic EPS	$	0.24
	Diluted EPS (1)	$	0.24
	-1	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for the period presented. Under the treasury stock method, 151,123 incremental shares were included in the diluted EPS computation.

LongTerm_Incentive_Plans

Long-Term Incentive Plans	3 Months Ended
	Mar. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Long-Term Incentive Plans	Note 11. Long-Term Incentive Plans
	MRD
	The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented:
		Number of Shares				Weighted-Average Grant Date Fair Value per Share (1)
	Restricted common shares outstanding at December 31, 2014		1,059,211			$	19
	Granted (2)		115,302			$	18.05
	Forfeited		(9,211	)		$	19
	Restricted common shares outstanding at March 31, 2015		1,165,302			$	18.91
	(1)Determined by dividing the aggregate grant date fair value of awards issued.
	-2	The aggregate grant date fair value of restricted common share awards issued in 2015 was $2.1 million based on a grant date market price of $18.05 per share.
	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	1,486			n/a
	The unrecognized compensation cost associated with restricted common share awards was $17.7 million at March 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.13 years.
	MEMP
	The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented:
		Number of Units				Weighted-Average Grant Date Fair Value per Unit (1)
	Restricted common units outstanding at December 31, 2014		1,093,520			$	20.93
	Granted (2)		157,360			$	15.45
	Forfeited		(12,467	)		$	20.73
	Vested		(78,307	)		$	19.16
	Restricted common units outstanding at March 31, 2015		1,160,106			$	20.31
	-1	Determined by dividing the aggregate grant date fair value of awards issued.
	-2	The aggregate grant date fair value of restricted common unit awards issued in 2015 was $2.4 million based on a grant date market price of $15.45 per unit.
	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	2,341			$	1,295
	The unrecognized compensation cost associated with restricted common unit awards was $16.3 million at March 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.99 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to noncontrolling interests as presented on our unaudited condensed statements of consolidated and combined cash flows.

Incentive_Units

Incentive Units	3 Months Ended
	Mar. 31, 2015
Compensation Related Costs [Abstract]
Incentive Units	Note 12. Incentive Units
	MRD Holdco
	MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”).
	We recognized $10.2 million of compensation expense during the three months ended March 31, 2015, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $95.5 million as of March 31, 2015 will be recognized over the remaining expected service period of 2.17 years.
	The fair value of the Exchanged and Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by deemed capital contributions. As such, these awards are not dilutive to our stockholders.
	The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:
		Exchanged Incentive Units			Subsequent Incentive Units
	Valuation date	3/31/15			3/31/15
	Dividend yield		0	%		0	%
	Expected volatility		27.9	%		27.9	%
	Risk-free rate		0.61	%		0.61	%
	Expected life (years)		2.17			2.17

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 13. Related Party Transactions
	Amounts due to (due from) MRD Holdco and certain affiliates of NGP at March 31, 2015 and December 31, 2014 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.
	NGP Affiliated Companies
	During the three months ended March 31, 2015, MRD paid approximately $0.6 million to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities.
	NGPCIF NPI Acquisition
	WildHorse Resources purchased a net profits interest from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands):
	Accounts receivable	$	2,274
	Oil and natural gas properties, net		40,056
	Accrued liabilities		(297	)
	Asset retirement obligations		(277	)
	Net assets	$	41,756
	Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates.
	Other Acquisitions or Dispositions
	On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution.
	On March 28, 2014, our predecessor acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from a NGP affiliated company for $3.3 million. Due to common control considerations, this transaction was recognized in the equity statement.
	Related Party Agreements
	We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.
	Registration Rights Agreement
	In connection with the closing of our initial public offering, we entered into a registration rights agreement with MRD Holdco and former management members of WildHorse Resources, Jay Graham (“Graham”) and Anthony Bahr (“Bahr”). Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.
	Voting Agreement
	In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco.
	Services Agreement
	In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WildHorse Resource Management Company, LLC (“WHR Management Company”), pursuant to which WHR Management Company agreed to provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we paid a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits.
	Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company (“WHR II”). NGP and certain former management members of WildHorse Resources own WHR II.
	The services agreement was terminated effective March 1, 2015.
	WildHorse Management Services Agreement
	A discussion of the WildHorse and WHR II management services and related agreements is included in our 2014 Form 10-K. These agreements were terminated in connection with our initial public offering.
	Gas Processing Agreement
	Subsequent event. On April 14, 2015, we, through our wholly-owned subsidiary, MRD Operating, entered into an amended and restated gas processing agreement (“GPA”) with PennTex North Louisiana Operating, LLC (“PennTex Operating”), a wholly-owned subsidiary of PennTex North Louisiana, LLC (“PennTex”). WildHorse Resources, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015, initially entered into a gas processing agreement with PennTex in March 2014, prior to our initial public offering. PennTex is a joint venture among certain affiliates of NGP in which MRD Midstream LLC, a wholly-owned subsidiary of MRD Holdco, owns a minority interest. Once PennTex Operating’s first processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The GPA has a 15-year primary term, subject to one-year extensions at either party’s election. We will pay PennTex Operating a monthly volume processing fee, subject to annual inflation escalators, based on volumes of natural gas processed by PennTex Operating. Once the first plant is declared operational, we will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions until the second processing plant is declared operational. Once the second plant is declared operational, we will be obligated to pay a minimum volume processing fee equal to approximately $55.0 million on an annual basis, subject to certain adjustments and conditions.
	In addition, on April 14, 2015, we entered into (i) an amended and restated area of mutual interest and midstream exclusivity agreement (“AMI”) with PennTex NLA Holdings, LLC, which owns a majority interest in PennTex, MRD WHR LA Midstream LLC, an affiliate of MRD Holdco, and PennTex, (ii) a gas transportation agreement (“GTA”) with PennTex Operating, (iii) a gas gathering agreement (“GGA”) with PennTex Operating, and (iv) a transportation services agreement (“TSA” and, together with the GPA, AMI, GTA, and GGA, the “Midstream Agreements”) with PennTex Operating to provide gathering, residue gas and natural gas liquids transportation services to us in the state of Louisiana. The Midstream Agreements have a 15-year primary term, subject to one-year extensions at either party’s elections.
	Under the GGA, once the first processing plant is declared operational, we will pay PennTex Operating a commodity usage charge equal to at least the minimum volume commitment (115,000 MMBtu per day) times $0.02 per MMBtu until PennTex Operating’s second processing plant is declared operational. Once the second processing plant is declared operational, we will pay PennTex Operating a commodity usage charge equal to at least an increased minimum volume commitment (345,000 MMBtu per day) times $0.02 MMBtu through November 30, 2019. The minimum volume commitment will increase to 460,000 MMBtu on July 1, 2016 and may further increase subject to the terms of the GGA. Prior to December 1, 2019, PennTex Operating is also entitled to a payback demand fee from us equal to the monthly demand quantity (460,000 MMBtu per day) times a $0.03 MMBtu through November 30, 2019. Beginning on December 1, 2019, PennTex Operating is not entitled to a monthly demand charge, the commodity usage charge escalates to $0.05 per MMBtu, and PennTex Operating is entitled to receive a commodity usage charge from us equal to the minimum volume commitment (460,000 MMBtu per day through June 30, 2026, and 345,000 MMBtu per day thereafter) times $0.05 MMBtu.
	Similarly, under each of the GTA and TSA, which commence concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per MMBtu for all volumes of residue gas and natural gas liquids produced on our behalf.
	Under the AMI, we granted PennTex Operating the exclusive right to build all of our midstream infrastructure in northern Louisiana and to provide midstream services to support our current and future production on our operated acreage within such area (other than production subject to existing third-party commitments).
	Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement
	In November 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.
	In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline.
	In February 2015, in connection with and as part of the Property Swap, Classic sold all of the equity interests owned by it in Classic Operating to Memorial Production Operating LLC, a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015.

Business_Segment_Data

Business Segment Data	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Business Segment Data	MEMORIAL RESOURCE DEVELOPMENT CORP.
	NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
	Note 14. Business Segment Data
	Our reportable business segments are organized in a manner that reflects how management manages those business activities.
	We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties. Our reportable business segments are as follows:
	·	MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.
	·	MEMP—reflects the combined operations of MEMP and its subsidiaries.
	We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of goodwill and long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); transaction related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid on expired positions; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items.
	Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available.
	Segment revenues and expenses include intersegment transactions. Our combined totals reflect the elimination of intersegment transactions.
	In the MRD Segment’s individual financial statements, investments in the MEMP Segment that are included in the consolidated and combined financial statements are accounted for by the equity method.
	The following table presents selected business segment information for the periods indicated (in thousands):
								Other,			Consolidated
								Adjustments &			& Combined
		MRD			MEMP			Eliminations			Totals
	Total revenues:
	For the Three Months Ended March 31, 2015	$	87,023		$	92,818		$	—		$	179,841
	For the Three Months Ended March 31, 2014		87,736			116,885			—			204,621
	Adjusted EBITDA: (1)
	For the Three Months Ended March 31, 2015		86,830			86,432			(76	)		173,186
	For the Three Months Ended March 31, 2014		64,752			62,046			(3,002	)		123,796
	Segment assets: (2)
	As of March 31, 2015		1,535,233			3,051,190			(12,201	)		4,574,222
	As of December 31, 2014		1,413,768			3,189,760			(9,981	)		4,593,547
	Total cash expenditures for additions to long-lived assets:
	For the Three Months Ended March 31, 2015		88,566			77,680			—			166,246
	For the Three Months Ended March 31, 2014		75,258			231,973			—			307,231
	-1	Adjustments and eliminations for the three months ended March 31, 2015 and 2014 include less than $0.1 million and $3.0 million of cash distributions that MEMP paid MRD for the three months ended March 31, 2015 and 2014, respectively, related to MRD’s partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014.
	-2	As of March 31, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment.
	Calculation of Reportable Segments’ Adjusted EBITDA
		For the Three Months Ended
		31-Mar-15
								Combined
		MRD			MEMP			Totals
		(In thousands)
	Net income (loss)	$	50,371		$	(162,658	)	$	(112,287	)
	Interest expense, net		9,756			28,818			38,574
	Income tax expense (benefit)		47,558			(2,370	)		45,188
	DD&A		40,532			51,266			91,798
	Impairment of proved oil and natural gas properties		—			251,347			251,347
	Accretion of AROs		123			1,634			1,757
	(Gain) loss on commodity derivative instruments		(108,190	)		(145,459	)		(253,649	)
	Cash settlements received (paid) on expired commodity derivative instruments		32,749			60,124			92,873
	Transaction related costs		1,281			1,299			2,580
	Incentive-based compensation expense		11,710			2,341			14,051
	Exploration costs		726			90			816
	Non-cash equity (income) loss from MEMP		138			—			138
	Cash distributions from MEMP		76			—			76
	Adjusted EBITDA	$	86,830		$	86,432		$	173,262
		For the Three Months Ended
		31-Mar-14
								Combined
		MRD			MEMP			Totals
					(In thousands)
	Net income (loss)	$	6,390		$	(32,892	)	$	(26,502	)
	Interest expense, net		17,974			16,078			34,052
	Income tax expense (benefit)		25			75			100
	DD&A		25,129			32,550			57,679
	Accretion of AROs		130			1,391			1,521
	(Gain) loss on commodity derivative instruments		12,716			46,766			59,482
	Cash settlements received (paid) on expired commodity derivative instruments		(5,221	)		(7,969	)		(13,190	)
	(Gain) loss on sale of properties		(110	)		—			(110	)
	Transaction related costs		568			1,894			2,462
	Incentive-based compensation expense		1,023			1,295			2,318
Exploration costs		140			6			146
Provision for environmental remediation		—			2,852			2,852
Non-cash equity (income) loss from MEMP		2,986			—			2,986
Cash distributions from MEMP		3,002			—			3,002
Adjusted EBITDA	$	64,752		$	62,046		$	126,798
The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands).
	For the Three Months Ended
	March 31,
	2015			2014
Total Reportable Segments' Adjusted EBITDA	$	173,262		$	126,798
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(38,574	)		(34,052	)
Income tax benefit (expense)		(45,188	)		(100	)
DD&A		(91,798	)		(57,679	)
Impairment of proved oil and natural gas properties		(251,347	)		—
Accretion of AROs		(1,757	)		(1,521	)
Gains (losses) on commodity derivative instruments		253,649			(59,482	)
Cash settlements paid (received) on expired commodity derivative instruments		(92,873	)		13,190
Gain (loss) on sale of properties		—			110
Transaction related costs		(2,580	)		(2,462	)
Incentive-based compensation expense		(14,051	)		(2,318	)
Exploration costs		(816	)		(146	)
Provision for environmental remediation		—			(2,852	)
Cash distributions from MEMP		(76	)		(3,002	)
Net income (loss)	$	(112,149	)	$	(23,516	)
Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands):
	For the Three Months Ended March 31, 2015
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	87,023		$	91,949		$	—		$	178,972
Other revenues		—			869			—			869
Total revenues		87,023			92,818			—			179,841
Costs and expenses:
Lease operating		5,222			40,478			—			45,700
Gathering, processing, and transportation		14,763			8,220			—			22,983
Pipeline operating		—			446			—			446
Exploration		726			90			—			816
Production and ad valorem taxes		2,775			6,655			—			9,430
Depreciation, depletion, and amortization		40,532			51,266			—			91,798
Impairment of proved oil and natural gas properties		—			251,347			—			251,347
Incentive unit compensation expense		10,224			—			—			10,224
General and administrative		12,976			14,511			—			27,487
Accretion of asset retirement obligations		123			1,634			—			1,757
(Gain) loss on commodity derivative instruments		(108,190	)		(145,459	)		—			(253,649	)
Total costs and expenses		(20,849	)		229,188			—			208,339
Operating income (loss)		107,872			(136,370	)		—			(28,498	)
Other income (expense):
Interest expense, net		(9,756	)		(28,818	)		—			(38,574	)
Earnings from equity investments		(138	)		—			138			—
Other, net		(49	)		160			—			111
Total other income (expense)		(9,943	)		(28,658	)		138			(38,463	)
Income (loss) before income taxes		97,929			(165,028	)		138			(66,961	)
Income tax benefit (expense)		(47,558	)		2,370			—			(45,188	)
Net income (loss)	$	50,371		$	(162,658	)	$	138		$	(112,149	)
	For the Three Months Ended March 31, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	87,733		$	115,977		$	—		$	203,710
Other revenues		3			908			—			911
Total revenues		87,736			116,885			—			204,621
Costs and expenses:
Lease operating		3,235			30,120			—			33,355
Gathering, processing, and transportation		8,557			5,563						14,120
Pipeline operating		—			489			—			489
Exploration		140			6			—			146
Production and ad valorem taxes		2,573			6,011			—			8,584
Depreciation, depletion, and amortization		25,129			32,550			—			57,679
Incentive unit compensation expense		1,023			—			—			1,023
General and administrative		6,999			10,740			—			17,739
Accretion of asset retirement obligations		130			1,391			—			1,521
(Gain) loss on commodity derivative instruments		12,716			46,766			—			59,482
(Gain) loss on sale of properties		(110	)		—			—			(110	)
Other, net		—			(12	)		—			(12	)
Total costs and expenses		60,392			133,624			—			194,016
Operating income (loss)		27,344			(16,739	)		—			10,605
Other income (expense):
Interest expense, net		(17,974	)		(16,078	)		—			(34,052	)
Earnings from equity investments		(2,986	)		—			2,986			—
Other, net		31			—			—			31
Total other income (expense)		(20,929	)		(16,078	)		2,986			(34,021	)
Income (loss) before income taxes		6,415			(32,817	)		2,986			(23,416	)
Income tax benefit (expense)		(25	)		(75	)		—			(100	)
Net income (loss)	$	6,390		$	(32,892	)	$	2,986		$	(23,516	)

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 15. Commitments and Contingencies
	Litigation & Environmental
	As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.
	At March 31, 2015 and December 31, 2014, we had $1.3 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively.
	Gas Processing Agreement
	See Note 13 for additional information.
	Supplemental Bond for Decommissioning Liabilities Trust Agreement
	In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities. The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of March 31, 2015 (in thousands):
		Amortized
	Investment	Cost
	U.S. Bank Money Market Cash Equivalent	$	137,705
	Less: Outside working interest owners share		(66,442	)
		$	71,263
	The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):
	30-Jun-15	$	72,450
	30-Jun-16	$	76,590
	31-Dec-16	$	78,660
	As of March 31, 2015, the maximum remaining obligation net to REO’s interest was approximately $7.4 million.
	Processing Plant Expansions by Third Party Gatherer
	A discussion of processing plant expansions by a third party gatherer is included in our 2014 Form 10-K.
	Related Party Agreements
	See Note 13 for additional information.

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Note 16. Subsequent Events
	MRD Common Stock Repurchase Approval
	For additional information, see Note 9.
	MRD Borrowing Base Reaffirmed
	For additional information, see Note 8.
	MRD Sale of Oil and Natural Gas Properties in Colorado and Wyoming
	For additional information, see Note 3.
	MRD and PennTex Midstream Agreements
	For additional information, see Note 13.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Overview	Overview
	Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries.
	References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds.
Previous Owners	Previous Owners
	References to “the previous owners” for accounting and financial reporting purposes refer to the net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of certain acquisitions in 2010, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.
	Our unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI.
Basis of Presentation	Basis of Presentation
	The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP.
	Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.
	All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).
	We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties (See Note 14). Our reportable business segments are as follows:
	·	MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.
	·	MEMP—reflects the combined operations of MEMP and its subsidiaries.
	Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.0 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $172.9 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction. This amount represents $250.8 million of net book value related to the assets transferred to MEMP allocated to its limited partners less $77.9 million of cash allocated to its limited partners. Amounts allocated to MEMP GP eliminate in consolidation.
Use of Estimates	Use of Estimates
	The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Accrued Liabilities	Accrued liabilities
	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
		March 31,		December 31,
		2015		2014
	Accrued capital expenditures	$	84,939	$	80,350
	Accrued lease operating expense		17,996		16,403
	Accrued general and administrative expenses		10,098		8,516
	Accrued ad valorem and production taxes		10,390		8,870
	Accrued interest payable		36,815		24,797
	Accrued environmental		1,309		2,092
	Accrued current deferred income taxes		51,937		51,929
	Other miscellaneous, including operator advances		4,185		6,043
		$	217,669	$	199,000
Income Tax	Income Tax
	Our predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes.  We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes.  As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. We reported no liability for unrecognized tax benefits as of March 31, 2015 and expect no significant change to the unrecognized tax benefits in the next twelve months.
	Our effective tax rate is negative 67.5% for the three months ended March 31, 2015, which differs from the statutory federal income tax rate of 35% primarily due to the following recurring items:
	·	84.0% reduction to the effective tax rate related to pass-through entities;
	·	10.6% reduction to the effective tax rate related to non-deductible incentive compensation; and
	·	8.1% reduction to the effective tax rate related to state income tax provision, net of federal benefit.
	We had a net noncurrent deferred income tax liability of $95.0 million at December 31, 2014, of which $29.2 million was attributable to certain oil and gas properties in East Texas that MEMP acquired from us in February 2015 as noted above.  A deferred income tax benefit of $1.2 million associated with these oil and gas properties was recorded during February 2015.  As such, a net deferred income tax liability of $28.0 million has been reduced through additional paid capital in our equity statement.
New Accounting Pronouncements	New Accounting Pronouncements
	Presentation of Debt Issuance Cost. In April 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the impact of adopting this guidance to be material to the Company's financial statements and related disclosures.
	Amendments to Consolidation Analysis. In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures.
	Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Schedule of Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
		March 31,		December 31,
		2015		2014
	Accrued capital expenditures	$	84,939	$	80,350
	Accrued lease operating expense		17,996		16,403
	Accrued general and administrative expenses		10,098		8,516
	Accrued ad valorem and production taxes		10,390		8,870
	Accrued interest payable		36,815		24,797
	Accrued environmental		1,309		2,092
	Accrued current deferred income taxes		51,937		51,929
	Other miscellaneous, including operator advances		4,185		6,043
		$	217,669	$	199,000

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Acquisition-Related Costs	Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	2,580			$	2,462
Unaudited Pro Forma Results of Operations	In July 2014, MEMP closed a third-party acquisition that was deemed significant to our consolidated financial statements. The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2014 as though this third-party acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
		For the Three Months Ended
		March 31,
		2014
		(In thousands)
	Revenues	$	252,019
	Net income (loss)		(14,817	)

Fair_Value_Measurements_of_Fin1

Fair Value Measurements of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels:
		Fair Value Measurements at March 31, 2015 Using
		Quoted Prices in		Significant Other		Significant
		Active		Observable		Unobservable
		Market		Inputs		Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	1,022,706	$	—	$	1,022,706
	Interest rate derivatives		—		10		—		10
	Total assets	$	—	$	1,022,716	$	—	$	1,022,716
	Liabilities:
	Commodity derivatives	$	—	$	87,809	$	—	$	87,809
	Interest rate derivatives		—		3,549		—		3,549
	Total liabilities	$	—	$	91,358	$	—	$	91,358
		Fair Value Measurements at December 31, 2014 Using
		Quoted Prices in		Significant Other		Significant
		Active		Observable		Unobservable
		Market		Inputs		Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	845,759	$	—	$	845,759
	Interest rate derivatives		—		1,305		—		1,305
	Total assets	$	—	$	847,064	$	—	$	847,064
	Liabilities:
	Commodity derivatives	$	—	$	71,639	$	—	$	71,639
	Interest rate derivatives		—		3,289		—		3,289
	Total liabilities	$	—	$	74,928	$	—	$	74,928

Risk_Management_and_Derivative1

Risk Management and Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Open Commodity Positions	At March 31, 2015, the MRD Segment had the following open commodity positions:
		Remaining
		2015				2016				2017				2018
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		3,600,000				2,570,000				1,770,000				4,600,000
	Weighted-average fixed price	$	4.15			$	4.09			$	4.24			$	4.06
	Collar contracts:
	Average Monthly Volume (MMBtu)		130,000				1,100,000				1,050,000				—
	Weighted-average floor price	$	4			$	4			$	4			$	—
	Weighted-average ceiling price	$	4.64			$	4.71			$	5.06			$	—
	Purchased put option contracts:
	Average Monthly Volume (MMBtu)		3,366,667				4,100,000				3,450,000				2,850,000
	Weighted-average fixed price	$	3.75			$	3.75			$	3.75			$	3.75
	Weighted-average deferred premium paid	$	(0.33	)		$	(0.36	)		$	(0.35	)		$	(0.35	)
	Written call option contracts (1):
	Average Monthly Volume (MMBtu)		2,625,000				—				—				—
	Weighted-average sold strike price	$	3.75			$	—			$	—			$	—
	Weighted-average deferred premium received	$	0.08			$	—			$	—			$	—
	TGT Z1 basis swaps:
	Average Monthly Volume (MMBtu)		3,480,000				1,120,000				200,000				—
	Spread - Henry Hub	$	(0.10	)		$	(0.10	)		$	(0.08	)		$	—
	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		45,000				8,500				28,000				31,625
	Weighted-average fixed price	$	91.67			$	84.8			$	84.7			$	84.5
	Collar contracts:
	Average Monthly Volume (Bbls)		2,000				27,000				—				—
	Weighted-average floor price	$	85			$	80			$	—			$	—
	Weighted-average ceiling price	$	101.35			$	99.7			$	—			$	—
	Purchased put option contracts:
	Average Monthly Volume (Bbls)		30,333				—				—				—
	Weighted-average fixed price	$	85			$	—			$	—			$	—
	Weighted-average deferred premium paid	$	(3.80	)		$	—			$	—			$	—
	Written call option contracts (1):
	Average Monthly Volume (Bbls)		22,750				—				—				—
	Weighted-average sold strike price	$	85			$	—			$	—			$	—
	Weighted-average deferred premium received	$	0.48			$	—			$	—			$	—
	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		155,000				185,658				—				—
	Weighted-average fixed price	$	41.58			$	34.06			$	—			$	—
	-1	These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps.
	At March 31, 2015, the MEMP Segment had the following open commodity positions:
		Remaining
		2015				2016				2017				2018				2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		3,061,181				3,292,442				3,050,067				2,760,000				2,514,583
	Weighted-average fixed price	$	4.16			$	4.22			$	4.14			$	4.28			$	4.43
	Collar contracts:
	Average Monthly Volume (MMBtu)		350,000				—				—				—				—
	Weighted-average floor price	$	4.62			$	—			$	—			$	—			$	—
	Weighted-average ceiling price	$	5.8			$	—			$	—			$	—			$	—
	Call spreads (1):
	Average Monthly Volume (MMBtu)		80,000				—				—				—				—
	Weighted-average sold strike price	$	5.25			$	—			$	—			$	—			$	—
	Weighted-average bought strike price	$	6.75			$	—			$	—			$	—			$	—
	Basis swaps:
	Average Monthly Volume (MMBtu)		3,390,000				3,108,333				415,000				115,000				—
	Spread	$	(0.12	)		$	(0.05	)		$	—			$	0.15			$	—
	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		273,864				279,813				301,600				312,000				160,000
Weighted-average fixed price	$	91.34			$	86.87			$	84.7			$	83.74			$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		5,000				—				—				—				—
Weighted-average floor price	$	80			$	—			$	—			$	—			$	—
Weighted-average ceiling price	$	94			$	—			$	—			$	—			$	—
Basis swaps:
Average Monthly Volume (Bbls)		97,333				95,000				—				—				—
Spread	$	(7.07	)		$	(9.56	)		$	—			$	—			$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		211,867				158,600				43,300				—				—
Weighted-average fixed price	$	42.3			$	40.36			$	37.55			$	—			$	—
-1	These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.
The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below:
	Remaining
	2015				2016				2017				2018
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,730,000				2,703,333				300,000				—
Spread - Henry Hub	$	(0.12	)		$	(0.07	)		$	(0.05	)		$	—
HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000				135,000				115,000				115,000
Spread - Henry Hub	$	(0.08	)		$	0.07			$	0.14			$	0.15
CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000				—				—				—
Spread - Henry Hub	$	(0.25	)		$	—			$	—			$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000				270,000				—				—
Spread - Henry Hub	$	(0.09	)		$	0.06			$	—			$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,333				55,000				—				—
Spread - Brent	$	(9.73	)		$	(13.35	)		$	—			$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000				40,000				—				—
Spread - WTI	$	(3.25	)		$	(4.34	)		$	—			$	—
Schedule of Entity's Interest Rate Swap Open Positions	At March 31, 2015, we had the following interest rate swap open positions:
		Remaining
	Credit Facility	2015				2016				2017				2018
	MEMP:
	Average Monthly Notional (in thousands)	$	386,111			$	400,000			$	400,000			$	100,000
	Weighted-average fixed rate		1.247	%			0.943	%			1.612	%			1.946	%
	Floating rate	1 Month LIBOR				1 Month LIBOR				1 Month LIBOR				1 Month LIBOR
Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at March 31, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements.
					Asset Derivatives								Liability Derivatives
					March 31,				December 31,				March 31,				December 31,
	Type		Balance Sheet Location		2015				2014				2015				2014
					(In thousands)
	Commodity contracts		Short-term derivative instruments		$	398,708			$	378,908			$	41,954			$	38,852
	Interest rate swaps		Short-term derivative instruments			—				—				2,994				3,289
	Gross fair value					398,708				378,908				44,948				42,141
	Netting arrangements		Short-term derivative instruments			(41,648	)			(38,852	)			(41,648	)			(38,852	)
	Net recorded fair value		Short-term derivative instruments		$	357,060			$	340,056			$	3,300			$	3,289
	Commodity contracts		Long-term derivative instruments		$	623,998			$	466,851			$	45,855			$	32,787
	Interest rate swaps		Long-term derivative instruments			10				1,305				555				—
	Gross fair value					624,008				468,156				46,410				32,787
	Netting arrangements		Long-term derivative instruments			(45,855	)			(32,787	)			(45,855	)			(32,787	)
	Net recorded fair value		Long-term derivative instruments		$	578,153			$	435,369			$	555			$	—
Schedule of Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the three months ended March 31, 2015 and 2014 (in thousands):
					For the Three Months Ended
			Statements of		March 31,
			Operations Location		2015				2014
	Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(253,649	)		$	59,482
	Interest rate derivatives		Interest expense, net			2,441				511

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2015 (in thousands):
	Asset retirement obligations at beginning of period	$	122,531
	Liabilities added from acquisitions or drilling		39
	Revisions		149
	Accretion expense		1,757
	Asset retirement obligations at end of period	$	124,476

Restricted_Investments_Tables

Restricted Investments (Tables)	3 Months Ended
	Mar. 31, 2015
Schedule Of Investments [Abstract]
Restricted Investment Balance	The components of the restricted investment balance consisted of the following at the dates indicated:
		March 31,		December 31,
		2015		2014
		(In thousands)
	BOEM platform abandonment (See Note 15)	$	71,263	$	69,954
	BOEM lease bonds		794		794
	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,818		2,701
	California State Lands Commission pipeline right-of-way bond		3,005		3,005
	City of Long Beach pipeline facility permit		500		500
	Federal pipeline right-of-way bond		307		307
	Port of Long Beach pipeline license		100		100
	Restricted investments	$	78,787	$	77,361

Long_Term_Debt_Tables

Long Term Debt (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated:
		March 31,			December 31,
		2015			2014
		(In thousands)
	MRD Segment:
	MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	144,000		$	183,000
	5.875% senior unsecured notes, due July 2022 (1)		600,000			600,000
	Subtotal		744,000			783,000
	MEMP Segment:
	MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		573,000			412,000
	7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2)		700,000			700,000
	6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3)		496,990			500,000
	Unamortized discounts		(15,945	)		(16,587	)
	Subtotal		1,754,045			1,595,413
	Total long-term debt	$	2,498,045		$	2,378,413
	-1	The estimated fair value of this fixed-rate debt was $564.0 million and $534.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	-2	The estimated fair value of this fixed-rate debt was $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	-3	The estimated fair value of this fixed-rate debt was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
Borrowing Base Credit Facility	The borrowing base for each credit facility was the following at the date indicated (in thousands):
		March 31,
		2015
	MRD Segment:
	MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	725,000
	MEMP Segment:
	MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		1,300,000
Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented:
		For the Three Months Ended
	Credit Facility	March 31,
		2015			2014
	MRD Segment:
	MRD revolving credit facility		1.87	%	n/a
	WildHorse Resources revolver terminated June 2014	n/a				3.97	%
	WildHorse Resources second lien terminated June 2014	n/a				6.44	%
	MEMP Segment:
	MEMP revolving credit facility		1.9	%		1.66	%
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:
		March 31,			December 31,
		2015			2014
		(In thousands)
	MRD Segment:
	MRD revolving credit facility	$	4,060		$	4,285
	MRD senior notes		12,041			12,455
	MEMP Segment:
	MEMP revolving credit facility		5,395			6,468
	2021 Senior Notes		12,779			13,308
	2022 Senior Notes		7,656			7,958
		$	41,931		$	44,474

Stockholders_Equity_and_Noncon1

Stockholders' Equity and Noncontrolling Interests (Tables)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Summary of Changes In Common Shares Issued	The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the three months ended March 31, 2015:
	Balance December 31, 2014	193,435,414
	Shares of common stock repurchased	(2,764,887	)
	Restricted common shares issued (Note 11)	115,302
	Restricted common shares forfeited	(9,211	)
	Balance March 31, 2015	190,776,618

Earnings_per_Share_Tables

Earnings per Share (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Summary of Calculation of Earnings (Loss) Per Share, or EPS	The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts):
		For the Three
		Months Ended
		March 31,
		2015
	Numerator:
	Net income (loss) available to common stockholders	$	45,615
	Denominator:
	Weighted average common shares outstanding		190,705
	Basic EPS	$	0.24
	Diluted EPS (1)	$	0.24
	-1	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for the period presented. Under the treasury stock method, 151,123 incremental shares were included in the diluted EPS computation.

LongTerm_Incentive_Plans_Table

Long-Term Incentive Plans (Tables)	3 Months Ended
	Mar. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented:
		Number of Shares				Weighted-Average Grant Date Fair Value per Share (1)
	Restricted common shares outstanding at December 31, 2014		1,059,211			$	19
	Granted (2)		115,302			$	18.05
	Forfeited		(9,211	)		$	19
	Restricted common shares outstanding at March 31, 2015		1,165,302			$	18.91
	(1)Determined by dividing the aggregate grant date fair value of awards issued.
	-2	The aggregate grant date fair value of restricted common share awards issued in 2015 was $2.1 million based on a grant date market price of $18.05 per share.
	The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented:
		Number of Units				Weighted-Average Grant Date Fair Value per Unit (1)
	Restricted common units outstanding at December 31, 2014		1,093,520			$	20.93
	Granted (2)		157,360			$	15.45
	Forfeited		(12,467	)		$	20.73
	Vested		(78,307	)		$	19.16
	Restricted common units outstanding at March 31, 2015		1,160,106			$	20.31
	-1	Determined by dividing the aggregate grant date fair value of awards issued.
	-2	The aggregate grant date fair value of restricted common unit awards issued in 2015 was $2.4 million based on a grant date market price of $15.45 per unit.
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	1,486			n/a
	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	2,341			$	1,295

Incentive_Units_Tables

Incentive Units (Tables)	3 Months Ended
	Mar. 31, 2015
Compensation Related Costs [Abstract]
Fair Value of Incentive Units Estimated	The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:
		Exchanged Incentive Units			Subsequent Incentive Units
	Valuation date	3/31/15			3/31/15
	Dividend yield		0	%		0	%
	Expected volatility		27.9	%		27.9	%
	Risk-free rate		0.61	%		0.61	%
	Expected life (years)		2.17			2.17

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Schedule of Net Assets Recorded	WildHorse Resources recorded the following net assets (in thousands):
	Accounts receivable	$	2,274
	Oil and natural gas properties, net		40,056
	Accrued liabilities		(297	)
	Asset retirement obligations		(277	)
	Net assets	$	41,756

Business_Segment_Data_Tables

Business Segment Data (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Summary of Selected Business Segment Information	The following table presents selected business segment information for the periods indicated (in thousands):
								Other,			Consolidated
								Adjustments &			& Combined
		MRD			MEMP			Eliminations			Totals
	Total revenues:
	For the Three Months Ended March 31, 2015	$	87,023		$	92,818		$	—		$	179,841
	For the Three Months Ended March 31, 2014		87,736			116,885			—			204,621
	Adjusted EBITDA: (1)
	For the Three Months Ended March 31, 2015		86,830			86,432			(76	)		173,186
	For the Three Months Ended March 31, 2014		64,752			62,046			(3,002	)		123,796
	Segment assets: (2)
	As of March 31, 2015		1,535,233			3,051,190			(12,201	)		4,574,222
	As of December 31, 2014		1,413,768			3,189,760			(9,981	)		4,593,547
	Total cash expenditures for additions to long-lived assets:
	For the Three Months Ended March 31, 2015		88,566			77,680			—			166,246
	For the Three Months Ended March 31, 2014		75,258			231,973			—			307,231
	-1	Adjustments and eliminations for the three months ended March 31, 2015 and 2014 include less than $0.1 million and $3.0 million of cash distributions that MEMP paid MRD for the three months ended March 31, 2015 and 2014, respectively, related to MRD’s partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014.
	-2	As of March 31, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment.
Schedule of Calculation of Reportable Segment's Adjusted EBITDA	Calculation of Reportable Segments’ Adjusted EBITDA
		For the Three Months Ended
		31-Mar-15
								Combined
		MRD			MEMP			Totals
		(In thousands)
	Net income (loss)	$	50,371		$	(162,658	)	$	(112,287	)
	Interest expense, net		9,756			28,818			38,574
	Income tax expense (benefit)		47,558			(2,370	)		45,188
	DD&A		40,532			51,266			91,798
	Impairment of proved oil and natural gas properties		—			251,347			251,347
	Accretion of AROs		123			1,634			1,757
	(Gain) loss on commodity derivative instruments		(108,190	)		(145,459	)		(253,649	)
	Cash settlements received (paid) on expired commodity derivative instruments		32,749			60,124			92,873
	Transaction related costs		1,281			1,299			2,580
	Incentive-based compensation expense		11,710			2,341			14,051
	Exploration costs		726			90			816
	Non-cash equity (income) loss from MEMP		138			—			138
	Cash distributions from MEMP		76			—			76
	Adjusted EBITDA	$	86,830		$	86,432		$	173,262
		For the Three Months Ended
		31-Mar-14
								Combined
		MRD			MEMP			Totals
					(In thousands)
	Net income (loss)	$	6,390		$	(32,892	)	$	(26,502	)
	Interest expense, net		17,974			16,078			34,052
	Income tax expense (benefit)		25			75			100
	DD&A		25,129			32,550			57,679
	Accretion of AROs		130			1,391			1,521
	(Gain) loss on commodity derivative instruments		12,716			46,766			59,482
	Cash settlements received (paid) on expired commodity derivative instruments		(5,221	)		(7,969	)		(13,190	)
	(Gain) loss on sale of properties		(110	)		—			(110	)
	Transaction related costs		568			1,894			2,462
	Incentive-based compensation expense		1,023			1,295			2,318
	Exploration costs		140			6			146
	Provision for environmental remediation		—			2,852			2,852
	Non-cash equity (income) loss from MEMP		2,986			—			2,986
	Cash distributions from MEMP		3,002			—			3,002
	Adjusted EBITDA	$	64,752		$	62,046		$	126,798
Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss)	The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands).
		For the Three Months Ended
		March 31,
		2015			2014
	Total Reportable Segments' Adjusted EBITDA	$	173,262		$	126,798
	Adjustments to reconcile Adjusted EBITDA to net income (loss):
	Interest expense, net		(38,574	)		(34,052	)
	Income tax benefit (expense)		(45,188	)		(100	)
	DD&A		(91,798	)		(57,679	)
	Impairment of proved oil and natural gas properties		(251,347	)		—
	Accretion of AROs		(1,757	)		(1,521	)
	Gains (losses) on commodity derivative instruments		253,649			(59,482	)
	Cash settlements paid (received) on expired commodity derivative instruments		(92,873	)		13,190
	Gain (loss) on sale of properties		—			110
	Transaction related costs		(2,580	)		(2,462	)
	Incentive-based compensation expense		(14,051	)		(2,318	)
	Exploration costs		(816	)		(146	)
	Provision for environmental remediation		—			(2,852	)
	Cash distributions from MEMP		(76	)		(3,002	)
	Net income (loss)	$	(112,149	)	$	(23,516	)
Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment	Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands):
		For the Three Months Ended March 31, 2015
		MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
	Revenues:
	Oil & natural gas sales	$	87,023		$	91,949		$	—		$	178,972
	Other revenues		—			869			—			869
	Total revenues		87,023			92,818			—			179,841
	Costs and expenses:
	Lease operating		5,222			40,478			—			45,700
	Gathering, processing, and transportation		14,763			8,220			—			22,983
	Pipeline operating		—			446			—			446
	Exploration		726			90			—			816
	Production and ad valorem taxes		2,775			6,655			—			9,430
	Depreciation, depletion, and amortization		40,532			51,266			—			91,798
	Impairment of proved oil and natural gas properties		—			251,347			—			251,347
	Incentive unit compensation expense		10,224			—			—			10,224
	General and administrative		12,976			14,511			—			27,487
	Accretion of asset retirement obligations		123			1,634			—			1,757
	(Gain) loss on commodity derivative instruments		(108,190	)		(145,459	)		—			(253,649	)
	Total costs and expenses		(20,849	)		229,188			—			208,339
	Operating income (loss)		107,872			(136,370	)		—			(28,498	)
	Other income (expense):
	Interest expense, net		(9,756	)		(28,818	)		—			(38,574	)
	Earnings from equity investments		(138	)		—			138			—
	Other, net		(49	)		160			—			111
	Total other income (expense)		(9,943	)		(28,658	)		138			(38,463	)
	Income (loss) before income taxes		97,929			(165,028	)		138			(66,961	)
	Income tax benefit (expense)		(47,558	)		2,370			—			(45,188	)
	Net income (loss)	$	50,371		$	(162,658	)	$	138		$	(112,149	)
		For the Three Months Ended March 31, 2014
		MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
	Revenues:
	Oil & natural gas sales	$	87,733		$	115,977		$	—		$	203,710
	Other revenues		3			908			—			911
	Total revenues		87,736			116,885			—			204,621
	Costs and expenses:
	Lease operating		3,235			30,120			—			33,355
	Gathering, processing, and transportation		8,557			5,563						14,120
	Pipeline operating		—			489			—			489
	Exploration		140			6			—			146
	Production and ad valorem taxes		2,573			6,011			—			8,584
	Depreciation, depletion, and amortization		25,129			32,550			—			57,679
	Incentive unit compensation expense		1,023			—			—			1,023
	General and administrative		6,999			10,740			—			17,739
	Accretion of asset retirement obligations		130			1,391			—			1,521
	(Gain) loss on commodity derivative instruments		12,716			46,766			—			59,482
	(Gain) loss on sale of properties		(110	)		—			—			(110	)
	Other, net		—			(12	)		—			(12	)
	Total costs and expenses		60,392			133,624			—			194,016
	Operating income (loss)		27,344			(16,739	)		—			10,605
	Other income (expense):
	Interest expense, net		(17,974	)		(16,078	)		—			(34,052	)
	Earnings from equity investments		(2,986	)		—			2,986			—
	Other, net		31			—			—			31
	Total other income (expense)		(20,929	)		(16,078	)		2,986			(34,021	)
	Income (loss) before income taxes		6,415			(32,817	)		2,986			(23,416	)
	Income tax benefit (expense)		(25	)		(75	)		—			(100	)
	Net income (loss)	$	6,390		$	(32,892	)	$	2,986		$	(23,516	)

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Gross Held-to-Maturity Investments	The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of March 31, 2015 (in thousands):
		Amortized
	Investment	Cost
	U.S. Bank Money Market Cash Equivalent	$	137,705
	Less: Outside working interest owners share		(66,442	)
		$	71,263
Minimum Balances Attributable to Net Working Interest	The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):
	30-Jun-15	$	72,450
	30-Jun-16	$	76,590
	31-Dec-16	$	78,660

Background_Organization_and_Ba1

Background, Organization and Basis of Presentation - Additional Information (Detail) (USD $)	3 Months Ended	1 Months Ended
	Mar. 31, 2015	Feb. 28, 2015
	Segment
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments	2
MEMP [Member]
Consolidation And Basis Of Presentation [Line Items]
Net payment made to affiliate for acquisition of oil and natural gas properties		$78,000,000
Net equity deemed contribution (distribution) related to net assets transferred		172,900,000
Net book value of assets transferred to MEMP segment		250,800,000
Cash allocated to limited partners		$77,900,000
Limited Partner [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage	99.90%
General Partner [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage	0.10%
MRD Operating [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage	100.00%

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Accrued capital expenditures	$84,939	$80,350
Accrued lease operating expense	17,996	16,403
Accrued general and administrative expenses	10,098	8,516
Accrued ad valorem and production taxes	10,390	8,870
Accrued interest payable	36,815	24,797
Accrued environmental	1,309	2,092
Accrued current deferred income taxes	51,937	51,929
Other miscellaneous, including operator advances	4,185	6,043
Accrued liabilities	$217,669	$199,000

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	3 Months Ended	1 Months Ended
	Mar. 31, 2015	Feb. 28, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Unrecognized tax benefits	$0
Effective tax rate	-67.50%
Federal statutory income tax rate	35.00%
Percentage of reduction to effective tax rate related to pass-through entities	84.00%
Percentage of reduction to effective tax rate related to non-deductible incentive compensation	10.60%
Percentage of effective tax rate related to state income tax provision, net of federal benefit	8.10%
Deferred tax liabilities	111,790,000		95,017,000
Deferred income tax liabilities, net	28,000,000
MEMP [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred tax liabilities			29,200,000
Deferred income tax benefit		$1,200,000

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Acquisition Related Costs (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Business Acquisition [Line Items]
Acquisition related costs	$2,580	$2,462
General and administrative expense [Member]
Business Acquisition [Line Items]
Acquisition related costs	$2,580	$2,462

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures - Additional Information (Detail) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Mar. 25, 2014	Apr. 17, 2015
Eagle Ford Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Percentage of leasehold interest acquired	30.00%
Subsequent Event [Member] | Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures		$13.50

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Unaudited Pro Forma Results of Operations (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014
Business Combinations [Abstract]
Revenues	$252,019
Net income (loss)	($14,817)

Fair_Value_Measurements_of_Fin2

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (Fair Value, Measurements [Member], USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Assets:
Fair value of derivative asset	$1,022,716	$847,064
Liabilities:
Fair value of derivative liability	91,358	74,928
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	1,022,716	847,064
Liabilities:
Fair value of derivative liability	91,358	74,928
Commodity derivatives [Member]
Assets:
Fair value of derivative asset	1,022,706	845,759
Liabilities:
Fair value of derivative liability	87,809	71,639
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	1,022,706	845,759
Liabilities:
Fair value of derivative liability	87,809	71,639
Interest rate derivatives [Member]
Assets:
Fair value of derivative asset	10	1,305
Liabilities:
Fair value of derivative liability	3,549	3,289
Interest rate derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	10	1,305
Liabilities:
Fair value of derivative liability	$3,549	$3,289

Fair_Value_Measurements_of_Fin3

Fair Value Measurements of Financial Instruments - Additional Information (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	$251,347
Carrying value of properties after impairment charges	3,366,600		3,537,656
MEMP [Member] | East Texas, Wyoming and Colorado [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	251,300	0
Carrying value of properties after impairment charges	$157,600

Risk_Management_and_Derivative2

Risk Management and Derivative Instruments - Additional Information (Detail) (USD $)	1 Months Ended	3 Months Ended
	Feb. 28, 2015	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk		$81,800,000
Effect netting arrangements, counterparty exposure		248,700,000
Net derivative asset		330,500,000
Deferred premiums		1,800,000
Cash collateral received or pledged		0
Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure		113,400,000
MEMP [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk		272,600,000
Effect netting arrangements, counterparty exposure		328,400,000
Net derivative asset		601,000,000
Cash settlement receipt	27,100,000
MRD [Member] | Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure		$66,600,000

Risk_Management_and_Derivative3

Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail)	3 Months Ended
	Mar. 31, 2015
	MMBTU
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,600,000
Weighted-average fixed price	4.15
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	130,000
Weighted-average floor price	4
Weighted-average ceiling price	4.64
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,366,667
Weighted-average fixed price	3.75
Weighted-average deferred premium paid	-0.33
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Call Option [Member] | Written
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,625,000
Weighted-average sold strike price	3.75
Weighted-average deferred premium received	0.08
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,480,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.1
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,061,181
Weighted-average fixed price	4.16
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	350,000
Weighted-average floor price	4.62
Weighted-average ceiling price	5.8
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	80,000
Weighted-average sold strike price	5.25
Weighted-average bought strike price	6.75
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,390,000
Spread	-0.12
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,730,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.12
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	150,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.08
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	210,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.25
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	300,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.09
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	91.67
Average Monthly Volume (Bbls)	45,000
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price	85
Weighted-average ceiling price	101.35
Average Monthly Volume (Bbls)	2,000
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased
Derivative [Line Items]
Weighted-average fixed price	85
Weighted-average deferred premium paid	-3.8
Average Monthly Volume (Bbls)	30,333
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Call Option [Member] | Written
Derivative [Line Items]
Weighted-average sold strike price	85
Weighted-average deferred premium received	0.48
Average Monthly Volume (Bbls)	22,750
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	91.34
Average Monthly Volume (Bbls)	273,864
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price	80
Weighted-average ceiling price	94
Average Monthly Volume (Bbls)	5,000
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread	-7.07
Average Monthly Volume (Bbls)	97,333
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Spread	-9.73
Average Monthly Volume (Bbls)	57,333
Remaining 2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread	-3.25
Average Monthly Volume (Bbls)	40,000
Remaining 2015 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	41.58
Average Monthly Volume (Bbls)	155,000
Remaining 2015 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	42.3
Average Monthly Volume (Bbls)	211,867
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,570,000
Weighted-average fixed price	4.09
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,100,000
Weighted-average floor price	4
Weighted-average ceiling price	4.71
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased
Derivative [Line Items]
Average Monthly Volume (MMBtu)	4,100,000
Weighted-average fixed price	3.75
Weighted-average deferred premium paid	-0.36
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,120,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.1
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,292,442
Weighted-average fixed price	4.22
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,108,333
Spread	-0.05
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,703,333
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.07
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	135,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.07
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	270,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.06
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	84.8
Average Monthly Volume (Bbls)	8,500
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price	80
Weighted-average ceiling price	99.7
Average Monthly Volume (Bbls)	27,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	86.87
Average Monthly Volume (Bbls)	279,813
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread	-9.56
Average Monthly Volume (Bbls)	95,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Spread	-13.35
Average Monthly Volume (Bbls)	55,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread	-4.34
Average Monthly Volume (Bbls)	40,000
2016 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	34.06
Average Monthly Volume (Bbls)	185,658
2016 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	40.36
Average Monthly Volume (Bbls)	158,600
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,770,000
Weighted-average fixed price	4.24
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,050,000
Weighted-average floor price	4
Weighted-average ceiling price	5.06
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,450,000
Weighted-average fixed price	3.75
Weighted-average deferred premium paid	-0.35
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	200,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.08
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,050,067
Weighted-average fixed price	4.14
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	415,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	300,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	-0.05
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	115,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.14
2017 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	84.7
Average Monthly Volume (Bbls)	28,000
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	84.7
Average Monthly Volume (Bbls)	301,600
2017 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	37.55
Average Monthly Volume (Bbls)	43,300
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	4,600,000
Weighted-average fixed price	4.06
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,850,000
Weighted-average fixed price	3.75
Weighted-average deferred premium paid	-0.35
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,760,000
Weighted-average fixed price	4.28
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	115,000
Spread	0.15
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	115,000
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.15
2018 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	84.5
Average Monthly Volume (Bbls)	31,625
2018 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	83.74
Average Monthly Volume (Bbls)	312,000
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,514,583
Weighted-average fixed price	4.43
2019 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	85.52
Average Monthly Volume (Bbls)	160,000

Risk_Management_and_Derivative4

Risk Management and Derivative Instruments - Schedule of Entity's Interest Rate Swap Open Positions (Detail) (MEMP [Member], Interest rate swaps [Member], USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015
Remaining 2015 [Member]
Derivative [Line Items]
Average Monthly Notional	$386,111
Weighted-average fixed rate	1.25%
Floating rate	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	400,000
Weighted-average fixed rate	0.94%
Floating rate	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	400,000
Weighted-average fixed rate	1.61%
Floating rate	1 Month LIBOR
2018 [Member]
Derivative [Line Items]
Average Monthly Notional	$100,000
Weighted-average fixed rate	1.95%
Floating rate	1 Month LIBOR

Risk_Management_and_Derivative5

Risk Management and Derivative Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$357,060	$340,056
Asset Derivatives, Net recorded fair value	578,153	435,369
Liability Derivatives, Net recorded fair value	3,300	3,289
Liability Derivatives, Net recorded fair value	555
Short-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	398,708	378,908
Asset Derivatives, Netting arrangements	-41,648	-38,852
Asset Derivatives, Net recorded fair value	357,060	340,056
Liability Derivatives, Gross fair value	44,948	42,141
Liability Derivatives, Netting arrangements	-41,648	-38,852
Liability Derivatives, Net recorded fair value	3,300	3,289
Short-term derivative instruments [Member] | Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	398,708	378,908
Liability Derivatives, Gross fair value	41,954	38,852
Short-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Liability Derivatives, Gross fair value	2,994	3,289
Long-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	624,008	468,156
Asset Derivatives, Netting arrangements	-45,855	-32,787
Asset Derivatives, Net recorded fair value	578,153	435,369
Liability Derivatives, Gross fair value	46,410	32,787
Liability Derivatives, Netting arrangements	-45,855	-32,787
Liability Derivatives, Net recorded fair value	555
Long-term derivative instruments [Member] | Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	623,998	466,851
Liability Derivatives, Gross fair value	45,855	32,787
Long-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	10	1,305
Liability Derivatives, Gross fair value	$555

Risk_Management_and_Derivative6

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	($253,649)	$59,482
Interest expense, net	38,574	34,052
Commodity contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	-253,649	59,482
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	$2,441	$511

Asset_Retirement_Obligations_S

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$122,531
Liabilities added from acquisitions or drilling	39
Revisions	149
Accretion expense	1,757	1,521
Asset retirement obligations at end of period	$124,476

Restricted_Investments_Restric

Restricted Investments - Restricted Investment Balance (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Schedule Of Investments [Line Items]
Restricted investments	$78,787	$77,361
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	71,263	69,954
BOEM lease bonds [Member]
Schedule Of Investments [Line Items]
Restricted investments	794	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	2,818	2,701
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	3,005	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Schedule Of Investments [Line Items]
Restricted investments	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$100	$100

Long_Term_Debt_Consolidated_De

Long Term Debt - Consolidated Debt Obligations (Detail) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Total long-term debt	$2,498,045		$2,378,413
MRD [Member]
Debt Instrument [Line Items]
Long-term debt	744,000		783,000
MRD [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility	144,000		183,000
MRD [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	600,000	[1]	600,000	[1]
MEMP [Member]
Debt Instrument [Line Items]
Unamortized discounts	-15,945		-16,587
Long-term debt	1,754,045		1,595,413
MEMP [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility	573,000		412,000
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member]
Debt Instrument [Line Items]
Senior Notes	700,000	[2]	700,000	[2]
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Senior Notes	$496,990	[3]	$500,000	[3]
[1]	The estimated fair value of this fixed-rate debt was $564.0 million and $534.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[2]	The estimated fair value of this fixed-rate debt was $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[3]	The estimated fair value of this fixed-rate debt was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Long_Term_Debt_Consolidated_De1

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
MRD [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities	$2,000,000,000
Maturity date	18-Jun-19
MRD [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Maturity date	1-Jul-22
Debt interest rate	5.88%
Estimated fair value of fixed rate debt	564,000,000	534,000,000
MEMP [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities	2,000,000,000
Maturity date	19-Mar-18
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member]
Debt Instrument [Line Items]
Maturity date	1-May-21
Debt interest rate	7.63%
Estimated fair value of fixed rate debt	640,500,000	563,500,000
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Maturity date	1-Aug-22
Debt interest rate	6.88%
Estimated fair value of fixed rate debt	$437,400,000	$380,000,000

Long_Term_Debt_Borrowing_Base_

Long Term Debt - Borrowing Base Credit Facility (Detail) (USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$725,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$1,300,000

Long_Term_Debt_Borrowing_Base_1

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) (USD $)	Mar. 31, 2015
In Billions, unless otherwise specified
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$2
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$2

Long_Term_Debt_MRD_Revolving_C

Long Term Debt - MRD Revolving Credit Facility - Additional Information (Detail) (Subsequent Event [Member], USD $)	Apr. 13, 2015
In Thousands, unless otherwise specified
Subsequent Event [Member]
Debt Instrument [Line Items]
Revolving credit facility borrowing base	$725,000

Long_Term_Debt_Summary_of_Weig

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
MRD [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.87%
MRD [Member] | WildHorse Resources, LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.97%
MRD [Member] | WildHorse Resources second lien [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		6.44%
MEMP [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.90%	1.66%

Long_Term_Debt_Summary_of_Unam

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Unamortized deferred financing costs	$41,931	$44,474
MRD [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	4,060	4,285
MRD [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	12,041	12,455
MEMP [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	5,395	6,468
MEMP [Member] | 2021 Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	12,779	13,308
MEMP [Member] | 2022 Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	$7,656	$7,958

Stockholders_Equity_and_Noncon2

Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Mar. 16, 2015	Dec. 31, 2014	Apr. 30, 2015
Stockholders Equity Note Disclosure [Line Items]
Common stock, shares authorized	600,000,000		600,000,000
Common stock, par value	$0.01		$0.01
Payments for repurchase of common stock	$47,785,000
Subsequent Event [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchase program, authorized amount				50,000,000
MRD [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock		47,800,000
Stock repurchased and retired during period, shares		2,764,887
MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock	28,420,000
MEMP [Member] | Noncontrolling Interest [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock	$28,420,000
Stock repurchased and retired during period, shares	1,909,583

Stockholders_Equity_and_Noncon3

Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Beginning Balance		193,435,414
Ending Balance	190,776,618	193,435,414
Common Stock [Member]
Class of Stock [Line Items]
Shares of common stock repurchased	-2,764,887
Restricted common shares issued (Note 11)	115,302
Restricted common shares forfeited	-9,211

Earnings_per_Share_Summary_of_

Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Detail) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Numerator:
Net income (loss) available to common stockholders	$45,615	$0
Denominator:
Weighted average common shares outstanding	190,705
Basic EPS	$0.24
Diluted EPS	$0.24

Earnings_per_Share_Summary_of_1

Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Parenthetical) (Detail)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015
Earnings Per Share [Abstract]
Incremental shares included in diluted EPS computation	151,123

LongTerm_Incentive_Plans_Summa

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) (Restricted Stock [Member], USD $)	3 Months Ended
	Mar. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common shares outstanding, Number of Shares, Beginning Balance	1,059,211
Granted, Number of Shares	115,302
Forfeited, Number of Shares	-9,211
Restricted common shares outstanding, Number of Shares, Ending Balance	1,165,302
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance	$19
Granted, Weighted-Average Grant Date Fair Value Per Shares	$18.05
Forfeited, Weighted-Average Grant Date Fair Value Per Shares	$19
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance	$18.91
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Shares	157,360
Forfeited, Number of Shares	-12,467
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance	$20.93
Granted, Weighted-Average Grant Date Fair Value Per Shares	$15.45
Forfeited, Weighted-Average Grant Date Fair Value Per Shares	$20.73
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance	$20.31
Restricted common shares outstanding, Number of Units, Beginning Balance	1,093,520
Vested, Number of Units	-78,307
Restricted common shares outstanding, Number of Units, Ending Balance	1,160,106
Vested, Weighted-Average Grant Date Fair Value Per Unit	$19.16

LongTerm_Incentive_Plans_Summa1

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) (Restricted Stock [Member], USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$2.10
Granted, Weighted-Average Grant Date Fair Value Per Shares	$18.05
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$2.40
Granted, Weighted-Average Grant Date Fair Value Per Shares	$15.45

LongTerm_Incentive_Plans_Summa2

Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$14,051	$2,318
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	2,341	1,295
Restricted Stock [Member] | MRD [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$1,486

LongTerm_Incentive_Plans_Addit

Long-Term Incentive Plans - Additional Information (Detail) (Restricted Stock [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$17.70
Unrecognized compensation cost weighted-average period	3 years 1 month 17 days
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$16.30
Unrecognized compensation cost weighted-average period	1 year 11 months 27 days

Incentive_Units_Additional_Inf

Incentive Units - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation expense	$14,051,000	$2,318,000
MRD Holdco LLC [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
The number of incentive units authorized by governing documents	1,000
MRD Holdco LLC [Member] | Exchanged Incentive Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive units granted in an exchange for cancelled predecessor awards	930
Compensation expense	10,200,000
Unrecognized compensation expense	$95,500,000
Remaining expected life	2 years 2 months 1 day
MRD Holdco LLC [Member] | Subsequent Incentive Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Subsequent incentive units	70

Incentive_Units_Fair_Value_of_

Incentive Units - Fair Value of Incentive Units Estimated (Detail)	3 Months Ended
	Mar. 31, 2015
Exchanged Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	30-Mar-15
Dividend yield	0.00%
Expected volatility	27.90%
Risk-free rate	0.61%
Expected life (years)	2 years 2 months 1 day
Subsequent Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	31-Mar-15
Dividend yield	0.00%
Expected volatility	27.90%
Risk-free rate	0.61%
Expected life (years)	2 years 2 months 1 day

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)	1 Months Ended		3 Months Ended	0 Months Ended
In Millions, unless otherwise specified	31-May-14	Nov. 30, 2011	Mar. 31, 2015	Mar. 28, 2014	Mar. 10, 2014	Apr. 14, 2015	Feb. 28, 2014
Related Party Transaction [Line Items]
Commodity usage charge			0.04
Natural gas produced per day		50,000
Fee per MMBTU	0.3
Annual inflationary escalation	3.50%
Price per unit	0.07
Through November 30, 2019
Related Party Transaction [Line Items]
Monthly gas demand quantity			460,000
Payback demand fee			0.03
July 1, 2016 | Minimum
Related Party Transaction [Line Items]
Minimum gas volume commitment			460,000
Through June 30, 2026
Related Party Transaction [Line Items]
Commodity usage charge			0.05
Through June 30, 2026 | Minimum
Related Party Transaction [Line Items]
Minimum gas volume commitment			460,000
June 30, 2026, and thereafter
Related Party Transaction [Line Items]
Commodity usage charge			0.05
June 30, 2026, and thereafter | Minimum
Related Party Transaction [Line Items]
Minimum gas volume commitment			345,000
First Plant [Member] | Until Second Processing Plant Operational
Related Party Transaction [Line Items]
Commodity usage charge			0.02
First Plant [Member] | Until Second Processing Plant Operational | Minimum
Related Party Transaction [Line Items]
Minimum gas volume commitment			115,000
Second Plant [Member] | Through November 30, 2019
Related Party Transaction [Line Items]
Commodity usage charge			0.02
Second Plant [Member] | Through November 30, 2019 | Minimum
Related Party Transaction [Line Items]
Minimum gas volume commitment			345,000
Natural Gas Partners [Member]
Related Party Transaction [Line Items]
Cash received				$3.30
NGPCIF [Member]
Related Party Transaction [Line Items]
Business acquisition common control purchase price							63.4
Date of acquisition common control			28-Feb-14
Cretic Energy Services, LLC [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses			0.6
BlueStone Natural Resources Holdings, LLC [Member]
Related Party Transaction [Line Items]
Total cash consideration					1.2
Amount of gain over the book value					0.5
Gain recognized as contribution					0.5
WHR Management Company [Member]
Related Party Transaction [Line Items]
Management fee per month			1
WildHorse Resources, LLC [Member] | Subsequent Event [Member]
Related Party Transaction [Line Items]
Primary term of gas processing agreement						15 years
WildHorse Resources, LLC [Member] | First Plant [Member] | Subsequent Event [Member]
Related Party Transaction [Line Items]
Minimum annual processing fee						18.3
WildHorse Resources, LLC [Member] | Second Plant [Member] | Subsequent Event [Member]
Related Party Transaction [Line Items]
Minimum annual processing fee						55
Classic [Member]
Related Party Transaction [Line Items]
Water disposal agreement period	3 years
Water disposal fee per barrel	1.1

Related_Party_Transactions_Sch

Related Party Transactions - Schedule of Net Assets Recorded (Detail) (NGPCIF [Member], USD $)	Feb. 28, 2014
In Thousands, unless otherwise specified
NGPCIF [Member]
Related Party Transaction [Line Items]
Accounts receivable	$2,274
Oil and natural gas properties, net	40,056
Accrued liabilities	-297
Asset retirement obligations	-277
Net assets	$41,756

Business_Segment_Data_Addition

Business Segment Data - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2015
	Segment
Segment Reporting [Abstract]
Number of reportable business segments	2

Business_Segment_Data_Summary_

Business Segment Data - Summary of Selected Business Segment Information (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total revenues	$179,841	$204,621
Adjusted EBITDA	173,186	123,796
Segment assets	4,574,222		4,593,547
Total cash expenditures for additions to long-lived assets	166,246	307,231
Operating Segments [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	173,262	126,798
Operating Segments [Member] | MRD [Member]
Segment Reporting Information [Line Items]
Total revenues	87,023	87,736
Adjusted EBITDA	86,830	64,752
Segment assets	1,535,233		1,413,768
Total cash expenditures for additions to long-lived assets	88,566	75,258
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Total revenues	92,818	116,885
Adjusted EBITDA	86,432	62,046
Segment assets	3,051,190		3,189,760
Total cash expenditures for additions to long-lived assets	77,680	231,973
Other, Adjustments & Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	-76	-3,002
Segment assets	($12,201)		($9,981)

Business_Segment_Data_Summary_1

Business Segment Data - Summary of Selected Business Segment Information (Parenthetical) (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Segment Reporting Information [Line Items]
Cash distributions from MEMP	$76	$3,002
Other, Adjustments & Eliminations [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Cash distributions from MEMP	$100	$3,000

Business_Segment_Data_Schedule

Business Segment Data - Schedule of Calculation of Reportable Segment's Adjusted EBITDA (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Segment Reporting Information [Line Items]
Net income (loss)	($112,149)	($23,516)
Interest expense, net	38,574	34,052
Income tax expense (benefit)	45,188	100
DD&A	91,798	57,679
Impairment of proved oil and natural gas properties	251,347
Accretion of AROs	1,757	1,521
(Gain) loss on commodity derivative instruments	-253,649	59,482
Cash settlements received (paid) on expired commodity derivative instruments	92,873	-13,190
(Gain) loss on sale of properties		-110
Transaction related costs	2,580	2,462
Compensation expense	14,051	2,318
Exploration costs	816	146
Provision for environmental remediation		2,852
Cash distributions from MEMP	76	3,002
Adjusted EBITDA	173,186	123,796
Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income (loss)	-112,287	-26,502
Interest expense, net	38,574	34,052
Income tax expense (benefit)	45,188	100
DD&A	91,798	57,679
Impairment of proved oil and natural gas properties	251,347
Accretion of AROs	1,757	1,521
(Gain) loss on commodity derivative instruments	-253,649	59,482
Cash settlements received (paid) on expired commodity derivative instruments	92,873	-13,190
(Gain) loss on sale of properties		-110
Transaction related costs	2,580	2,462
Compensation expense	14,051	2,318
Exploration costs	816	146
Provision for environmental remediation		2,852
Non-cash equity (income) loss from MEMP	138	2,986
Cash distributions from MEMP	76	3,002
Adjusted EBITDA	173,262	126,798
Operating Segments [Member] | MRD [Member]
Segment Reporting Information [Line Items]
Net income (loss)	50,371	6,390
Interest expense, net	9,756	17,974
Income tax expense (benefit)	47,558	25
DD&A	40,532	25,129
Accretion of AROs	123	130
(Gain) loss on commodity derivative instruments	-108,190	12,716
Cash settlements received (paid) on expired commodity derivative instruments	32,749	-5,221
(Gain) loss on sale of properties		-110
Transaction related costs	1,281	568
Compensation expense	11,710	1,023
Exploration costs	726	140
Non-cash equity (income) loss from MEMP	138	2,986
Cash distributions from MEMP	76	3,002
Adjusted EBITDA	86,830	64,752
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Net income (loss)	-162,658	-32,892
Interest expense, net	28,818	16,078
Income tax expense (benefit)	-2,370	75
DD&A	51,266	32,550
Impairment of proved oil and natural gas properties	251,347
Accretion of AROs	1,634	1,391
(Gain) loss on commodity derivative instruments	-145,459	46,766
Cash settlements received (paid) on expired commodity derivative instruments	60,124	-7,969
Transaction related costs	1,299	1,894
Compensation expense	2,341	1,295
Exploration costs	90	6
Provision for environmental remediation		2,852
Adjusted EBITDA	$86,432	$62,046

Business_Segment_Data_Reconcil

Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA	$173,186	$123,796
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net	-38,574	-34,052
Income tax benefit (expense)	-45,188	-100
DD&A	-91,798	-57,679
Impairment of proved oil and natural gas properties	-251,347
Accretion of AROs	-1,757	-1,521
Gains (losses) on commodity derivative instruments	253,649	-59,482
Cash settlements paid (received) on expired commodity derivative instruments	-92,873	13,190
Gain (loss) on sale of properties		110
Transaction related costs	-2,580	-2,462
Incentive-based compensation expense	-14,051	-2,318
Exploration costs	-816	-146
Provision for environmental remediation		-2,852
Cash distributions from MEMP	-76	-3,002
Net income (loss)	-112,149	-23,516
Reportable Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA	$173,262	$126,798

Business_Segment_Data_Schedule1

Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues:
Oil & natural gas sales	$178,972	$203,710
Other revenues	869	911
Total revenues	179,841	204,621
Costs and expenses:
Lease operating	45,700	33,355
Gathering, processing, and transportation	22,983	14,120
Pipeline operating	446	489
Exploration	816	146
Production and ad valorem taxes	9,430	8,584
Depreciation, depletion, and amortization	91,798	57,679
Impairment of proved oil and natural gas properties	251,347
Incentive unit compensation expense	10,224	1,023
General and administrative	27,487	17,739
Accretion of asset retirement obligations	1,757	1,521
(Gain) loss on commodity derivative instruments	-253,649	59,482
(Gain) loss on sale of properties		-110
Other, net		-12
Total costs and expenses	208,339	194,016
Operating income (loss)	-28,498	10,605
Other income (expense):
Interest expense, net	-38,574	-34,052
Other, net	111	31
Total other income (expense)	-38,463	-34,021
Income (loss) before income taxes	-66,961	-23,416
Income tax benefit (expense)	-45,188	-100
Net income (loss)	-112,149	-23,516
Operating Segments [Member]
Costs and expenses:
Exploration	816	146
Depreciation, depletion, and amortization	91,798	57,679
Impairment of proved oil and natural gas properties	251,347
Accretion of asset retirement obligations	1,757	1,521
(Gain) loss on commodity derivative instruments	-253,649	59,482
(Gain) loss on sale of properties		-110
Other income (expense):
Interest expense, net	-38,574	-34,052
Income tax benefit (expense)	-45,188	-100
Other, Adjustments & Eliminations [Member]
Other income (expense):
Earnings from equity investments	138	2,986
Total other income (expense)	138	2,986
Income (loss) before income taxes	138	2,986
Net income (loss)	138	2,986
MRD [Member] | Operating Segments [Member]
Revenues:
Oil & natural gas sales	87,023	87,733
Other revenues		3
Total revenues	87,023	87,736
Costs and expenses:
Lease operating	5,222	3,235
Gathering, processing, and transportation	14,763	8,557
Exploration	726	140
Production and ad valorem taxes	2,775	2,573
Depreciation, depletion, and amortization	40,532	25,129
Incentive unit compensation expense	10,224	1,023
General and administrative	12,976	6,999
Accretion of asset retirement obligations	123	130
(Gain) loss on commodity derivative instruments	-108,190	12,716
(Gain) loss on sale of properties		-110
Total costs and expenses	-20,849	60,392
Operating income (loss)	107,872	27,344
Other income (expense):
Interest expense, net	-9,756	-17,974
Earnings from equity investments	-138	-2,986
Other, net	-49	31
Total other income (expense)	-9,943	-20,929
Income (loss) before income taxes	97,929	6,415
Income tax benefit (expense)	-47,558	-25
Net income (loss)	50,371	6,390
MEMP [Member] | Operating Segments [Member]
Revenues:
Oil & natural gas sales	91,949	115,977
Other revenues	869	908
Total revenues	92,818	116,885
Costs and expenses:
Lease operating	40,478	30,120
Gathering, processing, and transportation	8,220	5,563
Pipeline operating	446	489
Exploration	90	6
Production and ad valorem taxes	6,655	6,011
Depreciation, depletion, and amortization	51,266	32,550
Impairment of proved oil and natural gas properties	251,347
General and administrative	14,511	10,740
Accretion of asset retirement obligations	1,634	1,391
(Gain) loss on commodity derivative instruments	-145,459	46,766
Other, net		-12
Total costs and expenses	229,188	133,624
Operating income (loss)	-136,370	-16,739
Other income (expense):
Interest expense, net	-28,818	-16,078
Other, net	160
Total other income (expense)	-28,658	-16,078
Income (loss) before income taxes	-165,028	-32,817
Income tax benefit (expense)	2,370	-75
Net income (loss)	($162,658)	($32,892)

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Commitments And Contingencies (Additional Textual) [Abstract]
Environmental reserves liability	$1.30	$2.10
Maximum remaining obligation	$7.40

Commitments_and_Contingencies_2

Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Held-to-maturity Securities [Abstract]
Less: Outside working interest owners share, Amortized Cost	($66,442)
Restricted investments	78,787	77,361
BOEM platform abandonment [Member]
Held-to-maturity Securities [Abstract]
Restricted investments	71,263	69,954
Money Market Funds [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$137,705

Commitments_and_Contingencies_3

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) (USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
June 30, 2015 [Member]
Asset retirement obligations
Minimum balances attributable to net working interest	$72,450
June 30, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to net working interest	76,590
December 31, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to net working interest	$78,660