Range Louisiana Operating S-417 Apr 15Registration of securities issued in business combination transactionsFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	12 Months Ended
Document and Entity Information	Dec. 31, 2014
Document And Entity Information [Abstract]
Document Type	S-4
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Trading Symbol	MRD
Entity Registrant Name	MEMORIAL RESOURCE DEVELOPMENT CORP.
Entity Central Index Key	1599222
Entity Filer Category	Non-accelerated Filer

CONSOLIDATED_AND_COMBINED_BALA

CONSOLIDATED AND COMBINED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$5,958	$77,721
Restricted cash		35,000
Accounts receivable:
Oil and natural gas sales	82,263	68,764
Joint interest owners and other	49,313	19,958
Affiliates		4,652
Short-term derivative instruments	340,056	9,289
Prepaid expenses and other current assets	28,027	19,513
Total current assets	505,617	234,897
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	4,844,529	3,037,298
Other	33,815	10,331
Accumulated depreciation, depletion and impairment	-1,340,688	-627,925
Property and equipment, net	3,537,656	2,419,704
Long-term derivative instruments	435,369	48,616
Restricted investments	77,361	73,385
Restricted cash	260	15,506
Other long-term assets	37,284	37,053
Total assets	4,593,547	2,829,161
Current liabilities:
Accounts payable	25,772	20,734
Accounts payable - affiliates	624	1,975
Revenues payable	57,352	56,091
Accrued liabilities	199,000	98,130
Short-term derivative instruments	3,289	9,711
Total current liabilities	286,037	186,641
Noncurrent liabilities:
Asset retirement obligations	122,531	111,679
Long-term derivative instruments		6,080
Deferred tax liabilities	95,017	3,106
Other long-term liabilities	8,585	306
Total liabilities	2,890,583	1,971,029
Commitments and contingencies (Note 16)
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; 193,435,414 shares issued and outstanding at December 31, 2014; no shares authorized, issued or outstanding at December 31, 2013	1,935
Additional paid-in capital	1,367,346
Accumulated earnings (deficit)	-786,871
Total stockholders' equity	582,410
Members' equity:
Members		237,186
Previous owners (Note 1)		40,331
Total members' equity		277,517
Noncontrolling interests	1,120,554	580,615
Total equity	1,702,964	858,132
Total liabilities and equity	4,593,547	2,829,161
MRD [Member]
Noncurrent liabilities:
Long-term debt	783,000	871,150
MEMP [Member]
Noncurrent liabilities:
Long-term debt	$1,595,413	$792,067

CONSOLIDATED_AND_COMBINED_BALA1

CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
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	0
Common stock, shares issued	193,435,414	0
Common stock, shares outstanding	193,435,414	0

STATEMENTS_OF_CONSOLIDATED_AND

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil & natural gas sales	$894,967	$571,948	$393,631
Other revenues	4,378	3,075	3,237
Total revenues	899,345	575,023	396,868
Costs and expenses:
Lease operating	161,303	113,640	103,754
Pipeline operating	2,068	1,835	2,114
Exploration	16,603	2,356	9,800
Production and ad valorem taxes	45,751	27,146	23,624
Depreciation, depletion, and amortization	314,193	184,717	138,672
Impairment of proved oil and natural gas properties	432,116	6,600	28,871
Incentive unit compensation expense	943,949	43,279	9,510
General and administrative	87,673	82,079	59,677
Accretion of asset retirement obligations	6,306	5,581	5,009
(Gain) loss on commodity derivative instruments	-749,988	-29,294	-34,905
(Gain) loss on sale of properties	3,057	-85,621	-9,761
Other, net	-12	649	502
Total costs and expenses	1,263,019	352,967	336,867
Operating income (loss)	-363,674	222,056	60,001
Other income (expense):
Interest expense, net	-133,833	-69,250	-33,238
Loss on extinguishment of debt	-37,248	0	0
Amortization of investment premium	0	0	-194
Other, net	-337	145	535
Total other income (expense)	-171,418	-69,105	-32,897
Income (loss) before income taxes	-535,092	152,951	27,104
Income tax benefit (expense)	-100,971	-1,619	-107
Net income (loss)	-636,063	151,332	26,997
Net income (loss) attributable to noncontrolling interest	126,788	49,830	-2,701
Net income (loss) attributable to Memorial Resource Development Corp.	-762,851	101,502	29,698
Net (income) loss allocated to members	-20,305	-90,712	7,620
Net (income) loss allocated to previous owners	-1,425	-10,790	-37,318
Net income (loss) available to common stockholders	($784,581)	$0	$0
Earnings per common share: (Note 10)
Basic	($4.08)	$0	$0
Diluted	($4.08)	$0	$0
Weighted average common and common equivalent shares outstanding:
Basic	192,498	0	0
Diluted	192,498	0	0

STATEMENTS_OF_CONSOLIDATED_AND1

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	($636,063)	$151,332	$26,997
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	314,193	184,717	138,672
Impairment of proved oil and natural gas properties	432,116	6,600	28,871
(Gain) loss on derivatives	-749,843	-29,533	-29,323
Cash settlements (paid) received on derivative instruments	20,559	30,403	72,045
Cash settlements on terminated derivatives	5,326	0	0
Premiums paid for derivatives	-6,065	0	-411
Loss on extinguishment of debt	30,248	0	0
Amortization of deferred financing costs	7,436	8,343	3,584
Accretion of senior notes net discount	2,501	554	0
Amortization of investment premium	0	0	194
Accretion of asset retirement obligations	6,306	5,581	5,009
Amortization of equity awards	10,678	3,557	1,423
(Gain) loss on sale of properties	3,057	-85,621	-9,761
Non-cash compensation expense	916,218	1,057	0
Exploration costs	14,953	181	6,980
Deferred income tax expense (benefit)	100,230	76	-312
Changes in operating assets and liabilities:
Accounts receivable	-17,635	-15,758	-7,382
Prepaid expenses and other assets	-7,424	-2,986	-1,574
Payables and accrued liabilities	21,208	19,320	5,392
Other	8,272	0	0
Net cash provided by operating activities	476,271	277,823	240,404
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	-1,177,670	-105,762	-360,678
Additions to oil and gas properties	-674,396	-360,015	-273,334
Additions to other property and equipment	-17,067	-2,670	-2,674
Additions to restricted investments	-3,976	-5,361	-4,599
Deposits for property acquisitions	-215	0	0
Decrease (increase) in restricted cash	49,946	-49,347	-3
Proceeds from the sale of oil and natural gas properties	6,700	155,712	34,521
Other	-301	0	29
Net cash used in investing activities	-1,816,979	-367,443	-606,738
Cash flows from financing activities:
Advances on revolving credit facilities	2,746,800	1,132,755	619,450
Payments on revolving credit facilities	-2,457,900	-1,766,037	-251,569
Proceeds from the issuances of senior notes	1,092,425	1,031,563	0
Redemption of senior notes	-351,808	0	0
Borrowings under second lien credit facility	0	325,000	0
Redemption of second lien credit facility	-328,282	0	0
Deferred financing costs	-30,334	-41,175	-3,501
Proceeds from changes in ownership interests in MEMP	0	135,012	0
Repurchased shares under repurchase program	-161	0	0
Restricted MEMP units returned to plan	-1,012	0	0
Purchase of additional interests in consolidated subsidiaries	-3,292	-15,135	0
Contributions from previous owners	0	1,214	44,072
Distributions to the Funds	0	-732,362	0
Distributions to noncontrolling interests	-149,084	-78,083	-15,208
Distributions made by previous owners	0	-4,005	-28,772
Cash retained by previous owners	0	-7,909	0
Other	320	455	0
Net cash provided by financing activities	1,268,945	117,950	361,761
Net change in cash and cash equivalents	-71,763	28,330	-4,573
Cash and cash equivalents, beginning of period	77,721	49,391	53,964
Cash and cash equivalents, end of period	5,958	77,721	49,391
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties	1,165	2,013	45,158
Distribution to NGP affiliates related to purchase of assets	-66,693	-355,494	-242,174
Distribution to NGP affiliates related to sale of assets, net of cash received	-32,770	0	0
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco	-59,803	0	0
MRD [Member]
Cash flows from financing activities:
Proceeds from public offering	408,500	0	0
Costs incurred in conjunction with initial public offering	-28,373	0	0
MEMP [Member]
Cash flows from financing activities:
Proceeds from public offering	553,288	511,204	202,573
Costs incurred in conjunction with initial public offering	-12,510	-21,066	-8,268
Repurchased shares under repurchase program	($11,531)	$0	$0

STATEMENTS_OF_CONSOLIDATED_AND2

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY (USD $)	Total	MRD [Member]	MEMP [Member]	Member Equity [Member]	Member Equity [Member]	Member Equity [Member]	Previous Owners [Member]	Previous Owners [Member]	Previous Owners [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member]	Common Stock [Member]	Common Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]	Accumulated earnings (deficit) [Member]	Accumulated earnings (deficit) [Member]	Accumulated earnings (deficit) [Member]
In Thousands					MRD [Member]	MEMP [Member]	Member Equity [Member]	Member Equity [Member]	Member Equity [Member]		MRD [Member]	MEMP [Member]		MRD [Member]	MEMP [Member]		MRD [Member]	MEMP [Member]		MRD [Member]	MEMP [Member]
								MRD [Member]	MEMP [Member]
Members' equity, beginning balance at Dec. 31, 2011				$853,436			$261,340
Noncontrolling interests, beginning balance at Dec. 31, 2011										161,588
Total equity, beginning balance at Dec. 31, 2011	1,276,364
Net income (loss)	26,997			-7,620			37,318			-2,701
Contributions	44,072			0			44,072			0
Contribution of oil and gas properties from NGP affiliate	6,893			0			6,893			0
Net proceeds from MEMP public equity Offering	194,134			0			0			194,134
Distributions	-44,027			0			-28,772			-15,255
Net book value of net assets acquired from affiliates	0			52,217			-93,696			41,479
Amortization of MEMP equity awards	1,423			0			0			1,423
Noncontrolling interest's share of net book value in excess of consideration received from sale of assets to MEMP	0			727			0			-727
Contribution related to sale of assets to NGP affiliate	47,171			6,291			40,138			742
Net book value of assets acquired by NGP affiliate	-34,506			-579			-33,859			-68
Distribution to affiliate in connection with acquisition of assets	-242,174			-134,964			0			-107,210
Impact of equity transactions of MEMP	0			41,930			0			-41,930
Other	362			176			-1			187
Members' equity, ending balance at Dec. 31, 2012				811,614			233,433
Noncontrolling interests, ending balance at Dec. 31, 2012										231,662
Total equity, ending balance at Dec. 31, 2012	1,276,709
Net income (loss)	151,332			90,712			10,790			49,830
Contributions	1,214			0			1,214			0
Net proceeds from MEMP public equity Offering	490,138			0			0			490,138
Sale of MEMP common units	135,012			60,701			0			74,311
Distributions	-814,450			-732,362			-4,005			-78,083
Net book value of net assets acquired from affiliates	0			50,751			-181,556			130,805
Amortization of MEMP equity awards	3,558			0			0			3,558
Noncontrolling interest's share of cash consideration received in excess of the net book value sold to MEMP	0			-24			0			24
Distribution to affiliate in connection with acquisition of assets	-351,235			-98,180			0			-253,055
Purchase of noncontrolling interests	-15,135			-303			0			-14,832
Impact of equity transactions of MEMP	0			54,183			0			-54,183
Other	-1,765			94			-2,299			440
Net assets retained by previous owners	-17,246			0			-17,246			0
Members' equity, ending balance at Dec. 31, 2013	277,517			237,186			40,331
Noncontrolling interests, ending balance at Dec. 31, 2013	580,615									580,615
Total equity, ending balance at Dec. 31, 2013	858,132
Total stockholders equity, beginning balance at Dec. 31, 2013													0			0			0
Net income (loss)	-636,063			20,305			1,425			126,788			0			0			-784,581
Issuance of shares in connection with restructuring transactions (see Note 1)	914,862			0			0			0			1,710			913,152			0
Issuance of shares in connection with initial public offering (see Note 1)	380,177			0			0			0			215			379,962			0
Tax related effects in connection with restructuring transactions and initial public offering	-43,251			0			0			0			0			-43,251			0
Share repurchase		-2,215	-12,903		0	0		0	0		0	-12,903		-1	0		0	0		-2,214	0
Restricted stock awards	0			0			0			0			11			-11			0
Amortization of restricted stock awards	2,804			0			0			0			0			2,804			0
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12)	111,866			0			0			0			0			111,866			0
Net proceeds from MEMP public equity Offering	540,698			0			0			540,698			0			0			0
Distributions	-149,084			0			0			-149,084			0			0			0
Net book value of net assets acquired from affiliates	3,303			45,059			-41,756			0			0			0			0
Amortization of MEMP equity awards	7,874			0			0			7,874			0			0			0
Contribution related to sale of assets to NGP affiliate	1,165			1,165			0			0			0			0			0
Net book value of assets sold to NGP affiliate	-621			-621			0			0			0			0			0
Distribution to affiliate in connection with acquisition of assets	-66,693			-66,693			0			0			0			0			0
Purchase of noncontrolling interests	-3,292			0			0			-411			0			-2,881			0
Distribution of net assets to MRD Holdco	-93,084			-123,078			0			29,994			0			0			0
Distribution of shares received in connection with restructuring transactions to MRD Holdco	-110,510			-110,510			0			0			0			0			0
Net equity deemed contribution (distribution) related to net assets transferred to MEMP	0			-2,659			0			-2,668			0			5,327			0
Other	811			-154			0			663			0			378			-76
MEMP restricted units repurchased	-1,012			0			0			-1,012			0			0			0
Members' equity, ending balance at Dec. 31, 2014				0			0
Total stockholders equity, ending balance at Dec. 31, 2014	582,410												1,935			1,367,346			-786,871
Total equity, ending balance at Dec. 31, 2014	1,702,964
Noncontrolling interests, ending balance at Dec. 31, 2014	$1,120,554									$1,120,554

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. 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.
	The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering.
	Initial Public Offering and Restructuring Transactions
	On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering:
	—	The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC;
	—	WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015;
	—	Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014;
	—	MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources;
	—	We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco;
	—	We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes;
	—	Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources;
	—	We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources;
	—	We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes;
	—	Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption;
	—	MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating;
	—	MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014;
	—	We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and
	—	MRD LLC merged into MRD Operating.
	Previous Owners
	References to “the previous owners” for accounting and financial reporting purposes refer collectively to:
	—	Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions in October 2013 from certain affiliates of NGP. In October 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds.
	—	A 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 the 2010 Petrohawk and Clayton Williams acquisitions, 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 audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) 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.
	All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
	We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows:
	—	MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.
	—	MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries.
	Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes:
	—	acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013;
	—	acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013;
	—	acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013;
	—	acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013;
	—	acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and
	—	acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	MEMORIAL RESOURCE DEVELOPMENT CORP.
	NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Note 2. Summary of Significant Accounting Policies
	Use of Estimates
	The preparation of 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 and incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
	Principles of Consolidation and Combination
	Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year.
	Cash and Cash Equivalents
	Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.
	Book Overdrafts
	Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.
	Concentrations of Credit Risk
	Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments.
	Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2014 and 2013, respectively.
	If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.
	Oil and Natural Gas Properties
	Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.
	As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.
	On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.
	There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012.
	Oil and Gas Reserves
	The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2014. MEMP engaged NSAI and Ryder Scott Company, L.P. to audit MEMP’s internally prepared reserves estimates for all of MEMP’s proved reserves (by volume) at December 31, 2014.
	Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
	Other Property & Equipment
	Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years.
	Asset Retirement Obligations
	An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.
	Impairments
	Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. 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. Impairment expense for the years ended December 31, 2014, 2013, and 2012 was approximately $432.1 million, $6.6 million, $28.9 million, respectively. See Note 4 for further discussion on impairments.
	Restricted Investments
	Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.
	Debt Issuance Costs
	These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013, and 2012 was approximately $7.4 million, $8.3 million and $3.6 million, respectively.
	Revenue Recognition
	Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2014 or 2013.
	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:
		Years Ending December 31,
		2014				2013				2012
	Consolidated & Combined:
	Energy Transfer Equity, L.P. and subsidiaries		33	%			35	%			13	%

	MRD Segment:
	Energy Transfer Equity, L.P. and subsidiaries		73	%			77	%			39	%
	Sunoco, Inc. (1)	n/a				n/a					15	%
	Dominion Gas Ventures LP	n/a				n/a					15	%

	MEMP Segment:
	Sinclair Oil & Gas Company		12	%		n/a				n/a
	Phillips 66 (2)		13	%			15	%			13	%
	ConocoPhillips	n/a				n/a					14	%

	-1	Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012.
	-2	Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.
	Derivative Instruments
	Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.
	Capitalized Interest
	We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we capitalized $7.3 million of interest. We did not capitalize any interest in 2013 or 2012.
	Income Tax
	Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal 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 Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
	We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than 50% chance of being realized.
	The evaluation of uncertain tax positions is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.
The Company has no liability for unrecognized tax benefits as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2014. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.
In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders.
Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates. See Note 15 for additional information.
Earnings Per Share
Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information.
Incentive Based Compensation Arrangements
The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest.
Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.
In connection with the restructuring transactions, the MRD LLC 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. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period.
See Notes 11 and 12 for further information.
Accrued Liabilities
Current accrued liabilities consisted of the following at the dates indicated (in thousands):

	December 31,
	2014				2013
Accrued capital expenditures	$	80,350			$	48,579
Accrued lease operating expense		16,403				13,240
Accrued general and administrative expenses		8,516				14,485
Accrued ad valorem and production taxes		8,870				3,541
Accrued interest payable		24,797				11,934
Accrued environmental		2,092				577
Accrued current deferred income taxes		51,929				382
Other miscellaneous, including operator advances		6,043				5,392
	$	199,000			$	98,130
Supplemental Cash Flow Information
Supplemental cash flow for the periods presented (in thousands):
	For Year Ended December 31,
	2014				2013				2012
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	130,732			$	61,140			$	23,525
Income tax paid		838				168				22
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities		31,771				41,017				17,158
Assumptions of asset retirement obligations related to properties acquired or drilled		5,420				4,227				7,962
Contribution of oil and gas properties from NGP affiliate		—				—				6,893
Accrued distribution to NGP affiliates related to Cinco Group acquisitions		—				4,352				—
Contribution related to sale of assets to NGP affiliate - restricted cash		—				—				2,013
Accrued equity offering costs		—				—				171
Distributions to noncontrolling interests		—				—				47
Repurchase of equity under repurchase program		3,425				—				—
Accounts receivable related to acquisitions		9,569				—				—

New Accounting Pronouncements
Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures.
Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015.
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 of 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	12 Months Ended
Acquisitions and Divestitures	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures
	The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we, our predecessor, and the previous owners conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through equity offerings, capital contributions and borrowings under credit facilities.
	The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include 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.
	MEMP has consummated several common control acquisitions since completing its initial public offering in December 2011, as further discussed in Note 13, from certain affiliates of NGP. These acquisitions were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost.
	Acquisition-related costs
	Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):
	For the Year Ended December 31,
	2014				2013				2012
	$	6,668			$	8,313			$	4,538
	2014 Acquisitions
	On December 30, 2014, MRD acquired certain oil and natural gas producing properties from third parties in the Terryville Complex for approximately $71.9 million, including estimated customary post-closing adjustments (the “Louisiana Acquisition”).
	During the fourth quarter 2014, MRD acquired incremental interests in certain oil and gas properties and leases in the Terryville Complex from third parties in four separate transactions for an aggregate purchase price of approximately $24.0 million.
	On July 1, 2014, MEMP consummated a transaction to acquire certain oil and natural gas liquids properties from a third party in Wyoming for an aggregate purchase price of approximately $906.1 million, including estimated post-closing adjustments (the “Wyoming Acquisition”). Revenues of $72.0 million were recorded in the statement of operations generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date.
	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 for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold. During the year ended December 31, 2014, revenues of approximately $36.5 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and MEMP generated earnings of approximately $16.3 million.
	The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition dates (in thousands):
		MRD				MEMP				MEMP
		Louisiana				Eagle Ford				Wyoming
		Acquisition				Acquisition				Acquisition
	Oil and gas properties	$	72,141			$	168,606			$	930,168
	Asset retirement obligations		(271	)			(285	)			(3,980	)
	Revenue Payable		—				—				(375	)
	Accrued liabilities		—				(250	)			(19,693	)
	Total identifiable net assets	$	71,870			$	168,071			$	906,120

	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the 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 Year Ended December 31,
		2014				2013
		(In thousands, except per share amounts)
	Revenues	$	990,544			$	761,443
	Net income (loss)		(602,044	)			257,839
	Basic earnings per share	$	(4.08	)		$	—
	Diluted earnings per share	$	(4.08	)		$	—
	2014 Divestitures
	On May 9, 2014, MRD LLC sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for approximately $7.6 million and recorded a loss of $3.2 million.
	2013 Acquisitions
	On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million.
	MEMP closed two separate transactions during 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013.
		Louisiana				East Texas				Rockies
		Acquisition				Acquisition				Acquisition
	Oil and gas properties	$	68,887			$	9,974			$	20,744
	Asset retirement obligation		(1,789	)			(78	)			(1,163	)
	Accrued liabilities		-				-				(118	)
	Total identifiable net assets	$	67,098			$	9,896			$	19,463
	During 2013, Propel Energy acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from third parties in three separate transactions for an aggregate purchase price of approximately $9.3 million.
	2013 Divestitures
	On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum purchase price of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. During 2013, Tanos also sold certain non-operated oil and gas properties for $2.9 million and recorded a gain of $1.4 million.
	On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013.
	During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $89.5 million. The transaction closed on July 31, 2013.
	2012 Acquisitions
	On May 1, 2012, MEMP and WildHorse jointly acquired operating and non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller (“Undisclosed Seller Acquisition”) for a final net purchase price of approximately $112.1 million. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. During the year ended December 31, 2012, approximately $22.1 million of revenue and $9.2 million of earnings were recorded in the statement of operations related to the Undisclosed Seller Acquisition subsequent to the closing date.


	On September 28, 2012, MEMP acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation (“Goodrich Acquisition”) for a final net purchase price of $90.4 million after customary post-closing adjustments. The effective date of this transaction was July 1, 2012. This transaction was financed with borrowings under MEMP’s revolving credit facility. These properties are located in the East Henderson field of Rusk County, Texas. During the year ended December 31, 2012, approximately $4.6 million of revenue and $2.0 million of earnings were recorded in the statement of operations related to the Goodrich Acquisition subsequent to the closing date.
	Collectively, the previous owners consummated multiple acquisitions during 2012 by acquiring operating and non-operating interests in certain oil and natural gas properties primarily located in various Texas and New Mexico counties for an aggregate adjusted purchase price of $147.9 million, the largest of which was completed in July by Stanolind. In July 2012, Stanolind completed an acquisition of working interests, royalty interests and net revenue interests (the “Menemsha Acquisition”) located in various counties in Texas for a final net purchase price of $74.7 million. During the year ended December 31, 2012, approximately $4.9 million of revenue and $0.9 million of earnings were recorded in the statement of operations related to the Menemsha Acquisition subsequent to the closing date.
	The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands).

		Undisclosed Seller				Goodrich				Menemsha			Other
		Acquisition				Acquisition				Acquisition			Acquisitions
	Oil and gas properties	$	115,633			$	91,187			$	75,114		$	77,764
	Prepaid expenses and other current assets		—				425				—			—
	Revenues payable		(1,602	)			(875	)			—			—
	Asset retirement obligation		(1,592	)			(161	)			(408	)		(4,558	)
	Accrued liabilities		(297	)			(153	)			—			—
	Total identifiable net assets	$	112,142			$	90,423			$	74,706		$	73,206
The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from our historical combined statements of operations 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 acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
Revenue	$	431,060
Net income		40,940
During 2012, we also acquired certain interests in oil and gas properties through several individually immaterial acquisitions for an aggregate purchase price of $10.2 million.
2012 Divestitures
During 2012, certain of our subsidiaries sold certain interests in oil and gas properties for an aggregate $3.3 million. Losses of approximately $0.1 million were recognized related to these divestures.
On July 11, 2012, the previous owners completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. On September 18, 2012, the previous owners completed the sale of a portion of its oil and gas assets located in Ector County, Texas to a third party for $4.7 million and recognized a gain of approximately $2.2 million.
The majority of the proceeds generated from these sales were used to acquire operating and non-operating interests in certain oil and natural gas properties located primarily in various Texas and New Mexico counties.

Fair_Value_Measurements_of_Fin

Fair Value Measurements of Financial Instruments	12 Months Ended
Fair Value Measurements of Financial Instruments	Dec. 31, 2014
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). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:
	Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2014 and 2013, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.
	Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The carrying values of cash and cash equivalents, 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 December 31, 2014 and December 31, 2013. 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.
	The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2014 and December 31, 2013 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 derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013 for each of the fair value hierarchy levels:
		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
		Fair Value Measurements at December 31, 2013 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	$	—	$	105,054	$	—	$	105,054
	Interest rate derivatives		—		884		—		884
	Total assets	$	—	$	105,938	$	—	$	105,938

	Liabilities:
	Commodity derivatives	$	—	$	58,234	$	—	$	58,234
	Interest rate derivatives		—		5,590		—		5,590
	Total liabilities	$	—	$	63,824	$	—	$	63,824

	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 such factors 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. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach.
	—	Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. 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 year ended December 31, 2014, the MRD Segment recognized $24.6 million of impairments. The impairments primarily related to certain properties located in the Rockies as well as certain fields in North Louisiana. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to declining commodity prices.
	During the year ended December 31, 2014, MEMP recognized $407.5 million of impairments. The impairments primarily related to certain properties located in the Permian Basin, East Texas, and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable. In the Permian Basin the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and updated well performance data. In South Texas, the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. In East Texas, the impairments were due to downward revisions based on declining commodity prices. The carrying value of the: (i) Permian Basin properties after the $234.2 million impairment was approximately $88.7 million; (ii) East Texas properties after the $107.6 million impairment was approximately $88.8 million; and (iii) South Texas properties after the $65.6 million impairment was $71.2 million.

	·	During the year ended December 31, 2013, we recognized $6.6 million of impairments. The impairments related to certain properties located in South Texas. The estimated future cash flows expected were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties.
	·	During the year ended December 31, 2012, we recognized $28.9 million of impairments to proved oil and natural gas properties. Approximately $8.0 million related to a particular lease in the Elkhorn (Ellenburger) and Canyon Fields located in the Permian Basin as a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area. The remaining $20.9 million of impairments primarily related to certain fields in East Texas. The carrying values of these fields were determined to be unrecoverable due to a decline in gas prices.

Risk_Management_and_Derivative

Risk Management and Derivative Instruments	12 Months Ended
Risk Management and Derivative Instruments	Dec. 31, 2014
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 transactions 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 December 31, 2014, MEMP had net derivative assets of $517.1 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $309.8 million related to its derivative instruments of which $109.7 million was with a single counterparty. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $207.3 million against amounts outstanding under its revolving credit facility at December 31, 2014. At December 31, 2014, MRD had derivative assets of $255.0 million. After taking into effect netting arrangements, MRD had counterparty exposure of $155.8 million related to derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $99.2 million against amounts outstanding under its revolving credit facility at December 31, 2014. 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, call spreads and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement. During the year ended December 31, 2014, MRD restructured a portion of its commodity derivative portfolio by terminating “in the money” natural gas collars settling in 2015 and entering into natural gas swaps. The cash settlement receipts of $6.1 million from the termination of the collars were utilized to enhance the fixed price portion of the natural gas swaps.
	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 December 31, 2014, the MRD Segment had the following open commodity positions:
		2015				2016				2017				2018
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		3,700,000				2,570,000				1,770,000				2,900,000
	Weighted-average fixed price	$	4.15			$	4.09			$	4.24			$	4.27

	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			$	—

	Natural gas put option contracts:
	Average Monthly Volume (MMBtu)		3,000,000				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	$	(0.33	)		$	(0.36	)		$	(0.35	)		$	(0.35	)

	TGT Z1 basis swaps:
	Average Monthly Volume (MMBtu)		1,730,000				220,000				200,000				—
	Spread - Henry Hub	$	(0.09	)		$	(0.08	)		$	(0.08	)		$	—

	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		46,500				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			$	—			$	—

	Put option contracts:
	Average Monthly Volume (Bbls)		26,000				—				—				—
	Weighted-average fixed price	$	85			$	—			$	—			$	—
	Weighted-average deferred premium	$	(3.80	)		$	—			$	—			$	—

	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		151,000				185,658				—				—
	Weighted-average fixed price	$	41.61			$	34.06			$	—			$	—

	At December 31, 2014, the MEMP Segment had the following open commodity positions:
		2015				2016				2017				2018				2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		2,605,278				2,692,442				2,450,067				2,160,000				1,914,583
	Weighted-average fixed price	$	4.28			$	4.4			$	4.31			$	4.51			$	4.75

	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)		2,940,000				2,508,333				415,000				115,000				—
Spread	$	(0.12	)		$	(0.04	)		$	0			$	0.15			$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		314,281				332,813				326,600				312,000				160,000
Weighted-average fixed price	$	90.96			$	85.83			$	84.38			$	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)		97,500				95,000				—				—				—
Spread	$	(7.07	)		$	(9.56	)		$	—			$	—			$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		149,200				84,600				—				—				—
Weighted-average fixed price	$	43.02			$	41.49			$	—			$	—			$	—

-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:
	2015				2016				2017				2018
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,280,000				2,103,333				300,000				—
Spread - Henry Hub	$	(0.11	)		$	(0.06	)		$	(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)		57,500				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, interest rate swaps are entered into 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 December 31, 2014, we had the following interest rate swap open positions:
Credit Facility	2015				2016				2017
MEMP:
Average Monthly Notional (in thousands)	$	314,167			$	250,000			$	250,000
Weighted-average fixed rate		1.349	%			1.029	%			1.62	%
Floating rate	1 Month LIBOR				1 Month LIBOR				1 Month LIBOR
On July 1, 2014, we elected to terminate the interest rate swaps associated with the MRD credit facility and in the aggregate paid our counterparties approximately $0.7 million. WildHorse Resources novated the interest rate swaps to MRD in connection with the closing of our initial public offering.
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 December 31, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our collective credit agreements.

				Asset Derivatives								Liability Derivatives
Type		Balance Sheet Location		2014				2013				2014				2013
				(In thousands)
Commodity contracts		Short-term derivative instruments		$	378,908			$	21,759			$	38,852			$	19,739
Interest rate swaps		Short-term derivative instruments			—				845				3,289				3,287
Gross fair value					378,908				22,604				42,141				23,026
Netting arrangements		Short-term derivative instruments			(38,852	)			(13,315	)			(38,852	)			(13,315	)
Net recorded fair value		Short-term derivative instruments		$	340,056			$	9,289			$	3,289			$	9,711

Commodity contracts		Long-term derivative instruments		$	466,851			$	83,295			$	32,787			$	38,495
Interest rate swaps		Long-term derivative instruments			1,305				39				—				2,303
Gross fair value					468,156				83,334				32,787				40,798
Netting arrangements		Long-term derivative instruments			(32,787	)			(34,718	)			(32,787	)			(34,718	)
Net recorded fair value		Long-term derivative instruments		$	435,369			$	48,616			$	—			$	6,080
(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 years ending December 31, 2014, 2013, and 2012:
		Statements of		For the Years Ended December 31,
		Operations Location		2014				2013				2012
				(In thousands)
Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(749,988	)		$	(29,294	)		$	(34,905	)
Interest rate derivatives		Interest expense, net			145				(239	)			5,582

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2014
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 of wells and related facilities.
	The following table presents the changes in the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012:
		2014			2013			2012
		(In thousands)
	Asset retirement obligations at beginning of period	$	111,769		$	102,380		$	90,699
	Liabilities added from acquisitions or drilling		5,420			4,227			7,962
	Liabilities removed upon sale of wells		(669	)		(1,765	)		(1,931	)
	Liabilities removed upon plugging and abandoning		(588	)		(170	)		(119	)
	Revisions		293			1,516			760
	Accretion expense		6,306			5,581			5,009
	Asset retirement obligations at end of period		122,531			111,769			102,380
	Less: Current portion		—			90			390
	Asset retirement obligations— long-term portion	$	122,531		$	111,679		$	101,990

Restricted_Investments

Restricted Investments	12 Months Ended
Restricted Investments	Dec. 31, 2014
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 the offshore Southern California oil and gas properties owned by MEMP.
	The components of the restricted investment balance are as follows at December 31, 2014 and 2013:
		2014		2013
		(In thousands)
	BOEM platform abandonment (See Note 16)	$	69,954	$	66,373
	BOEM lease bonds		794		794

	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,701		2,306
	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	$	77,361	$	73,385

Long_Term_Debt

Long Term Debt	12 Months Ended
Long Term Debt	Dec. 31, 2014
Debt Disclosure [Abstract]
Long Term Debt	Note 8. Long Term Debt
	The following table presents our consolidated debt obligations at the dates indicated. The MEMP Segment debt included in the table below is nonrecourse to the Company.
		December 31,				December 31,
		2014				2013
		(In thousands)
	MRD Segment:
	MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	183,000			$	—
	WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014		—				203,100
	WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014		—				325,000
	10.00%/10.75% senior PIK toggle notes redeemed June 2014		—				350,000
	5.875% senior unsecured notes, due July 2022 (1)		600,000				—
	10.00%/10.75% senior PIK toggle notes unamortized discounts		—				(6,950	)
	Subtotal		783,000				871,150

	MEMP Segment:
	MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		412,000				103,000
	7.625% senior notes, fixed-rate, due May 2021 (2)		700,000				700,000
	6.875% senior unsecured notes, due August 2022 (3)		500,000				—
	Unamortized discounts		(16,587	)			(10,933	)
	Subtotal		1,595,413				792,067
	Total long-term debt	$	2,378,413			$	1,663,217

	-1	The estimated fair value of this fixed-rate debt was $534.0 million at December 31, 2014. 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 $563.5 million and $721.0 million at December 31, 2014 and 2013, 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 $380.0 million at December 31, 2014. 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 MRD’s and MEMP’s revolving credit facility was the following at the date indicated:
		December 31,
		2014
	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		1,440,000
	MRD Revolving Credit Facility
	On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with an initial borrowing base of $725.0 million and aggregate elected commitments of $725.0 million.
	We are permitted to borrow under the revolving credit facility in an amount up to the lesser of (i) the face amount of our revolving credit facility, (ii) the borrowing base or (iii) the aggregate elected commitments. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In addition, we may, subject to certain conditions, increase our aggregate elected commitments in an amount not to exceed the then effective borrowing base on or following a scheduled redetermination of our borrowing base once before the next scheduled redetermination date.
	Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage.
	The revolving credit facility requires maintenance of a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is determined under the MRD revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under the revolving credit facility, which we refer to as the current ratio, of not less than 1.0 to 1.0.
	Additionally, the revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production and prepay certain indebtedness.
	Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on our business.

	MRD 5.875% Senior Unsecured Notes Offering
	On July 10, 2014, MRD completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing subsidiaries (subject to customary release provisions). The MRD Senior Notes and the guarantees of the MRD Senior Notes will rank equally with our and the guarantors’ existing and future senior indebtedness, will be effectively junior to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the value of the assets securing such indebtedness), and senior in right of payment to all of our and the guarantors’ subordinated indebtedness. The MRD Senior Notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries, including MEMP and its subsidiaries and MEMP GP.
	The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies. MEMP and its subsidiaries are not subject to these covenants. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either the Company or the guarantors, all outstanding MRD Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately.
	PIK notes
	On December 18, 2013, MRD LLC and its wholly-owned subsidiary Memorial Resource Finance Corp. (“MRD Finance Corp.” and, together with MRD LLC, the “MRD Issuers”) completed a private placement of $350.0 million in aggregate principal amount of the PIK notes. The PIK notes were issued at 98% of par with a maturity date of December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under MRD LLC’s then-existing revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes. Interest on the PIK notes was payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014.
	A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014 at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption. In connection with the closing of our initial public offering, we assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee. An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes.
	WildHorse Resources Revolving Credit Facility and Second Lien Facility
	On April 3, 2013, WildHorse Resources entered into an amended and restated credit agreement. This revolving credit facility provided for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit and had an initial borrowing base of $300.0 million. This revolving credit facility was due to mature on April 13, 2018. The borrowing base was subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility were to be secured by liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties.
	On June 13, 2013, WildHorse Resources entered into a $325.0 million second lien term loan agreement that was due to mature on December 13, 2018. Borrowings bore interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement were to be secured by second-priority liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights was set forth in an intercreditor agreement. The second lien term loan agreement contained customary affirmative and negative covenants, restrictive provisions and events of default.
	On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC. This $225.0 million distribution was subsequently distributed to the Funds.
	In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan.
	MEMP Revolving Credit Facility & Senior Notes
	Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is a party to a $2.0 billion revolving credit facility, which is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries).
	Borrowings under the revolving credit facility are secured by liens on substantially all of MEMP’s properties, but in any event, not less than 80% of the total value of MEMP’s oil and natural gas properties, and all of MEMP’s equity interests in OLLC and any future guarantor subsidiaries (other than San Pedro Bay Pipeline Company) and all of MEMP’s other assets including personal property. Additionally, borrowings under the revolving credit facility bear interest, at MEMP’s option, at: (i) the Alternative Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base (or, if lower, the reduced commitment amount that has been elected) will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.
	On April 17, 2013, May 23, 2013 and October 10, 2013, MEMP and its wholly-owned subsidiary Memorial Production Finance Corporation (“Finance Corp.” and, together with MEMP, the “MEMP Issuers”) completed a private placement of $300.0 million, $100.0 million and $300.0 million, respectively, of their 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of the MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture. The 2021 Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MEMP Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately.
	On July 17, 2014, the MEMP Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2015. The indenture governing the 2022 Notes, dated as July 17, 2014, contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately.
	Weighted-Average Interest Rates
	The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented:
		For the Year Ended December 31,
		2014				2013				2012
	MRD Segment:
	MRD revolving credit facility		1.99	%		n/a				n/a
MRD LLC revolver terminated December 2013	n/a					3.17	%			4.11	%
Classic revolving credit facility terminated November 2012	n/a				n/a					4.5	%
WildHorse Resources revolver terminated June 2014		4.04	%			2.3	%			3	%
WildHorse Resources second lien terminated June 2014		6.44	%			7.6	%		n/a
Black Diamond terminated November 2013	n/a					3.97	%			3.62	%
MEMP Segment:
MEMP revolving credit facility		2.67	%			3.25	%			2.74	%
WHT revolver terminated March 2013	n/a					2.29	%			2.6	%
Tanos revolver terminated April 2013	n/a					3.1	%			2.31	%
REO revolving credit facility terminated December 2012	n/a				n/a					3.4	%
Stanolind revolver paid off by MEMP October 2013	n/a					3.52	%			3.76	%
Boaz revolver terminated October 2013	n/a					2.97	%			3.12	%
Crown revolver terminated October 2013	n/a					3.38	%			4.2	%
Propel Energy revolver paid off by MEMP October 2013	n/a					3.08	%			3.28	%
Unamortized Deferred Financing Costs
Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:
	December 31,				December 31,
	2014				2013
	(In thousands)
MRD Segment:
MRD revolving credit facility	$	4,285			$	—
MRD senior notes		12,455				—
WildHorse Resources revolving credit facility		—				2,436
WildHorse Resources second lien term loan		—				9,030
PIK notes		—				8,261
MEMP Segment:
MEMP revolving credit facility		6,468				5,413
2021 Senior Notes		13,308				15,053
2022 Senior Notes		7,958				—
	$	44,474			$	40,193

Stockholders_Equity_and_Noncon

Stockholders' Equity and Noncontrolling Interests	12 Months Ended
	Dec. 31, 2014
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 year ended December 31, 2014:
	Balance January 1, 2014	—
	Shares of common stock issued in connection with restructuring transactions (Note 1)	171,000,000
	Shares of common stock issued in initial public offering (Note 1)	21,500,000
	Shares of common stock repurchased and retired	(123,797	)
	Restricted common shares issued (Note 11)	1,068,422
	Restricted common shares forfeited	(9,211	)
	Balance December 31, 2014	193,435,414

	See Note 11 for additional information regarding restricted common shares that were granted in connection with our initial public offering. Restricted shares of common stock are participating securities and considered issued and outstanding on the grant date of restricted stock award.
	Share Repurchase Program
	In December 2014, 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 and are subject to market conditions, as well as corporate, regulatory, and other considerations. During the year ended December 31, 2014, 123,797 shares of common stock were repurchased and retired for a total cost of approximately $2.2 million.
	Subsequent event. MRD repurchased 2,764,887 shares of common stock under our repurchase program for an aggregate price of $47.8 million through March 16, 2015. MRD has retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding.
	Preferred Stock
	Our amended and restated certificate of incorporation authorizes our Board, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. There are no shares of preferred stock issued and outstanding as of December 31, 2014.
	Dividend Policy
	We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant.
	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, including the subordinated units held by MRD Holdco, that converted to common units in February 2015, 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. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings.
	In December 2012, MEMP sold 11,975,000 if its common units in an underwritten equity offering, which generated net cash proceeds of $194.1 million. The net proceeds from this equity offering partially funded MEMP’s December 2012 acquisition.
	On March 25, 2013, MEMP sold 9,775,000 of its common units in an underwritten equity offering, which generated net cash proceeds of $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering partially funded MEMP’s acquisition of all of the outstanding equity interests in WHT.
	On October 8, 2013, MEMP sold 16,675,000 of its common units in an underwritten equity offering, which generated net cash proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering were used to repay a portion of outstanding borrowings under MEMP’s revolving credit facility.
	On July 15, 2014, MEMP sold 9,890,000 common units in an underwritten equity offering, which generated net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.
	On September 9, 2014, MEMP sold 14,950,000 common units in an underwritten equity offering, which generated net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.
	In December 2014, the board of directors of MEMP GP authorized the repurchase of up to $150.0 million of MEMP’s outstanding common units from time to time on the open market, through block trades or otherwise and are subject to market conditions, as well as corporate, regulatory, and other considerations. During the year ended December 31, 2014, 899,912 common units were repurchased and retired for a total cost of approximately $12.9 million.
	Subsequent event. MEMP repurchased 1,909,583 common units under its repurchase program for an aggregate price of $28.5 million through February 1, 2015. MEMP has retired all common units repurchased and the common units are no longer issued or outstanding.
	On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. See Note 12 for further information.
	In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a transition services agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity.
	On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. See Note 12 for further information.
	In connection with our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for shares of our common stock and cash consideration of $30.0 million. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. See Note 12 for further information.

Earnings_per_Share

Earnings per Share	12 Months Ended
Earnings per Share	Dec. 31, 2014
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 period indicated (in thousands, except per share amounts):
		For the Year Ended December 31,
		2014
	Numerator:
	Net income (loss) available to common stockholders	$	(784,581	)

	Denominator:
	Weighted average common shares outstanding		192,498

	Basic EPS	$	(4.08	)
	Diluted EPS (1)	$	(4.08	)

	-1	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014.
	Our supplemental basic and diluted EPS includes earnings allocated to both previous owners and MRD LLC members for the period presented due to common control considerations. The following sets forth the calculation of our supplemental EPS, for the period indicated (in thousands, except per share amounts):
		For the Year Ended December 31,
		2014
	Numerator:
	Net income (loss) attributable to Memorial Resource Development Corp.	$	(762,851	)

	Denominator:
	Weighted average common shares outstanding		192,498

	Basic EPS	$	(3.96	)
	Diluted EPS (1)	$	(3.96	)

	-1	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014.

LongTerm_Incentive_Plans

Long-Term Incentive Plans	12 Months Ended
Long-Term Incentive Plans	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Long-Term Incentive Plans	Note 11. Long-Term Incentive Plans
	MRD
	In June 2014, our Board adopted the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) for the employees of the Company and the Board. The MRD LTIP became effective upon filing of a registration statement on Form S-8 with the SEC on June 18, 2014. The MRD LTIP provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, bonus stock, dividend equivalents, performance awards, annual incentive awards, and other stock-based awards. The MRD LTIP initially limits the number of common shares that may be delivered pursuant to awards under the plan up to 19,250,000 common shares. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The MRD LTIP will be administered by our Board or a committee thereof.
	In connection with our initial public offering, our Board approved an aggregate award of 1,052,633 shares of restricted stock under the MRD LTIP to certain of our key employees, including each of our executive officers. These restricted stock awards will vest ratably on a four-year annual vesting schedule from the date of the grant and are subject to restrictions on transferability and customary forfeiture provisions. An award of 5,263 shares of restricted stock was also granted to each of our independent directors. These restricted stock awards will vest one year from the date of the grant and are also subject to restrictions on transferability and customary forfeiture provisions.
	Award recipients are entitled to all the rights of absolute ownership of the restricted common shares, including the right to vote those shares and to receive dividends thereon if, as, and when declared by our Board. The term “restricted common share” represents a time-vested share. Such awards are non-vested until the required service period expires.
	The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented:
		Number of Shares				Weighted-Average Grant Date Fair Value per Share (1)
	Restricted common shares outstanding at January 1, 2014		—			$	—
	Granted (2)		1,068,422			$	19
	Forfeited		(9,211	)		$	19
	Restricted common units outstanding at December 31, 2014		1,059,211			$	19

	-1	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
	-2	The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on grant date market price of $19.00 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 Year Ended December 31,
	2014
	$	2,804

	The unrecognized compensation cost associated with restricted common share awards was an aggregate $17.3 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.43 years.
	MEMP
	In December 2011, the Memorial Production Partners GP LLC Long-Term Incentive Plan (“MEMP LTIP”) was adopted for employees, officers, consultants and directors of MEMP GP and any of its affiliates who perform services for MEMP. The MEMP LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The MEMP LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards.
	The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions. One-third of each award generally vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in MEMP with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by MEMP to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.
	The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented:
		Number of Units				Weighted-Average Grant Date Fair Value per Unit (1)
	Restricted common units outstanding at December 31, 2011		—			$	—
	Granted (2)		287,943			$	18.07
	Forfeited		(2,334	)		$	17.14
	Restricted common units outstanding at December 31, 2012		285,609			$	18.08
	Granted (3)		524,718			$	18.83
	Forfeited		(11,734	)		$	17.24
	Vested		(91,666	)		$	18.31
	Restricted common units outstanding at December 31, 2013		706,927			$	18.62
	Granted (4)		684,954			$	22.39
	Forfeited		(38,294	)		$	20.54
	Vested		(260,067	)		$	18.56
	Restricted common units outstanding at December 31, 2014		1,093,520			$	20.93

	-1	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
	-2	The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit.
	-3	The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit.
	-4	The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 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 Year Ended December 31,
	2014				2013			2012
	$	7,874			$	3,558		$	1,423
	The unrecognized compensation cost associated with restricted common unit awards was $16.5 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.1 years. Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to noncontrolling interests as presented on our statements of consolidated and combined cash flows.

Incentive_Units

Incentive Units	12 Months Ended
	Dec. 31, 2014
Compensation Related Costs [Abstract]
Incentive Units	Note 12. Incentive Units
	General
	Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.
	BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC each granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. In connection with MEMP’s initial public offering in December 2011, BlueStone’s Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders became eligible to participate in 16.5% of any future distributions made by BlueStone.
	Vesting of the incentive units was generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested were forfeited if an employee was no longer employed. All incentive units were forfeited if a holder resigned whether the incentive units were vested or not. If the payouts had not yet occurred, then all incentive units, whether or not vested, were forfeited automatically (unless extended).
	On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as a component of general and administrative expense during the year ended December 31, 2013.
	On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. Compensation expense of approximately $12.6 million was recorded by Black Diamond, Classic GP and Classic in the aggregate during November 2013.
	Compensation expense of approximately $1.0 million and $20.7 million was recorded by BlueStone and recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 and 2013, respectively. No compensation expense was recorded at December 31, 2012.
	In connection with the PIK notes issued in December 2013, a special distribution of $10.0 million to holders of WildHorse’s Tier 1 incentive units was deemed probable of occurring. This amount was recognized as compensation expense in December 2013 with a corresponding amount in accrued liabilities on our balance sheet at December 31, 2013 as payment was not made until January 2, 2014.
	In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was accounted for as the acquisition of noncontrolling interests. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. Compensation expense of approximately $831.1 million was recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 related to the incentive units, of which approximately $26.7 million was paid in cash and the remaining $804.4 million related to the issuance of our common stock.
	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”).
	The holders of the Exchanged Incentive Units are eligible to participate in 9.3% of any future distributions made by MRD Holdco. The payment likelihood was deemed probable as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. During 2014, we recognized $111.5 million of compensation expense offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $105.5 million as of December 31, 2014 will be recognized over the remaining expected service period of 2.41 years.
	Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”). The holders of the Subsequent Incentive Units are eligible to participate in 0.7% of any future distributions made by MRD Holdco once payout associated with these incentive units has been achieved. The payment likelihood was deemed probable at December 31, 2014 as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. During 2014, we recognized $0.4 million of compensation expense and the unrecognized compensation expense of approximately $1.7 million as of December 31, 2014 will be recognized over the remaining expected service period of 2.41 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 (income) will be allocated to us in future periods offset by capital contributions (distributions). 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	12/31/14			12/31/14
	Dividend yield		0	%		0	%
	Expected volatility		39.54	%		39.54	%
	Risk-free rate		0.85	%		0.85	%
	Expected life (years)		2.41			2.41

Related_Party_Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2014
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 December 31, 2014 and 2013 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.
	Net Profits Interest Sold to NGP
	Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Upon the acquisition of the Petrohawk properties WildHorse Resources immediately sold a net profits interest of 6.25% for all producing well bores and the right to participate in a 3.125% net profits interest in non-producing wellbores for the subject area for $19.5 million, or $19.1 million after adjustments. Upon the acquisition of the Clayton Williams properties, WildHorse Resources immediately sold a net profits interest of 23.5% for all producing wellbores and the right to participate in a 10.0% net profits interest in non-producing wellbores for the subject area for $19.8 million, or $19.9 million after adjustments. No gain or loss was recorded from these two transactions.
	The net profits agreements for these transactions provided for a fixed fee of $20,000 per month for overhead and management in lieu of COPAS (Council of Petroleum Accountants Societies) billings. The net profits agreements did not provide for an overhead adjustment factor for this monthly charge, as suggested by COPAS. Quarterly net payments were made to NGPCIF for its net profits interest in the Petrohawk and Clayton Williams acquisitions. The net payments included credits for revenue receipts which were offset with production costs, capital expenditures and the management fee and were adjusted for any acquisition settlements received or paid and any other miscellaneous adjustments. As required by such agreements, WildHorse Resources could not collect funds owed by NGPCIF to WildHorse Resources, but WildHorse Resources could net amounts due from future quarterly payments.
	As a result of these transactions, WildHorse Resources paid NGPCIF a total of $2.6 million and $2.3 million during 2013 and 2012, respectively. NGPCIF owed WildHorse Resources $0.2 million at December 31, 2013.

	NGPCIF NPI Acquisition
	WildHorse Resources repurchased the net profits interests discussed above 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.
	Transactions Between the Previous Owners and NGP Affiliates
	The previous owners sold certain interests in oil and gas properties offshore Louisiana on October 11, 2012 for an aggregate $40.1 million to an NGP controlled entity, of which $38.1 million was received upon closing and the remaining proceeds were released from escrow in April 2013. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $6.3 million and recognized in the equity statement as a net contribution.
	Beta Acquisition
	On December 12, 2012, MEMP acquired Rise Energy Operating, Inc. (‘REO”), which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California (the “Beta Properties”), from Rise for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. The Beta acquisition was funded with borrowings under MEMP’s revolving credit facility and the net proceeds generated from its December 12, 2012 public offering of common units. 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. MEMP recorded the following net assets (in thousands):
	Cash and cash equivalents	$	6,021
	Accounts receivable		16,284
	Short-term derivative instruments, net		2,926
	Prepaid expenses and other current assets		4,521
	Oil and natural gas properties, net		108,342
	Restricted investments		68,009
	Accounts payable		(9,092	)
	Accrued liabilities		(9,140	)
	Asset retirement obligations		(58,746	)
	Credit facilities		(28,500	)
	Deferred tax liability		(1,674	)
	Noncontrolling interest		(5,255	)
	Net assets	$	93,696
	An affiliate of REO collected a management fee for providing administrative services to REO. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. REO incurred and paid management fees of $1.6 million during the year ended December 31, 2012. These management fees are presented as a component of general and administrative costs and expenses in the accompanying statements of operations.
	October 2013 Cinco Group Acquisition
	On October 1, 2013, MEMP acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from MRD LLC and certain affiliates of NGP for an aggregate purchase price of approximately $603 million (subject to customary post-closing adjustments), of which approximately $507.1 million was received by certain affiliates of NGP. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under MEMP’s revolving credit facility. The Cinco Group 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.

	Cash and cash equivalents	$	2,820
	Accounts receivable		5,184
	Prepaid expenses and other current assets		1,454
	Oil and natural gas properties, net		342,759
	Long-term derivative instruments, net		(826	)
	Other long-term assets		344
	Accounts payable		(2,346	)
	Revenue payable		(2,910	)
	Accrued liabilities		(1,799	)
	Short-term derivative instruments, net		(1,828	)
	Asset retirement obligations		(9,606	)
	Credit facilities		(151,690	)
	Net assets	$	181,556
	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, MRD Royalty acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from Propel Energy for $3.3 million.
	On June 18, 2014, in connection with our initial public offering and the related restructuring transactions (see Note 1), WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value. The net book value of the assets sold was as follows (in thousands):
	Cash and cash equivalents	$	33,001
	Restricted cash		300
	Accounts receivable		5,256
	Prepaid expenses and other current assets		379
	Property, plant and equipment, net		3,410
	Other long-term assets		4
	Accounts payable		(19,959	)
	Accounts payable - affiliates		(17,099	)
	Accrued liabilities		(5,061	)
	Net assets	$	231
	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. The voting agreement also prohibits the transfer of any shares of our common stock by the former management members of WildHorse Resources until after the termination of the services agreement described below; provided, however, that the former management members of WildHorse Resources (other than Messrs. Bahr and Graham) may transfer their shares of our common stock after the 180 day lock-up period has expired and these transfer restrictions will not prohibit Messrs. Bahr and Graham from exercising piggyback registration rights under the registration rights agreement described above.
Services Agreement
In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WHR Management Company, pursuant to which WHR Management Company would 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. NGP and certain former management members of WildHorse Resources own WHR II.
Subsequent event. We terminated the services agreement as of March 1, 2015.
WildHorse Management Services Agreement
WHR II is an independent energy company engaged in the acquisition, exploration, and development of natural gas and crude oil properties. WHR II is a related party and was organized in the State of Delaware on June 3, 2013. A management services agreement was executed on August 8, 2013, where WildHorse Resources provided general, administrative and employee services to WHR II. On August 8, 2013, a management agreement between WildHorse Resources and WHR II was executed where WildHorse was appointed the manager for WHR II with responsibilities included administrative and land services, operator services and financial and accounting services. As operator, WildHorse Resources received operated and non-operated revenues on behalf of WHR II and billed and received joint interest billings. In addition, WildHorse Resources paid for lease operating expenses and drilling costs on behalf of WHR II. On August 8, 2013, an asset and cost sharing agreement between WildHorse Resources and WHR II was executed. As part of the agreement, shared WildHorse Resources costs were allocated between WildHorse Resources and WHR II in accordance with a sharing ratio. The sharing ratio is based on the previous quarter’s capital expenditures and number of operated wells. Company specific costs were billed directly to the appropriate entity. As a result of these agreements, WildHorse Resources received net payments of $4.4 million from WHR II in 2013. WildHorse Resources owed WHR II $2.4 million as of December 31, 2013. These agreements were terminated in connection with our initial public offering.
Cinco Group Transition Service Agreements
MEMP entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to provide operating and administrative services to MEMP with respect to the acquired properties. The term of these agreements were from October 1, 2013 through February 28, 2014. MEMP paid transition service fees of approximately $0.8 million in the aggregate under these agreements.
Other Agreements
Effective March 1, 2012, BlueStone entered into an agreement with CH4 Energy III, LLC, an NGP controlled entity, to sell an undivided 25% interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $7.0 million, which exceeded the net book value of the properties sold by $6.4 million. Due to common control considerations, the $6.4 million was recognized in the equity statement as a contribution. The transaction closed on July 13, 2012.
A company affiliated with one of the Classic’s employees provided certain land-related services to Classic. Classic paid approximately $1.0 million to this affiliated company for these services in 2012.
Certain of the Cinco Group entities entered into advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the years ended December 31, 2013 and 2012 were approximately $0.3 million and $0.4 million, respectively. Certain of the Cinco Group entities also paid a financing fee equal to a percentage of the capital contributions raised by NGP. These fees were considered a syndication cost and reduced equity contributions for financing fees paid. Fees for the year ended December 31, 2012 was approximately $0.4 million. There were no fees for the year ended December 31, 2013.
During 2012, the previous owners received an equity contribution of $6.9 million of oil and gas properties in the Hendricks Field located in the Permian Basin of Texas by an NGP controlled entity. Due to common control considerations, this equity contribution was recorded at historical cost of the properties.
During 2012, Boaz reimbursed a member of its management team approximately $0.3 million in general, administrative, and lease operating expenses related to an oral lease agreement between the member of management and a third party for a field office and yard located in Bronte, Texas.
Gas Processing Agreement
On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Holdco owns, through its subsidiary MRD Midstream LLC, a minority interest. Once PennTex’s 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 agreement has a 15-year primary term, subject to one-year extensions at either party’s election. We will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the 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. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015.
Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement
On November 1, 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. On May 1, 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.
On May 1, 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.

Business_Segment_Data

Business Segment Data	12 Months Ended
Business Segment Data	Dec. 31, 2014
Segment Reporting [Abstract]
Business Segment Data	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, development and production of oil and natural gas properties. Our reportable business segments are as follows:
	—	MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.
	—	MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating 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); acquisition 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; 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 Year ended December 31, 2014	$	405,286			$	494,105			$	(46	)		$	899,345
	For the Year ended December 31, 2013		231,558				343,616				(151	)			575,023
	For the Year ended December 31, 2012		138,814				258,423				(369	)			396,868
	Adjusted EBITDA: (1)
	For the Year ended December 31, 2014		343,976				309,901				(6,144	)			647,733
	For the Year ended December 31, 2013		197,903				222,185				(25,232	)			394,856
	For the Year ended December 31, 2012		132,105				179,334				(23,447	)			287,992
	Segment assets: (2)
	As of December 31, 2014		1,632,313				2,930,559				30,675				4,593,547
	As of December 31, 2013		1,281,134				1,552,307				(4,280	)			2,829,161
	Total cash expenditures for additions to long-lived assets:
	For the Year ended December 31, 2014		521,038				1,348,095				—				1,869,133
	For the Year ended December 31, 2013		267,870				200,577				—				468,447
	For the Year ended December 31, 2012		249,526				387,160				—				636,686

	-1	Adjustments and eliminations for the years ended December 31, 2014, 2013 and 2012 include amounts related to the MRD Segment’s equity investments in the MEMP Segment as well the elimination of $6.1 million, $26.0 million and $19.3 million of cash distributions that MEMP paid MRD Segment for the years ended December 31, 2014, 2013 and 2012, respectively, related to MRD Segment’s partnership interests in MEMP.
	-2	Adjustments and eliminations primarily represent the elimination of the MRD Segment’s equity investments in the MEMP Segment. The adjustment at December 31, 2014 and 2013 also includes $46.0 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013. This impairment did not exist on a consolidated basis.

	Calculation of Reportable Segments’ Adjusted EBITDA

		For the Year Ended December 31, 2014
										Combined
		MRD				MEMP				Totals
		(In thousands)
	Net income (loss)	$	(762,926	)		$	118,079			$	(644,847	)
	Interest expense, net		50,283				83,550				133,833
	Loss on extinguishment of debt		37,248				—				37,248
	Income tax expense (benefit)		99,850				1,121				100,971
	DD&A		154,917				155,404				310,321
	Impairment of proved oil and natural gas properties		24,576				407,540				432,116
	Accretion of AROs		688				5,618				6,306
	(Gain) loss on commodity derivative instruments		(257,734	)			(492,254	)			(749,988	)
	Cash settlements received (paid) on commodity derivative instruments		9,166				13,522				22,688
	(Gain) loss on sale of properties		3,057				—				3,057
	Acquisition related costs		2,305				4,363				6,668
	Incentive-based compensation expense		946,753				7,874				954,627
	Exploration costs		15,813				790				16,603
	Provision for environmental remediation		—				2,852				2,852
	Loss on office lease		1,180				1,442				2,622
	Non-cash equity (income) loss from MEMP		12,656				—				12,656
	Cash distributions from MEMP		6,144				—				6,144
	Adjusted EBITDA	$	343,976			$	309,901			$	653,877

		For the Year Ended December 31, 2013
										Combined
		MRD				MEMP				Totals
						(In thousands)
	Net income (loss)	$	82,243			$	20,268			$	102,511
	Interest expense, net		27,349				41,901				69,250
	Income tax expense (benefit)		1,311				308				1,619
DD&A		87,043				97,269				184,312
Impairment of proved oil and natural gas properties		2,527				54,362				56,889
Accretion of AROs		728				4,853				5,581
(Gain) loss on commodity derivative instruments		(3,013	)			(26,281	)			(29,294	)
Cash settlements received (paid) on commodity derivative instruments		12,240				19,879				32,119
(Gain) loss on sale of properties		(82,773	)			(2,848	)			(85,621	)
Acquisition related costs		1,584				6,729				8,313
Incentive-based compensation expense		43,279				3,558				46,837
Non-cash compensation expense		—				1,057				1,057
Exploration costs		1,226				1,130				2,356
Non-cash equity (income) loss from MEMP		(1,847	)			—				(1,847	)
Cash distributions from MEMP		26,006				—				26,006
Adjusted EBITDA	$	197,903			$	222,185			$	420,088


	For the Year Ended December 31, 2012
									Combined
	MRD				MEMP				Totals
					(In thousands)
Net income (loss)	$	(14,641	)		$	46,518			$	31,877
Interest expense, net		12,802				20,436				33,238
Income tax expense (benefit)		(178	)			285				107
DD&A		62,636				76,036				138,672
Impairment of proved oil and natural gas properties		18,339				10,532				28,871
Accretion of AROs		632				4,377				5,009
(Gain) loss on commodity derivative instruments		(13,488	)			(21,417	)			(34,905	)
Cash settlements received (paid) on commodity derivative instruments		30,188				44,111				74,299
(Gain) loss on sale of properties		(2	)			(9,759	)			(9,761	)
Acquisition related costs		403				4,135				4,538
Incentive-based compensation expense		9,510				1,423				10,933
Amortization of investment premium		—				194				194
Exploration costs		7,337				2,463				9,800
Non-cash equity (income) loss from MEMP		(696	)			—				(696	)
Cash distributions from MEMP		19,263				—				19,263
Adjusted EBITDA	$	132,105			$	179,334			$	311,439

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 Year Ended December 31,
	2014				2013				2012
Total Reportable Segments' Adjusted EBITDA	$	653,877			$	420,088			$	311,439
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(133,833	)			(69,250	)			(33,238	)
Loss on extinguishment of debt		(37,248	)			—				—
Income tax benefit (expense)		(100,971	)			(1,619	)			(107	)
DD&A		(314,193	)			(184,717	)			(138,672	)
Impairment of proved oil and natural gas properties		(432,116	)			(6,600	)			(28,871	)
Accretion of AROs		(6,306	)			(5,581	)			(5,009	)
Gains (losses) on commodity derivative instruments		749,988				29,294				34,905
Cash settlements paid (received) on commodity derivative instruments		(22,688	)			(32,119	)			(74,299	)
Gain (loss) on sale of properties		(3,057	)			85,621				9,761
Acquisition related costs		(6,668	)			(8,313	)			(4,538	)
Incentive-based compensation expense		(954,627	)			(46,837	)			(10,933	)
Non-cash compensation expense		—				(1,057	)			—
Exploration costs		(16,603	)			(2,356	)			(9,800	)
Amortization of investment premium		—				—				(194	)
Cash distributions from MEMP		(6,144	)			(26,006	)			(19,263	)
Provision for environmental remediation		(2,852	)			—				—
Loss on office lease		(2,622	)			—				—
Other non-cash equity (income) loss		—				784				(4,184	)
Net income (loss)	$	(636,063	)		$	151,332			$	26,997

Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands):
	For the Year Ended December 31, 2014
	MRD				MEMP				Other, Adjustments & Eliminations				Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	404,718			$	490,249			$	—			$	894,967
Other revenues		568				3,856				(46	)			4,378
Total revenues		405,286				494,105				(46	)			899,345

Costs and expenses:
Lease operating		26,695				134,654				(46	)			161,303
Pipeline operating		—				2,068				—				2,068
Exploration		15,813				790				—				16,603
Production and ad valorem taxes		14,150				31,601				—				45,751
Depreciation, depletion, and amortization		154,917				155,404				3,872				314,193
Impairment of proved oil and natural gas properties		24,576				407,540				—				432,116
Incentive unit compensation expense		943,949				—				—				943,949
General and administrative		42,054				45,619				—				87,673
Accretion of asset retirement obligations		688				5,618				—				6,306
(Gain) loss on commodity derivative instruments		(257,734	)			(492,254	)			—				(749,988	)
(Gain) loss on sale of properties		3,057				—				—				3,057
Other, net		—				(12	)			—				(12	)
Total costs and expenses		968,165				291,028				3,826				1,263,019
Operating income (loss)		(562,879	)			203,077				(3,872	)			(363,674	)
Other income (expense):
Interest expense, net		(50,283	)			(83,550	)			—				(133,833	)
Loss on extinguishment of debt		(37,248	)			—				—				(37,248	)
Earnings from equity investments		(12,656	)			—				12,656				—
Other, net		(10	)			(327	)			—				(337	)
Total other income (expense)		(100,197	)			(83,877	)			12,656				(171,418	)
Income (loss) before income taxes		(663,076	)			119,200				8,784				(535,092	)
Income tax benefit (expense)		(99,850	)			(1,121	)			—				(100,971	)
Net income (loss)	$	(762,926	)		$	118,079			$	8,784			$	(636,063	)


	For the Year Ended December 31, 2013
	MRD				MEMP				Other, Adjustments & Eliminations				Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	230,751			$	341,197			$	—			$	571,948
Other revenues		807				2,419				(151	)			3,075
Total revenues		231,558				343,616				(151	)			575,023

Costs and expenses:
Lease operating		25,006				88,893				(259	)			113,640
Pipeline operating		—				1,835				—				1,835
Exploration		1,226				1,130				—				2,356
Production and ad valorem taxes		9,362				17,784				—				27,146
Depreciation, depletion, and amortization		87,043				97,269				405				184,717
Impairment of proved oil and natural gas properties		2,527				54,362				(50,289	)			6,600
Incentive unit compensation expense		43,279				—				—				43,279
General and administrative		38,479				43,495				105				82,079
Accretion of asset retirement obligations		728				4,853				—				5,581
(Gain) loss on commodity derivative instruments		(3,013	)			(26,281	)			—				(29,294	)
(Gain) loss on sale of properties		(82,773	)			(2,848	)			—				(85,621	)
Other, net		2				647				—				649
Total costs and expenses		121,866				281,139				(50,038	)			352,967
Operating income (loss)		109,692				62,477				49,887				222,056
Other income (expense):
Interest expense, net		(27,349	)			(41,901	)			—				(69,250	)
Earnings from equity investments		1,066				—				(1,066	)			—
Other, net		145				—				—				145
Total other income (expense)		(26,138	)			(41,901	)			(1,066	)			(69,105	)
Income before income taxes		83,554				20,576				48,821				152,951
Income tax benefit (expense)		(1,311	)			(308	)			—				(1,619	)
Net income (loss)	$	82,243			$	20,268			$	48,821			$	151,332


	For the Year Ended December 31, 2012
	MRD				MEMP				Other, Adjustments & Eliminations				Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	138,032			$	255,608			$	(9	)		$	393,631
Other revenues		782				2,815				(360	)			3,237
Total revenues		138,814				258,423				(369	)			396,868

Costs and expenses:
Lease operating		24,438				80,116				(800	)			103,754
Pipeline operating		—				2,114				—				2,114
Exploration		7,337				2,463				—				9,800
Production and ad valorem taxes		7,576				16,048				—				23,624
Depreciation, depletion, and amortization		62,636				76,036				—				138,672
Impairment of proved oil and natural gas properties		18,339				10,532				—				28,871
Incentive unit compensation expense		9,510				—				—				9,510
General and administrative		28,904				30,342				431				59,677
Accretion of asset retirement obligations		632				4,377				—				5,009
(Gain) loss on commodity derivative instruments		(13,488	)			(21,417	)			—				(34,905	)
(Gain) loss on sale of properties		(2	)			(9,759	)			—				(9,761	)
Other, net		364				138				—				502
Total costs and expenses		146,246				190,990				(369	)			336,867
Operating income (loss)		(7,432	)			67,433				—				60,001
Other income (expense):
Interest expense, net		(12,802	)			(20,436	)			—				(33,238	)
Amortization of investment premium		—				(194	)			—				(194	)
Earnings from equity investments		4,880				—				(4,880	)			—
Other, net		535				—				—				535
Total other income (expense)		(7,387	)			(20,630	)			(4,880	)			(32,897	)
Income before income taxes		(14,819	)			46,803				(4,880	)			27,104
Income tax benefit (expense)		178				(285	)			—				(107	)
Net income (loss)	$	(14,641	)		$	46,518			$	(4,880	)		$	26,997

Income_Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Tax	Note 15. Income Taxes
	Income tax benefit (expense) for the indicated periods is comprised of the following:
		For the Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Current taxes:
	Federal	$	—		$	—		$	—
	State		22			(1,619	)		178
	Deferred taxes:
	Federal		(88,994	)		—			—
	State		(11,999	)		—			(285	)
	Total income tax benefit (expense)	$	(100,971	)	$	(1,619	)	$	(107	)
	The actual income tax benefit (expense) differs from the expected income tax benefit (provision) as computed by applying the federal statutory corporate tax rate of 35% for each period indicated as follows:
		For the Year Ended December 31,
		2014			2013			2012
	Expected tax benefit (expense)	$	187,282		$	(53,533	)	$	(9,486	)
	State income tax expense, net of federal benefit		(9,660	)		(1,619	)		(107	)
	Pass-through entities (1)		49,989			53,533			9,486
	Stock compensation (2)		(330,024	)		—			—
	Other		1,442			—			—
	Total income tax benefit (expense)	$	(100,971	)	$	(1,619	)	$	(107	)

	-1	MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes.
	-2	As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes.
	The components of net deferred income tax assets and (liabilities) recognized were as follows:
		December 31,
		2014			2013
		(In thousands)
	Deferred current income tax assets:
	Unrealized hedging transactions	$	109		$	37
	Accrued liabilities		—			5
	Other		342			(42	)
	Deferred current income tax assets:	$	451		$	—

	Deferred current income tax liabilities:
	Unrealized hedging transactions	$	(52,328	)		—
	Other		(52	)		(382	)
	Deferred current income tax liabilities:	$	(52,380	)	$	(382	)

	Deferred noncurrent income tax assets:
	Net operating loss carryforward	$	28,043		$	2,350
	Asset retirement obligation		5,757			971
	Other		3,224			1
	Net deferred tax valuation allowance		(2,634	)		(2,896	)
	Deferred noncurrent income tax assets:	$	34,390		$	426

	Deferred noncurrent income tax liabilities:
	Property, plant and equipment	$	(80,198	)	$	(3,318	)
	Unrealized hedging transactions		(48,929	)		(275	)
	Other		(280	)		61
	Deferred noncurrent income tax liabilities:	$	(129,407	)	$	(3,532	)

	Net current deferred income tax assets (liabilities)	$	(51,929	)	$	(382	)
	Net noncurrent deferred income tax assets (liabilities)	$	(95,017	)	$	(3,106	)
	We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company has no unrecognized tax benefits for the years ended December 31, 2014, 2013 or 2012.
	Generally, the Company's income tax years 2011 through 2014 remain open and subject to examination by Federal tax authorities or state tax authorities where the Company conducts operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination.
	The Company recognizes interest and penalties accrued to unrecognized benefits in Other income (expense) in its consolidated statements of operations. For the years ended December 31, 2014, 2013 and 2012 the Company recognized no interest and penalties.
	As of December 31, 2014, the Company has available, to reduce future taxable income, a United States net operating loss carryforwards (NOLs) of approximately $74.3 million before consideration of any valuation allowance which expires in the years 2027 thru 2035. A portion of these net operating loss carryforwards are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code (IRC). The Company also has various net state NOL carryforwards of approximately $65.0 million, before consideration of any valuation allowance with varying lengths of allowable carryforward periods ranging from 10 to 20 years that can be used to offset future state taxable income.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 16. 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.
	Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals.
	The following table presents the activity of our environmental reserves for the periods presented:
		2014				2013			2012
		(In thousands)
	Balance at beginning of period	$	577			$	1,469		$	1,747
	Charged to costs and expenses		2,852				—			193
	Payments		(1,337	)			(892	)		(471	)
	Balance at end of period	$	2,092			$	577		$	1,469
	At December 31, 2014 and 2013, $2.1 million and $0.6 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.
	Sinking Fund Trust Agreement
	REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2014, the gross account balance included in restricted investments was approximately $2.7 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $0.8 million at December 31, 2014.
	Supplemental Bond for Decommissioning Liabilities Trust Agreement
	REO assumed an obligation with the BOEM in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met.
	In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make additional quarterly payments to the trust account attributable to its net working interest of approximately $0.6 million beginning on June 30, 2010 until the payments and accrued interest attributable to REO equal $78.7 million by December 31, 2016. 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
	In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. As of December 31, 2014, the maximum remaining obligation net to REO’s interest was approximately $8.7 million.
	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 December 31, 2014 (in thousands):
		Amortized
	Investment	Cost
	U.S. Bank Money Market Cash Equivalent	$	135,176
	Less: Outside working interest owners share		(65,222	)
		$	69,954
	Purchase Commitment Assumed
	At December 31, 2014, MEMP had a CO2 purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands):
					Payment or Settlement due by Period
	Purchase commitment	Total				2015			2016			2017		2018		2019		Thereafter

	CO2 minimum purchase commitment:
	Estimated payment obligation	$	50,495			$	9,608		$	10,179		$	10,151	$	6,995	$	7,060	$	6,502
	Processing Plant Expansions by Third Party Gatherer
	In 2012, WildHorse Resources contracted with Regency Field Services LLC (the “Gatherer”) to expand their Dubach processing plant by up to 70 MMcf per day among other facility and infrastructure improvements. In 2013, WildHorse Resources contracted with the Gatherer to build a new high pressure pipeline from the dedicated area to the Gatherer’s Dubberly processing plant in Webster Parish, LA amongst other pipeline and infrastructure improvements. The Gatherer is entitled to receive a payback demand fee from us and other third parties equal to 110% of the infrastructure improvement costs. Effective February 1, 2014, the payback demand fee is equal to the monthly demand quantity (192,950 MMBtu per day) times $0.275 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, we are obligated to pay a payback demand fee of $0.275 per MMBtu. The monthly demand quantity escalated to 249,700 MMBtu per day until payout effective January 1, 2015.
	WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2014 were as follows (in thousands):
		Dubach				Dubberly
	2015	$	13,671			$	11,393
	2016		13,709				11,424
	2017		13,671				11,393
	2018		12,772				10,643
	Total	$	53,823			$	44,853
	Related Party Agreements
	Classic Operating entered into a gas gathering agreement and water disposal agreement with Classic Pipeline.
	On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex. See Note 13 for additional information.
	Operating Leases
	We have leases for offshore Southern California pipeline right-of-way use as well as office space for our corporate headquarters and operating regions. We also lease equipment and incur surface rentals related to our business operations. For the years ended December 31, 2014, 2013, and 2012 we recognized $10.8 million, $8.3 million, and $5.0 million of rent expense, respectively.
	Amounts shown in the following table represent minimum lease payment obligations and sublease rental income under non-cancelable operating leases with a remaining term in excess of one year:
					Payment or Settlement due by Period
		Total				2015			2016			2017		2018		2019		Thereafter
		(In thousands)
	MRD Segment:
	Operating leases	$	43,625			$	6,534		$	6,607		$	6,694	$	6,259	$	5,960	$	11,571
	Sublease rental income		5,786				1,691			1,579			1,197		814		431		74
	MEMP Segment:
	Operating leases		3,665				788			416			205		205		205		1,846

Defined_Contribution_Plans

Defined Contribution Plans	12 Months Ended
Defined Contribution Plans	Dec. 31, 2014
Postemployment Benefits [Abstract]
Defined Contribution Plans	Note 17. Defined Contribution Plans
	MRD sponsors a defined contribution plan for the benefit of substantially all employees who have attained 18 years of age. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. MRD makes matching contributions of 100% of employee contributions that does not exceed 6% of compensation. Employees are immediately vested in these matching contributions. This plan became effective on January 1, 2012. The plan received employer contributions of approximately $1.4 million, $0.9 million, and $0.4 million in 2014, 2013, and 2012 respectively.
	Effective January 1, 2012, REO assumed sponsorship of a separate defined contribution plan. This plan specifically benefits substantially all those employed by the MRD subsidiary (Beta Operating) that operates and supports the Beta properties that have attained 21 years of age. Eligible employees are permitted to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Employer matching contributions of 100% of employee contributions that does not exceed 6% of compensation are made to the plan as well. The employer matching contributions associated with this plan were subject to a three-year graded vesting schedule through February 28, 2012. Effective March 1, 2012, the plan was amended to offer immediate vesting of employer matching contributions. This plan was terminated December 31, 2013. The plan received employer contributions of approximately $0.6 million and $0.5 million in 2013, and 2012 respectively. Approximately $0.3 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for the each of the years ended December 31, 2013 and 2012, respectively.
	WildHorse, Tanos, BlueStone, Classic and Black Diamond also sponsored defined contribution plans for the benefit their eligible employees. Matching employer contributions of approximately $0.2 million, $0.5 million and $0.6 million were made to these other plans in 2014, 2013 and 2012, respectively.
	Crown and Stanolind also made matching contributions to defined contribution plans for the benefit of their eligible employees. Matching employer contributions of approximately $0.1 million were made to these plans in both 2013 and 2012. Such contributions to these plans are included in general and administrative expenses in the accompanying combined statements of operations.

Quarterly_Financial_Informatio

Quarterly Financial Information (Unaudited)	12 Months Ended
Quarterly Financial Information (Unaudited)	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (Unaudited)	Note 18. Quarterly Financial Information (Unaudited)
	The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 4 and Note 12, we recorded oil and natural gas property impairments and incentive unit compensation expense, respectively, during 2014, which impacted the comparability between the periods presented below.
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	For the Year Ended December 31, 2014	(In thousands, except per share amounts)
	Revenues	$	190,828		$	236,564		$	245,493		$	226,460
	Operating income (loss)		10,605			(993,256	)		174,201			444,776
	Net income (loss)		(23,516	)		(1,053,443	)		112,037			328,859
	Net income (loss) attributable to noncontrolling interest		(31,888	)		(105,094	)		102,109			161,661
	Net income (loss) attributable to Memorial Resource		8,372			(948,349	)		9,928			167,198
	Development Corp.		8,372			(948,349	)		9,928			167,198
	Net income (loss) allocated to members		6,947			13,358			—			—
	Net income (loss) allocated to previous owners		1,425			—			—			—
	Net income (loss) available to common stockholders	n/a				(961,707	)		9,928			167,198
	Basic earnings per share	n/a				(5.00	)		0.05			0.87
	Diluted earnings per share	n/a				(5.00	)		0.05			0.87


		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	For the Year Ended December 31, 2013	(In thousands, except per share amounts)
	Revenues	$	122,181		$	147,045		$	153,515		$	152,282
	Operating income (loss)		9,521			90,327			117,797			4,411
	Net income (loss)		180			78,158			95,962			(22,968	)
	Net income (loss) attributable to noncontrolling interest		(4,069	)		34,975			11,235			7,689
	Net income (loss) attributable to Memorial Resource		4,249			43,183			84,727			(30,657	)
	Development Corp.		4,249			43,183			84,727			(30,657	)
	Net income (loss) allocated to members		2,597			35,278			84,754			(31,917	)
	Net income (loss) allocated to previous owners		1,652			7,905			(27	)		1,260

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
Supplemental Oil and Gas Information (Unaudited)	Dec. 31, 2014
Extractive Industries [Abstract]
Supplemental Oil and Gas Information (Unaudited)	Note 19. Supplemental Oil and Gas Information (Unaudited)
	Capitalized Costs Relating to Oil and Natural Gas Producing Activities
	The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.
		For the Year Ended December 31,
		2014				2013				2012
		(In thousands)
	MRD Segment:
	Evaluated oil and natural gas properties	$	1,590,997			$	1,226,417			$	1,052,219
	Unevaluated oil and natural gas properties		48,229				46,413				26,589
	Accumulated depletion, depreciation, and amortization		(391,145	)			(256,629	)			(202,581	)
	Subtotal	$	1,248,081			$	1,016,201			$	876,227
	MEMP Segment:
	Evaluated oil and natural gas properties (1)	$	3,007,214			$	1,748,438			$	1,539,642
	Support equipment and facilities		185,997				5,910				5,760
	Unevaluated oil and natural gas properties		—				—				5,004
	Accumulated depletion, depreciation, and amortization (1)		(989,103	)			(416,617	)			(265,710	)
	Subtotal	$	2,204,108			$	1,337,731			$	1,284,696
	Eliminations:
	Accumulated depletion, depreciation, and amortization	$	46,013			$	49,884			$	—
	Consolidated:
	Evaluated oil and natural gas properties (1)	$	4,598,211			$	2,974,855			$	2,591,861
	Support equipment and facilities		185,997				5,910				5,760
	Unevaluated oil and natural gas properties		48,229				46,413				31,593
	Accumulated depletion, depreciation, and amortization (1)		(1,334,235	)			(623,362	)			(468,291	)
	Total	$	3,498,202			$	2,403,816			$	2,160,923

	-1	Amounts do not include costs for SPBPC and related support equipment.
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:
		For the Year Ended December 31,
		2014				2013				2012
		(In thousands)
	MRD Segment:
	Property acquisition costs, proved	$	74,490			$	56,108			$	87,857
	Property acquisition costs, unproved		25,030				19,975				5,293
	Exploration and extension well costs		209,532				13,313				212
	Development		208,459				210,440				135,951
	Subtotal	$	517,511			$	299,836			$	229,313
	MEMP Segment:
	Property acquisition costs, proved	$	983,076			$	37,786			$	278,246
	Exploration and extension well costs		—				—				42,430
	Development (1)		279,318				145,830				62,472
	Subtotal	$	1,262,394			$	183,616			$	383,148
	Consolidated:
	Property acquisition costs, proved	$	1,057,566			$	93,894			$	366,103
	Property acquisition costs, unproved		25,030				19,975				5,293
	Exploration and extension well costs		209,532				13,313				42,642
	Development (1)		487,777				356,270				198,423
	Total	$	1,779,905			$	483,452			$	612,461

	-1	Amounts do not include costs for SPBPC and related support equipment.
	Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
	As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
	Oil and Natural Gas Reserves
	Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
	Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
	We engaged NSAI and MEMP engaged NSAI and Ryder Scott to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.
	The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:
		2014				2013				2012
	Oil ($/Bbl)
	West Texas Intermediate (1)	$	91.48			$	93.42			$	91.33

	NGL ($/Bbl)
	West Texas Intermediate (1)	$	91.48			$	93.42			$	91.75

Natural Gas ($/Mmbtu)
Henry Hub (2)	$	4.35			$	3.67			$	2.75

-1	The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.
-2	The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
MRD Segment
The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively:
	For the Year Ended December 31, 2014
	Oil				Gas				NGLs				Equivalent
	(MBbls)				(MMcf)				(MBbls)				(MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		11,311				802,254				42,576				1,125,577
Extensions and discoveries		1,825				183,527				9,876				253,730
Purchase of minerals in place		269				22,186				1,247				31,283
Production		(951	)			(63,801	)			(2,220	)			(82,816	)
Sales of minerals in place		(623	)			(10,815	)			(950	)			(20,253	)
Revision of previous estimates		772				247,578				12,060				324,558
End of year		12,603				1,180,929				62,589				1,632,079

Proved developed reserves:
Beginning of year		3,402				263,797				13,904				367,641
End of year		3,905				392,181				19,924				535,151

Proved undeveloped reserves:
Beginning of year		7,909				538,457				28,672				757,936
End of year		8,698				788,748				42,665				1,096,928


	For the Year Ended December 31, 2013
	Oil				Gas				NGLs				Equivalent
	(MBbls)				(MMcf)				(MBbls)				(MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		11,953				739,378				41,466				1,059,895
Extensions and discoveries		1,794				149,974				8,319				210,652
Purchase of minerals in place		211				31,815				1,017				39,183
Production		(665	)			(34,092	)			(1,457	)			(46,819	)
Sales of minerals in place		(599	)			(14,137	)			(1,573	)			(27,169	)
Revision of previous estimates		(1,383	)			(70,684	)			(5,196	)			(110,165	)
End of year (1)		11,311				802,254				42,576				1,125,577

Proved developed reserves:
Beginning of year		3,082				245,449				12,321				337,869
End of year		3,402				263,797				13,904				367,641

Proved undeveloped reserves:
Beginning of year		8,871				493,929				29,145				722,026
End of year		7,909				538,457				28,672				757,936

-1		Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners.
-1

	For the Year Ended December 31, 2012
	Oil				Gas				NGLs				Equivalent
	(MBbls)				(MMcf)				(MBbls)				(MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		10,834				929,335				53,031				1,312,533
Extensions and discoveries		689				42,019				2,778				62,819
Purchase of minerals in place		1,100				28,115				1,879				45,987
Production		(369	)			(24,131	)			(898	)			(31,731	)
Sales of minerals in place		(4	)			(728	)			—				(752	)
Revision of previous estimates		(297	)			(235,232	)			(15,324	)			(328,961	)
End of year (1)		11,953				739,378				41,466				1,059,895

Proved developed reserves:
Beginning of year		2,107				191,557				7,644				250,073
End of year		3,082				245,449				12,321				337,869

Proved undeveloped reserves:
Beginning of year		8,727				737,778				45,387				1,062,460
End of year		8,871				493,929				29,145				722,026

-1		Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners.

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:
·	MRD had upward revisions of 324.6 Bcfe primarily due to well performance in East Texas and North Louisiana. Additionally, there was an increase of 253.7 Bcfe from extensions, primarily due to the redevelopment program in the Terryville Complex. MRD also acquired 31.3 Bcfe from multiple acquisitions already inside the Terryville Complex. Proved undeveloped reserves increased during the year primarily due to the development of unproved locations in 2014 and revisions to our forecasts for East Texas properties, which give effect for well performance using longer lateral lengths.
·	148.6 Bcfe of the increase in reserves for the year end December 31, 2013, through the category extensions and discoveries, was due to the horizontal redevelopment drilling program in the Terryville Complex.
·	WildHorse acquired 43.5 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Undisclosed Seller Acquisition. Downward revisions of previous estimates for estimated natural gas proved reserves was primarily the result of a decrease in natural gas prices.
See Note 3 for additional information on acquisitions and divestitures.
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
The standardized measure of discounted future net cash flows is as follows:
	For the Year Ended December 31,
	2014				2013				2012
	(In thousands)
Future cash inflows	$	8,313,329			$	5,722,848			$	4,921,192
Future production costs		(1,325,573	)			(1,587,374	)			(1,255,289	)
Future development costs		(1,443,612	)			(1,352,945	)			(1,060,777	)
Future income tax expense (1)		(1,789,031	)			—				—
Future net cash flows for estimated timing of cash flows		3,755,113				2,782,529				2,605,126
10% annual discount for estimated timing of cash flows		(1,792,579	)			(1,313,577	)			(1,284,531	)
Standardized measure of discounted future net cash flows (2)	$	1,962,534			$	1,468,952			$	1,320,595

-1	Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended December 31, 2013 and 2012.
-2	Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014:
	For the Year Ended December 31,
	2014				2013				2012
	(In thousands)
Beginning of year	$	1,468,952			$	1,320,595			$	1,386,071
Sale of oil and natural gas produced, net of production costs		(363,723	)			(196,444	)			(107,316	)
Purchase of minerals in place		69,282				51,177				98,384
Sale of minerals in place		(47,791	)			(54,091	)			—
Extensions and discoveries		653,186				301,004				127,994
Changes in income taxes, net		(1,058,814	)			—				—
Changes in prices and costs		365,030				(11,336	)			(402,202	)
Previously estimated development costs incurred		256,605				87,297				64,390
Net changes in future development costs		(126,598	)			57,353				(67,331	)
Revisions of previous quantities		828,296				(186,804	)			(176,788	)
Accretion of discount		146,896				128,544				138,607
Change in production rates and other		(228,787	)			(28,343	)			258,786
End of year	$	1,962,534			$	1,468,952			$	1,320,595
MEMP Segment
The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively:
	For the Year Ended December 31, 2014
	Oil				Gas				NGLs				Equivalent
	(MBbls)				(MMcf)				(MBbls)				(MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		39,149				607,139				28,846				1,015,105
Extensions and discoveries		849				12,723				711				22,085
Purchase of minerals in place		69,095				13,036				22,351				561,713
Production		(3,092	)			(41,494	)			(2,143	)			(72,902	)
Revision of previous estimates		(6,431	)			(31,777	)			(287	)			(72,090	)
End of year (1)		99,570				559,627				49,478				1,453,911

Proved developed reserves:
Beginning of year		22,265				387,548				15,959				616,893
End of year		54,526				380,397				35,539				920,783

Proved undeveloped reserves:
Beginning of year		16,884				219,591				12,887				398,212
End of year		45,044				179,230				13,939				533,128

(1) MRD Segment’s share of these reserves is 1,454 MMcfe.
	For the Year Ended December 31, 2013
	Oil				Gas				NGLs				Equivalent
	(MBbls)				(MMcf)				(MBbls)				(MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		39,089				604,440				29,352				1,015,095
Extensions and discoveries		5,655				40,770				1,747				85,180
Purchase of minerals in place		119				16,294				258				18,554
Production		(1,764	)			(35,924	)			(1,632	)			(56,303	)
Revision of previous estimates		(3,950	)			(18,441	)			(879	)			(47,421	)
End of year (1)		39,149				607,139				28,846				1,015,105

Proved developed reserves:
Beginning of year		24,515				376,932				15,947				619,704
End of year		22,265				387,548				15,959				616,893

Proved undeveloped reserves:
Beginning of year		14,574				227,508				13,405				395,391
End of year		16,884				219,591				12,887				398,212

(1) MRD Segment’s share of these reserves is 89,837 MMcfe.
	For the Year Ended December 31, 2012
	Oil				Gas				NGLs				Equivalent
	(MBbls)				(MMcf)				(MBbls)				(MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		27,150				579,751				15,045				832,913
Extensions and discoveries		7,501				19,869				1,053				71,192
Purchase of minerals in place		11,336				113,617				7,095				224,202
Production		(1,519	)			(29,744	)			(745	)			(43,329	)
Sales of minerals in place		(4,214	)			(4,214	)			—				(29,499	)
Revision of previous estimates		(1,165	)			(74,839	)			6,904				(40,384	)
End of year (1)		39,089				604,440				29,352				1,015,095

Proved developed reserves:
Beginning of year		19,332				413,431				10,015				589,504
End of year		24,515				376,932				15,947				619,704

Proved undeveloped reserves:
Beginning of year		7,818				166,320				5,030				243,409
End of year		14,574				227,508				13,405				395,391

(1) MRD Segment’s share of these reserves is 476,550 MMcfe.
Noteworthy amounts included in the categories of proved reserve changes in the above tables include:
·	MEMP acquired 561.7 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497.2 Bcfe. MEMP also acquired 45.0 Bcfe from the Eagle Ford Acquisition. Downward revision of natural gas for the year ended December 31, 2014 was primarily due to updated well performance data in certain East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition.
·	MEMP acquired 224.2 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Goodrich Acquisition of 148.9 Bcfe. Stanolind acquired 43.6 Bcfe through multiple acquisitions, the largest being the Menemsha Acquisition of 23.9 Bcfe. During the year ended December 31, 2012, Propel divested 19.0 Bcfe of offshore Louisiana oil and gas properties to an NGP controlled entity.
See Note 3 for additional information on acquisitions and divestitures.
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
The standardized measure of discounted future net cash flows is as follows:
	For the Year Ended December 31,
	2014				2013				2012
	(In thousands)
Future cash inflows	$	13,191,866			$	6,892,150			$	6,511,776
Future production costs		(4,516,077	)			(2,719,024	)			(2,258,554	)
Future development costs		(1,222,221	)			(685,858	)			(620,944	)
Future net cash flows for estimated timing of cash flows (1)		7,453,568				3,487,268				3,632,278
10% annual discount for estimated timing of cash flows		(4,693,960	)			(1,879,156	)			(2,042,362	)
Standardized measure of discounted future net cash flows (2)	$	2,759,608			$	1,608,112			$	1,589,916

-1	MEMP is subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the years ended December 31, 2014, 2013 and 2012.
-2	MRD Segment’s share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014:
	For the Year Ended December 31,
	2014				2013				2012
	(In thousands)
Beginning of year	$	1,608,112			$	1,589,916			$	1,499,414
Sale of oil and natural gas produced, net of production costs		(323,994	)			(234,520	)			(160,023	)
Purchase of minerals in place		1,489,477				23,160				375,953
Sale of minerals in place		—				—				(154,963	)
Extensions and discoveries		44,745				136,423				265,108
Changes in income taxes, net		—				—				1,947
Changes in prices and costs		(168,500	)			(74,395	)			(331,760	)
Previously estimated development costs incurred		223,861				174,490				66,360
Net changes in future development costs		(74,579	)			(74,867	)			(1,140	)
Revisions of previous quantities		(163,207	)			(141,122	)			(90,587	)
Accretion of discount		160,811				158,991				150,136
Change in production rates and other		(37,118	)			50,036				(30,529	)
End of year	$	2,759,608			$	1,608,112			$	1,589,916

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Note 20. Subsequent Events
	Termination of WHR Management Company Service Agreement
	For additional information, see Note 13.
	2015 Repurchases of MRD Common Stock and MEMP Common Units
	For additional information, see Note 9.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

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.

The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering.

Initial Public Offering and Restructuring Transactions

On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering:

The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC;

WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015;

Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014;

MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources;

We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco;

We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes;

Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources;

We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources;

We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes;

Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption;

MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating;

MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014;

We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and

MRD LLC merged into MRD Operating.

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer collectively to:

Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions in October 2013 from certain affiliates of NGP. In October 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds.

A 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 the 2010 Petrohawk and Clayton Williams acquisitions, 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 audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) 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.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows:

MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.

MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries.

Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes:

acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013;

acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013;

acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013;

acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013;

acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and

acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million.

Use of Estimates

The preparation of 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 and incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Principles of Consolidation and Combination

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

Book Overdrafts

Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.

Concentrations of Credit Risk

Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2014 and 2013, respectively.

If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012.

Oil and Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2014. MEMP engaged NSAI and Ryder Scott Company, L.P. to audit MEMP’s internally prepared reserves estimates for all of MEMP’s proved reserves (by volume) at December 31, 2014.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property & Equipment

Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years.

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. 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. Impairment expense for the years ended December 31, 2014, 2013, and 2012 was approximately $432.1 million, $6.6 million, $28.9 million, respectively. See Note 4 for further discussion on impairments.

Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.

Debt Issuance Costs

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013, and 2012 was approximately $7.4 million, $8.3 million and $3.6 million, respectively.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2014 or 2013.

The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:

Years Ending December 31,

2014

2013

2012

Consolidated & Combined:

Energy Transfer Equity, L.P. and subsidiaries

MRD Segment:

Energy Transfer Equity, L.P. and subsidiaries

Sunoco, Inc. (1)

n/a

Dominion Gas Ventures LP

n/a

MEMP Segment:

Sinclair Oil & Gas Company

n/a

Phillips 66 (2)

ConocoPhillips

n/a

-1

Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012.

-2

Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we capitalized $7.3 million of interest. We did not capitalize any interest in 2013 or 2012.

Income Tax

Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal 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 Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than 50% chance of being realized.

The evaluation of uncertain tax positions is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

The Company has no liability for unrecognized tax benefits as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2014. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.

In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders.

Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates. See Note 15 for additional information.

Earnings Per Share

Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information.

Incentive Based Compensation Arrangements

The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest.

Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.

In connection with the restructuring transactions, the MRD LLC 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. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period.

See Notes 11 and 12 for further information.

Accrued Liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

December 31,

2014

2013

Accrued capital expenditures

80,350

48,579

Accrued lease operating expense

16,403

13,240

Accrued general and administrative expenses

8,516

14,485

Accrued ad valorem and production taxes

8,870

3,541

Accrued interest payable

24,797

11,934

Accrued environmental

2,092

577

Accrued current deferred income taxes

51,929

382

Other miscellaneous, including operator advances

6,043

5,392

199,000

98,130

Supplemental Cash Flow Information

Supplemental cash flow for the periods presented (in thousands):

For Year Ended December 31,

2014

2013

2012

Supplemental cash flows:

Cash paid for interest, net of amounts capitalized

130,732

61,140

23,525

Income tax paid

838

168

Noncash investing and financing activities:

Change in capital expenditures in payables and accrued liabilities

31,771

41,017

17,158

Assumptions of asset retirement obligations related to properties acquired or drilled

5,420

4,227

7,962

Contribution of oil and gas properties from NGP affiliate

—

6,893

Accrued distribution to NGP affiliates related to Cinco Group acquisitions

—

4,352

—

Contribution related to sale of assets to NGP affiliate - restricted cash

—

2,013

Accrued equity offering costs

—

171

Distributions to noncontrolling interests

—

Repurchase of equity under repurchase program

3,425

—

Accounts receivable related to acquisitions

9,569

—

New Accounting Pronouncements

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Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2014
Accounting Policies [Abstract]
Individual Customers Each Accounted for 10% or More of Total Reported Revenues	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:
		Years Ending December 31,
		2014			2013			2012
	Consolidated & Combined:
	Energy Transfer Equity, L.P. and subsidiaries		33	%		35	%		13	%

	MRD Segment:
	Energy Transfer Equity, L.P. and subsidiaries		73	%		77	%		39	%
	Sunoco, Inc. (1)	n/a			n/a				15	%
	Dominion Gas Ventures LP	n/a			n/a				15	%

	MEMP Segment:
	Sinclair Oil & Gas Company		12	%	n/a			n/a
	Phillips 66 (2)		13	%		15	%		13	%
	ConocoPhillips	n/a			n/a				14	%

	-1	Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012.
	-2	Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.
Schedule of Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands):

		December 31,
		2014			2013
	Accrued capital expenditures	$	80,350		$	48,579
	Accrued lease operating expense		16,403			13,240
	Accrued general and administrative expenses		8,516			14,485
	Accrued ad valorem and production taxes		8,870			3,541
	Accrued interest payable		24,797			11,934
	Accrued environmental		2,092			577
	Accrued current deferred income taxes		51,929			382
	Other miscellaneous, including operator advances		6,043			5,392
		$	199,000		$	98,130

Schedule of Supplemental Cash flow	Supplemental cash flow for the periods presented (in thousands):
		For Year Ended December 31,
		2014			2013			2012
	Supplemental cash flows:
	Cash paid for interest, net of amounts capitalized	$	130,732		$	61,140		$	23,525
	Income tax paid		838			168			22
	Noncash investing and financing activities:
	Change in capital expenditures in payables and accrued liabilities		31,771			41,017			17,158
	Assumptions of asset retirement obligations related to properties acquired or drilled		5,420			4,227			7,962
	Contribution of oil and gas properties from NGP affiliate		—			—			6,893
	Accrued distribution to NGP affiliates related to Cinco Group acquisitions		—			4,352			—
	Contribution related to sale of assets to NGP affiliate - restricted cash		—			—			2,013
	Accrued equity offering costs		—			—			171
	Distributions to noncontrolling interests		—			—			47
	Repurchase of equity under repurchase program		3,425			—			—
	Accounts receivable related to acquisitions		9,569			—			—

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
Acquisitions and Divestitures (Tables)	Dec. 31, 2014
Acquisition-Related Costs	Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):
	For the Year Ended December 31,
	2014				2013				2012
	$	6,668			$	8,313			$	4,538

Unaudited Pro Forma Results of Operations	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the 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 Year Ended December 31,
		2014				2013
		(In thousands, except per share amounts)
	Revenues	$	990,544			$	761,443
	Net income (loss)		(602,044	)			257,839
	Basic earnings per share	$	(4.08	)		$	—
	Diluted earnings per share	$	(4.08	)		$	—

Eagle Ford and Wyoming Acquisition [Member]
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed	The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition dates (in thousands):
		MRD				MEMP				MEMP
		Louisiana				Eagle Ford				Wyoming
		Acquisition				Acquisition				Acquisition
	Oil and gas properties	$	72,141			$	168,606			$	930,168
	Asset retirement obligations		(271	)			(285	)			(3,980	)
	Revenue Payable		—				—				(375	)
	Accrued liabilities		—				(250	)			(19,693	)
	Total identifiable net assets	$	71,870			$	168,071			$	906,120

2013 Acquisitions [Member]
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed		Louisiana				East Texas				Rockies
		Acquisition				Acquisition				Acquisition
	Oil and gas properties	$	68,887			$	9,974			$	20,744
	Asset retirement obligation		(1,789	)			(78	)			(1,163	)
	Accrued liabilities		-				-				(118	)
	Total identifiable net assets	$	67,098			$	9,896			$	19,463

2012 Acquisitions [Member]
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed	The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands).

		Undisclosed Seller				Goodrich				Menemsha			Other
		Acquisition				Acquisition				Acquisition			Acquisitions
	Oil and gas properties	$	115,633			$	91,187			$	75,114		$	77,764
	Prepaid expenses and other current assets		—				425				—			—
	Revenues payable		(1,602	)			(875	)			—			—
	Asset retirement obligation		(1,592	)			(161	)			(408	)		(4,558	)
	Accrued liabilities		(297	)			(153	)			—			—
	Total identifiable net assets	$	112,142			$	90,423			$	74,706		$	73,206

Unaudited Pro Forma Results of Operations	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from our historical combined statements of operations 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 acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
	Revenue	$	431,060
	Net income		40,940

Fair_Value_Measurements_of_Fin1

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
Fair Value Measurements of Financial Instruments (Tables)	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013 for each of the fair value hierarchy levels:
		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
		Fair Value Measurements at December 31, 2013 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	$	—	$	105,054	$	—	$	105,054
	Interest rate derivatives		—		884		—		884
	Total assets	$	—	$	105,938	$	—	$	105,938

	Liabilities:
	Commodity derivatives	$	—	$	58,234	$	—	$	58,234
	Interest rate derivatives		—		5,590		—		5,590
	Total liabilities	$	—	$	63,824	$	—	$	63,824

Risk_Management_and_Derivative1

Risk Management and Derivative Instruments (Tables)	12 Months Ended
Risk Management and Derivative Instruments (Tables)	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Open Commodity Positions	At December 31, 2014, the MRD Segment had the following open commodity positions:
		2015				2016				2017				2018
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		3,700,000				2,570,000				1,770,000				2,900,000
	Weighted-average fixed price	$	4.15			$	4.09			$	4.24			$	4.27

	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			$	—

	Natural gas put option contracts:
	Average Monthly Volume (MMBtu)		3,000,000				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	$	(0.33	)		$	(0.36	)		$	(0.35	)		$	(0.35	)

	TGT Z1 basis swaps:
	Average Monthly Volume (MMBtu)		1,730,000				220,000				200,000				—
	Spread - Henry Hub	$	(0.09	)		$	(0.08	)		$	(0.08	)		$	—

	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		46,500				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			$	—			$	—

	Put option contracts:
	Average Monthly Volume (Bbls)		26,000				—				—				—
	Weighted-average fixed price	$	85			$	—			$	—			$	—
	Weighted-average deferred premium	$	(3.80	)		$	—			$	—			$	—

	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		151,000				185,658				—				—
	Weighted-average fixed price	$	41.61			$	34.06			$	—			$	—

	At December 31, 2014, the MEMP Segment had the following open commodity positions:
		2015				2016				2017				2018				2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		2,605,278				2,692,442				2,450,067				2,160,000				1,914,583
	Weighted-average fixed price	$	4.28			$	4.4			$	4.31			$	4.51			$	4.75

	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)		2,940,000				2,508,333				415,000				115,000				—
	Spread	$	(0.12	)		$	(0.04	)		$	0			$	0.15			$	—

	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
Average Monthly Volume (Bbls)		314,281				332,813				326,600				312,000				160,000
Weighted-average fixed price	$	90.96			$	85.83			$	84.38			$	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)		97,500				95,000				—				—				—
Spread	$	(7.07	)		$	(9.56	)		$	—			$	—			$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		149,200				84,600				—				—				—
Weighted-average fixed price	$	43.02			$	41.49			$	—			$	—			$	—

-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:
	2015				2016				2017				2018
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,280,000				2,103,333				300,000				—
Spread - Henry Hub	$	(0.11	)		$	(0.06	)		$	(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)		57,500				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 December 31, 2014, we had the following interest rate swap open positions:
	Credit Facility	2015				2016				2017
	MEMP:
	Average Monthly Notional (in thousands)	$	314,167			$	250,000			$	250,000
	Weighted-average fixed rate		1.349	%			1.029	%			1.62	%
	Floating rate	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 December 31, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our collective credit agreements.

					Asset Derivatives								Liability Derivatives
	Type		Balance Sheet Location		2014				2013				2014				2013
					(In thousands)
	Commodity contracts		Short-term derivative instruments		$	378,908			$	21,759			$	38,852			$	19,739
	Interest rate swaps		Short-term derivative instruments			—				845				3,289				3,287
	Gross fair value					378,908				22,604				42,141				23,026
	Netting arrangements		Short-term derivative instruments			(38,852	)			(13,315	)			(38,852	)			(13,315	)
	Net recorded fair value		Short-term derivative instruments		$	340,056			$	9,289			$	3,289			$	9,711

	Commodity contracts		Long-term derivative instruments		$	466,851			$	83,295			$	32,787			$	38,495
	Interest rate swaps		Long-term derivative instruments			1,305				39				—				2,303
	Gross fair value					468,156				83,334				32,787				40,798
	Netting arrangements		Long-term derivative instruments			(32,787	)			(34,718	)			(32,787	)			(34,718	)
	Net recorded fair value		Long-term derivative instruments		$	435,369			$	48,616			$	—			$	6,080

Schedule of Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the years ending December 31, 2014, 2013, and 2012:
			Statements of		For the Years Ended December 31,
			Operations Location		2014				2013				2012
					(In thousands)
	Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(749,988	)		$	(29,294	)		$	(34,905	)
	Interest rate derivatives		Interest expense, net			145				(239	)			5,582

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2014
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 years ended December 31, 2014, 2013 and 2012:
		2014			2013			2012
		(In thousands)
	Asset retirement obligations at beginning of period	$	111,769		$	102,380		$	90,699
	Liabilities added from acquisitions or drilling		5,420			4,227			7,962
	Liabilities removed upon sale of wells		(669	)		(1,765	)		(1,931	)
	Liabilities removed upon plugging and abandoning		(588	)		(170	)		(119	)
	Revisions		293			1,516			760
	Accretion expense		6,306			5,581			5,009
	Asset retirement obligations at end of period		122,531			111,769			102,380
	Less: Current portion		—			90			390
	Asset retirement obligations— long-term portion	$	122,531		$	111,679		$	101,990

Restricted_Investments_Tables

Restricted Investments (Tables)	12 Months Ended
Restricted Investments (Tables)	Dec. 31, 2014
Schedule Of Investments [Abstract]
Restricted Investment Balance	The components of the restricted investment balance are as follows at December 31, 2014 and 2013:
		2014		2013
		(In thousands)
	BOEM platform abandonment (See Note 16)	$	69,954	$	66,373
	BOEM lease bonds		794		794

	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,701		2,306
	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	$	77,361	$	73,385

Long_Term_Debt_Tables

Long Term Debt (Tables)	12 Months Ended
Long Term Debt (Tables)	Dec. 31, 2014
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated. The MEMP Segment debt included in the table below is nonrecourse to the Company.
		December 31,			December 31,
		2014			2013
		(In thousands)
	MRD Segment:
	MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	183,000		$	—
	WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014		—			203,100
	WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014		—			325,000
	10.00%/10.75% senior PIK toggle notes redeemed June 2014		—			350,000
	5.875% senior unsecured notes, due July 2022 (1)		600,000			—
	10.00%/10.75% senior PIK toggle notes unamortized discounts		—			(6,950	)
	Subtotal		783,000			871,150

	MEMP Segment:
	MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		412,000			103,000
	7.625% senior notes, fixed-rate, due May 2021 (2)		700,000			700,000
	6.875% senior unsecured notes, due August 2022 (3)		500,000			—
	Unamortized discounts		(16,587	)		(10,933	)
	Subtotal		1,595,413			792,067
	Total long-term debt	$	2,378,413		$	1,663,217

	-1	The estimated fair value of this fixed-rate debt was $534.0 million at December 31, 2014. 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 $563.5 million and $721.0 million at December 31, 2014 and 2013, 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 $380.0 million at December 31, 2014. 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 MRD’s and MEMP’s revolving credit facility was the following at the date indicated:
		December 31,
		2014
	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		1,440,000

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 and combined variable-rate debt obligations for the periods presented:
		For the Year Ended December 31,
		2014			2013			2012
	MRD Segment:
	MRD revolving credit facility		1.99	%	n/a			n/a
	MRD LLC revolver terminated December 2013	n/a				3.17	%		4.11	%
	Classic revolving credit facility terminated November 2012	n/a			n/a				4.5	%
	WildHorse Resources revolver terminated June 2014		4.04	%		2.3	%		3	%
	WildHorse Resources second lien terminated June 2014		6.44	%		7.6	%	n/a
	Black Diamond terminated November 2013	n/a				3.97	%		3.62	%
	MEMP Segment:
	MEMP revolving credit facility		2.67	%		3.25	%		2.74	%
	WHT revolver terminated March 2013	n/a				2.29	%		2.6	%
	Tanos revolver terminated April 2013	n/a				3.1	%		2.31	%
	REO revolving credit facility terminated December 2012	n/a			n/a				3.4	%
	Stanolind revolver paid off by MEMP October 2013	n/a				3.52	%		3.76	%
	Boaz revolver terminated October 2013	n/a				2.97	%		3.12	%
	Crown revolver terminated October 2013	n/a				3.38	%		4.2	%
	Propel Energy revolver paid off by MEMP October 2013	n/a				3.08	%		3.28	%

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:
		December 31,			December 31,
		2014			2013
		(In thousands)
	MRD Segment:
	MRD revolving credit facility	$	4,285		$	—
	MRD senior notes		12,455			—
	WildHorse Resources revolving credit facility		—			2,436
	WildHorse Resources second lien term loan		—			9,030
	PIK notes		—			8,261
	MEMP Segment:
	MEMP revolving credit facility		6,468			5,413
	2021 Senior Notes		13,308			15,053
	2022 Senior Notes		7,958			—
		$	44,474		$	40,193

Stockholders_Equity_and_Noncon1

Stockholders' Equity and Noncontrolling Interests (Tables)	12 Months Ended
Stockholders' Equity and Noncontrolling Interests (Tables)	Dec. 31, 2014
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 year ended December 31, 2014:
	Balance January 1, 2014	—
	Shares of common stock issued in connection with restructuring transactions (Note 1)	171,000,000
	Shares of common stock issued in initial public offering (Note 1)	21,500,000
	Shares of common stock repurchased and retired	(123,797	)
	Restricted common shares issued (Note 11)	1,068,422
	Restricted common shares forfeited	(9,211	)
	Balance December 31, 2014	193,435,414

Earnings_per_Share_Tables

Earnings per Share (Tables)	12 Months Ended
Earnings per Share (Tables)	Dec. 31, 2014
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 period indicated (in thousands, except per share amounts):
		For the Year Ended December 31,
		2014
	Numerator:
	Net income (loss) available to common stockholders	$	(784,581	)

	Denominator:
	Weighted average common shares outstanding		192,498

	Basic EPS	$	(4.08	)
	Diluted EPS (1)	$	(4.08	)

	-1	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014.
Supplemental EPS [Member]
Summary of Calculation of Earnings (Loss) Per Share, or EPS	The following sets forth the calculation of our supplemental EPS, for the period indicated (in thousands, except per share amounts):
		For the Year Ended December 31,
		2014
	Numerator:
	Net income (loss) attributable to Memorial Resource Development Corp.	$	(762,851	)

	Denominator:
	Weighted average common shares outstanding		192,498

	Basic EPS	$	(3.96	)
	Diluted EPS (1)	$	(3.96	)

	-1	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014.

LongTerm_Incentive_Plans_Table

Long-Term Incentive Plans (Tables)	12 Months Ended
Long-Term Incentive Plans (Tables)	Dec. 31, 2014
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 MRD LTIP for the periods presented:
		Number of Shares				Weighted-Average Grant Date Fair Value per Share (1)
	Restricted common shares outstanding at January 1, 2014		—			$	—
	Granted (2)		1,068,422			$	19
	Forfeited		(9,211	)		$	19
	Restricted common units outstanding at December 31, 2014		1,059,211			$	19

	-1	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
	-2	The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on grant date market price of $19.00 per share.
	The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented:
		Number of Units				Weighted-Average Grant Date Fair Value per Unit (1)
	Restricted common units outstanding at December 31, 2011		—			$	—
	Granted (2)		287,943			$	18.07
	Forfeited		(2,334	)		$	17.14
	Restricted common units outstanding at December 31, 2012		285,609			$	18.08
	Granted (3)		524,718			$	18.83
	Forfeited		(11,734	)		$	17.24
	Vested		(91,666	)		$	18.31
	Restricted common units outstanding at December 31, 2013		706,927			$	18.62
	Granted (4)		684,954			$	22.39
	Forfeited		(38,294	)		$	20.54
	Vested		(260,067	)		$	18.56
	Restricted common units outstanding at December 31, 2014		1,093,520			$	20.93

	·	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
	·	The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit.
	-3	The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit.
	-4	The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 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 Year Ended December 31,
	2014
	$	2,804

	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 Year Ended December 31,
	2014				2013			2012
	$	7,874			$	3,558		$	1,423

Incentive_Units_Tables

Incentive Units (Tables)	12 Months Ended
Incentive Units (Tables)	Dec. 31, 2014
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	12/31/14			12/31/14
	Dividend yield		0	%		0	%
	Expected volatility		39.54	%		39.54	%
	Risk-free rate		0.85	%		0.85	%
	Expected life (years)		2.41			2.41

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2014
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

	MEMP recorded the following net assets (in thousands):
	Cash and cash equivalents	$	6,021
	Accounts receivable		16,284
	Short-term derivative instruments, net		2,926
	Prepaid expenses and other current assets		4,521
	Oil and natural gas properties, net		108,342
	Restricted investments		68,009
	Accounts payable		(9,092	)
	Accrued liabilities		(9,140	)
	Asset retirement obligations		(58,746	)
	Credit facilities		(28,500	)
	Deferred tax liability		(1,674	)
	Noncontrolling interest		(5,255	)
	Net assets	$	93,696

Book Value of Assets Sold	The Cinco Group 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.
	Cash and cash equivalents	$	2,820
	Accounts receivable		5,184
	Prepaid expenses and other current assets		1,454
	Oil and natural gas properties, net		342,759
	Long-term derivative instruments, net		(826	)
	Other long-term assets		344
	Accounts payable		(2,346	)
	Revenue payable		(2,910	)
	Accrued liabilities		(1,799	)
	Short-term derivative instruments, net		(1,828	)
	Asset retirement obligations		(9,606	)
	Credit facilities		(151,690	)
	Net assets	$	181,556

	The net book value of the assets sold was as follows (in thousands):
	Cash and cash equivalents	$	33,001
	Restricted cash		300
	Accounts receivable		5,256
	Prepaid expenses and other current assets		379
	Property, plant and equipment, net		3,410
	Other long-term assets		4
	Accounts payable		(19,959	)
	Accounts payable - affiliates		(17,099	)
	Accrued liabilities		(5,061	)
	Net assets	$	231

Business_Segment_Data_Tables

Business Segment Data (Tables)	12 Months Ended
Business Segment Data (Tables)	Dec. 31, 2014
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 Year ended December 31, 2014	$	405,286			$	494,105			$	(46	)		$	899,345
	For the Year ended December 31, 2013		231,558				343,616				(151	)			575,023
	For the Year ended December 31, 2012		138,814				258,423				(369	)			396,868
	Adjusted EBITDA: (1)
	For the Year ended December 31, 2014		343,976				309,901				(6,144	)			647,733
	For the Year ended December 31, 2013		197,903				222,185				(25,232	)			394,856
	For the Year ended December 31, 2012		132,105				179,334				(23,447	)			287,992
	Segment assets: (2)
	As of December 31, 2014		1,632,313				2,930,559				30,675				4,593,547
	As of December 31, 2013		1,281,134				1,552,307				(4,280	)			2,829,161
	Total cash expenditures for additions to long-lived assets:
	For the Year ended December 31, 2014		521,038				1,348,095				—				1,869,133
	For the Year ended December 31, 2013		267,870				200,577				—				468,447
	For the Year ended December 31, 2012		249,526				387,160				—				636,686

	-1	Adjustments and eliminations for the years ended December 31, 2014, 2013 and 2012 include amounts related to the MRD Segment’s equity investments in the MEMP Segment as well the elimination of $6.1 million, $26.0 million and $19.3 million of cash distributions that MEMP paid MRD Segment for the years ended December 31, 2014, 2013 and 2012, respectively, related to MRD Segment’s partnership interests in MEMP.
	-2	Adjustments and eliminations primarily represent the elimination of the MRD Segment’s equity investments in the MEMP Segment. The adjustment at December 31, 2014 and 2013 also includes $46.0 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013. This impairment did not exist on a consolidated basis.
Schedule of Calculation of Reportable Segment's Adjusted EBITDA	Calculation of Reportable Segments’ Adjusted EBITDA
		For the Year Ended December 31, 2014
										Combined
		MRD				MEMP				Totals
		(In thousands)
	Net income (loss)	$	(762,926	)		$	118,079			$	(644,847	)
	Interest expense, net		50,283				83,550				133,833
	Loss on extinguishment of debt		37,248				—				37,248
	Income tax expense (benefit)		99,850				1,121				100,971
	DD&A		154,917				155,404				310,321
	Impairment of proved oil and natural gas properties		24,576				407,540				432,116
	Accretion of AROs		688				5,618				6,306
	(Gain) loss on commodity derivative instruments		(257,734	)			(492,254	)			(749,988	)
	Cash settlements received (paid) on commodity derivative instruments		9,166				13,522				22,688
	(Gain) loss on sale of properties		3,057				—				3,057
	Acquisition related costs		2,305				4,363				6,668
	Incentive-based compensation expense		946,753				7,874				954,627
	Exploration costs		15,813				790				16,603
	Provision for environmental remediation		—				2,852				2,852
	Loss on office lease		1,180				1,442				2,622
	Non-cash equity (income) loss from MEMP		12,656				—				12,656
	Cash distributions from MEMP		6,144				—				6,144
	Adjusted EBITDA	$	343,976			$	309,901			$	653,877

		For the Year Ended December 31, 2013
										Combined
		MRD				MEMP				Totals
						(In thousands)
	Net income (loss)	$	82,243			$	20,268			$	102,511
	Interest expense, net		27,349				41,901				69,250
	Income tax expense (benefit)		1,311				308				1,619
	DD&A		87,043				97,269				184,312
	Impairment of proved oil and natural gas properties		2,527				54,362				56,889
	Accretion of AROs		728				4,853				5,581
	(Gain) loss on commodity derivative instruments		(3,013	)			(26,281	)			(29,294	)
	Cash settlements received (paid) on commodity derivative instruments		12,240				19,879				32,119
	(Gain) loss on sale of properties		(82,773	)			(2,848	)			(85,621	)
	Acquisition related costs		1,584				6,729				8,313
	Incentive-based compensation expense		43,279				3,558				46,837
	Non-cash compensation expense		—				1,057				1,057
	Exploration costs		1,226				1,130				2,356
	Non-cash equity (income) loss from MEMP		(1,847	)			—				(1,847	)
	Cash distributions from MEMP		26,006				—				26,006
	Adjusted EBITDA	$	197,903			$	222,185			$	420,088

		For the Year Ended December 31, 2012
										Combined
		MRD				MEMP				Totals
						(In thousands)
	Net income (loss)	$	(14,641	)		$	46,518			$	31,877
	Interest expense, net		12,802				20,436				33,238
	Income tax expense (benefit)		(178	)			285				107
	DD&A		62,636				76,036				138,672
	Impairment of proved oil and natural gas properties		18,339				10,532				28,871
	Accretion of AROs		632				4,377				5,009
	(Gain) loss on commodity derivative instruments		(13,488	)			(21,417	)			(34,905	)
	Cash settlements received (paid) on commodity derivative instruments		30,188				44,111				74,299
	(Gain) loss on sale of properties		(2	)			(9,759	)			(9,761	)
	Acquisition related costs		403				4,135				4,538
	Incentive-based compensation expense		9,510				1,423				10,933
	Amortization of investment premium		—				194				194
	Exploration costs		7,337				2,463				9,800
	Non-cash equity (income) loss from MEMP		(696	)			—				(696	)
	Cash distributions from MEMP		19,263				—				19,263
Adjusted EBITDA	$	132,105			$	179,334			$	311,439

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 Year Ended December 31,
		2014				2013				2012
	Total Reportable Segments' Adjusted EBITDA	$	653,877			$	420,088			$	311,439
	Adjustments to reconcile Adjusted EBITDA to net income (loss):
	Interest expense, net		(133,833	)			(69,250	)			(33,238	)
	Loss on extinguishment of debt		(37,248	)			—				—
	Income tax benefit (expense)		(100,971	)			(1,619	)			(107	)
	DD&A		(314,193	)			(184,717	)			(138,672	)
	Impairment of proved oil and natural gas properties		(432,116	)			(6,600	)			(28,871	)
	Accretion of AROs		(6,306	)			(5,581	)			(5,009	)
	Gains (losses) on commodity derivative instruments		749,988				29,294				34,905
	Cash settlements paid (received) on commodity derivative instruments		(22,688	)			(32,119	)			(74,299	)
	Gain (loss) on sale of properties		(3,057	)			85,621				9,761
	Acquisition related costs		(6,668	)			(8,313	)			(4,538	)
	Incentive-based compensation expense		(954,627	)			(46,837	)			(10,933	)
	Non-cash compensation expense		—				(1,057	)			—
	Exploration costs		(16,603	)			(2,356	)			(9,800	)
	Amortization of investment premium		—				—				(194	)
	Cash distributions from MEMP		(6,144	)			(26,006	)			(19,263	)
	Provision for environmental remediation		(2,852	)			—				—
	Loss on office lease		(2,622	)			—				—
	Other non-cash equity (income) loss		—				784				(4,184	)
	Net income (loss)	$	(636,063	)		$	151,332			$	26,997

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 Year Ended December 31, 2014
		MRD				MEMP				Other, Adjustments & Eliminations				Consolidated & Combined Totals
	Revenues:
	Oil & natural gas sales	$	404,718			$	490,249			$	—			$	894,967
	Other revenues		568				3,856				(46	)			4,378
	Total revenues		405,286				494,105				(46	)			899,345

	Costs and expenses:
	Lease operating		26,695				134,654				(46	)			161,303
	Pipeline operating		—				2,068				—				2,068
	Exploration		15,813				790				—				16,603
	Production and ad valorem taxes		14,150				31,601				—				45,751
	Depreciation, depletion, and amortization		154,917				155,404				3,872				314,193
	Impairment of proved oil and natural gas properties		24,576				407,540				—				432,116
	Incentive unit compensation expense		943,949				—				—				943,949
	General and administrative		42,054				45,619				—				87,673
	Accretion of asset retirement obligations		688				5,618				—				6,306
	(Gain) loss on commodity derivative instruments		(257,734	)			(492,254	)			—				(749,988	)
	(Gain) loss on sale of properties		3,057				—				—				3,057
	Other, net		—				(12	)			—				(12	)
	Total costs and expenses		968,165				291,028				3,826				1,263,019
	Operating income (loss)		(562,879	)			203,077				(3,872	)			(363,674	)
	Other income (expense):
	Interest expense, net		(50,283	)			(83,550	)			—				(133,833	)
	Loss on extinguishment of debt		(37,248	)			—				—				(37,248	)
	Earnings from equity investments		(12,656	)			—				12,656				—
	Other, net		(10	)			(327	)			—				(337	)
	Total other income (expense)		(100,197	)			(83,877	)			12,656				(171,418	)
	Income (loss) before income taxes		(663,076	)			119,200				8,784				(535,092	)
	Income tax benefit (expense)		(99,850	)			(1,121	)			—				(100,971	)
	Net income (loss)	$	(762,926	)		$	118,079			$	8,784			$	(636,063	)

		For the Year Ended December 31, 2013
		MRD				MEMP				Other, Adjustments & Eliminations				Consolidated & Combined Totals
	Revenues:
	Oil & natural gas sales	$	230,751			$	341,197			$	—			$	571,948
	Other revenues		807				2,419				(151	)			3,075
	Total revenues		231,558				343,616				(151	)			575,023

	Costs and expenses:
	Lease operating		25,006				88,893				(259	)			113,640
	Pipeline operating		—				1,835				—				1,835
	Exploration		1,226				1,130				—				2,356
	Production and ad valorem taxes		9,362				17,784				—				27,146
	Depreciation, depletion, and amortization		87,043				97,269				405				184,717
	Impairment of proved oil and natural gas properties		2,527				54,362				(50,289	)			6,600
	Incentive unit compensation expense		43,279				—				—				43,279
	General and administrative		38,479				43,495				105				82,079
	Accretion of asset retirement obligations		728				4,853				—				5,581
	(Gain) loss on commodity derivative instruments		(3,013	)			(26,281	)			—				(29,294	)
	(Gain) loss on sale of properties		(82,773	)			(2,848	)			—				(85,621	)
	Other, net		2				647				—				649
	Total costs and expenses		121,866				281,139				(50,038	)			352,967
	Operating income (loss)		109,692				62,477				49,887				222,056
	Other income (expense):
	Interest expense, net		(27,349	)			(41,901	)			—				(69,250	)
	Earnings from equity investments		1,066				—				(1,066	)			—
	Other, net		145				—				—				145
	Total other income (expense)		(26,138	)			(41,901	)			(1,066	)			(69,105	)
	Income before income taxes		83,554				20,576				48,821				152,951
	Income tax benefit (expense)		(1,311	)			(308	)			—				(1,619	)
	Net income (loss)	$	82,243			$	20,268			$	48,821			$	151,332


	For the Year Ended December 31, 2012
	MRD				MEMP				Other, Adjustments & Eliminations				Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	138,032			$	255,608			$	(9	)		$	393,631
Other revenues		782				2,815				(360	)			3,237
Total revenues		138,814				258,423				(369	)			396,868

Costs and expenses:
Lease operating		24,438				80,116				(800	)			103,754
Pipeline operating		—				2,114				—				2,114
Exploration		7,337				2,463				—				9,800
Production and ad valorem taxes		7,576				16,048				—				23,624
Depreciation, depletion, and amortization		62,636				76,036				—				138,672
Impairment of proved oil and natural gas properties		18,339				10,532				—				28,871
Incentive unit compensation expense		9,510				—				—				9,510
General and administrative		28,904				30,342				431				59,677
Accretion of asset retirement obligations		632				4,377				—				5,009
(Gain) loss on commodity derivative instruments		(13,488	)			(21,417	)			—				(34,905	)
(Gain) loss on sale of properties		(2	)			(9,759	)			—				(9,761	)
Other, net		364				138				—				502
Total costs and expenses		146,246				190,990				(369	)			336,867
Operating income (loss)		(7,432	)			67,433				—				60,001
Other income (expense):
Interest expense, net		(12,802	)			(20,436	)			—				(33,238	)
Amortization of investment premium		—				(194	)			—				(194	)
Earnings from equity investments		4,880				—				(4,880	)			—
Other, net		535				—				—				535
Total other income (expense)		(7,387	)			(20,630	)			(4,880	)			(32,897	)
Income before income taxes		(14,819	)			46,803				(4,880	)			27,104
Income tax benefit (expense)		178				(285	)			—				(107	)
Net income (loss)	$	(14,641	)		$	46,518			$	(4,880	)		$	26,997

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit)	Income tax benefit (expense) for the indicated periods is comprised of the following:
		For the Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Current taxes:
	Federal	$	—		$	—		$	—
	State		22			(1,619	)		178
	Deferred taxes:
	Federal		(88,994	)		—			—
	State		(11,999	)		—			(285	)
	Total income tax benefit (expense)	$	(100,971	)	$	(1,619	)	$	(107	)

Reconciliation of Income Tax Benefit (Provision)	The actual income tax benefit (expense) differs from the expected income tax benefit (provision) as computed by applying the federal statutory corporate tax rate of 35% for each period indicated as follows:
		For the Year Ended December 31,
		2014			2013			2012
	Expected tax benefit (expense)	$	187,282		$	(53,533	)	$	(9,486	)
	State income tax expense, net of federal benefit		(9,660	)		(1,619	)		(107	)
	Pass-through entities (1)		49,989			53,533			9,486
	Stock compensation (2)		(330,024	)		—			—
	Other		1,442			—			—
	Total income tax benefit (expense)	$	(100,971	)	$	(1,619	)	$	(107	)

Components of Net Deferred Income Tax Assets and (Liabilities)
	-1	MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes.
	-2	As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes.
	The components of net deferred income tax assets and (liabilities) recognized were as follows:
		December 31,
		2014			2013
		(In thousands)
	Deferred current income tax assets:
	Unrealized hedging transactions	$	109		$	37
	Accrued liabilities		—			5
	Other		342			(42	)
	Deferred current income tax assets:	$	451		$	—

	Deferred current income tax liabilities:
	Unrealized hedging transactions	$	(52,328	)		—
	Other		(52	)		(382	)
	Deferred current income tax liabilities:	$	(52,380	)	$	(382	)

	Deferred noncurrent income tax assets:
	Net operating loss carryforward	$	28,043		$	2,350
	Asset retirement obligation		5,757			971
	Other		3,224			1
	Net deferred tax valuation allowance		(2,634	)		(2,896	)
	Deferred noncurrent income tax assets:	$	34,390		$	426

	Deferred noncurrent income tax liabilities:
	Property, plant and equipment	$	(80,198	)	$	(3,318	)
	Unrealized hedging transactions		(48,929	)		(275	)
	Other		(280	)		61
	Deferred noncurrent income tax liabilities:	$	(129,407	)	$	(3,532	)

	Net current deferred income tax assets (liabilities)	$	(51,929	)	$	(382	)
	Net noncurrent deferred income tax assets (liabilities)	$	(95,017	)	$	(3,106	)

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2014
Environmental Reserves Activity	The following table presents the activity of our environmental reserves for the periods presented:
		2014				2013			2012
		(In thousands)
	Balance at beginning of period	$	577			$	1,469		$	1,747
	Charged to costs and expenses		2,852				—			193
	Payments		(1,337	)			(892	)		(471	)
	Balance at end of period	$	2,092			$	577		$	1,469

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

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 December 31, 2014 (in thousands):
		Amortized
	Investment	Cost
	U.S. Bank Money Market Cash Equivalent	$	135,176
	Less: Outside working interest owners share		(65,222	)
		$	69,954

Minimum Commitments to Gatherer before Other Owner Contributions	WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2014 were as follows (in thousands):
		Dubach				Dubberly
	2015	$	13,671			$	11,393
	2016		13,709				11,424
	2017		13,671				11,393
	2018		12,772				10,643
	Total	$	53,823			$	44,853

Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases	Amounts shown in the following table represent minimum lease payment obligations and sublease rental income under non-cancelable operating leases with a remaining term in excess of one year:
					Payment or Settlement due by Period
		Total				2015			2016			2017		2018		2019		Thereafter
		(In thousands)
	MRD Segment:
	Operating leases	$	43,625			$	6,534		$	6,607		$	6,694	$	6,259	$	5,960	$	11,571
	Sublease rental income		5,786				1,691			1,579			1,197		814		431		74
	MEMP Segment:
	Operating leases		3,665				788			416			205		205		205		1,846

Wyoming Acquisition [Member]
CO2 Minimum Purchase Commitment	At December 31, 2014, MEMP had a CO2 purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands):
					Payment or Settlement due by Period
	Purchase commitment	Total				2015			2016			2017		2018		2019		Thereafter

	CO2 minimum purchase commitment:
	Estimated payment obligation	$	50,495			$	9,608		$	10,179		$	10,151	$	6,995	$	7,060	$	6,502

Quarterly_Financial_Informatio1

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
Quarterly Financial Information (Unaudited) (Tables)	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 4 and Note 12, we recorded oil and natural gas property impairments and incentive unit compensation expense, respectively, during 2014, which impacted the comparability between the periods presented below.
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	For the Year Ended December 31, 2014	(In thousands, except per share amounts)
	Revenues	$	190,828		$	236,564		$	245,493		$	226,460
	Operating income (loss)		10,605			(993,256	)		174,201			444,776
	Net income (loss)		(23,516	)		(1,053,443	)		112,037			328,859
	Net income (loss) attributable to noncontrolling interest		(31,888	)		(105,094	)		102,109			161,661
	Net income (loss) attributable to Memorial Resource		8,372			(948,349	)		9,928			167,198
	Development Corp.		8,372			(948,349	)		9,928			167,198
	Net income (loss) allocated to members		6,947			13,358			—			—
	Net income (loss) allocated to previous owners		1,425			—			—			—
	Net income (loss) available to common stockholders	n/a				(961,707	)		9,928			167,198
	Basic earnings per share	n/a				(5.00	)		0.05			0.87
	Diluted earnings per share	n/a				(5.00	)		0.05			0.87

		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	For the Year Ended December 31, 2013	(In thousands, except per share amounts)
	Revenues	$	122,181		$	147,045		$	153,515		$	152,282
	Operating income (loss)		9,521			90,327			117,797			4,411
	Net income (loss)		180			78,158			95,962			(22,968	)
	Net income (loss) attributable to noncontrolling interest		(4,069	)		34,975			11,235			7,689
	Net income (loss) attributable to Memorial Resource		4,249			43,183			84,727			(30,657	)
	Development Corp.		4,249			43,183			84,727			(30,657	)
	Net income (loss) allocated to members		2,597			35,278			84,754			(31,917	)
	Net income (loss) allocated to previous owners		1,652			7,905			(27	)		1,260

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
Supplemental Oil and Gas Information (Unaudited) (Tables)	Dec. 31, 2014
Capitalized Costs Relating to Oil and Natural Gas Producing Activities	The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.
		For the Year Ended December 31,
		2014			2013			2012
		(In thousands)
	MRD Segment:
	Evaluated oil and natural gas properties	$	1,590,997		$	1,226,417		$	1,052,219
	Unevaluated oil and natural gas properties		48,229			46,413			26,589
	Accumulated depletion, depreciation, and amortization		(391,145	)		(256,629	)		(202,581	)
	Subtotal	$	1,248,081		$	1,016,201		$	876,227
	MEMP Segment:
	Evaluated oil and natural gas properties (1)	$	3,007,214		$	1,748,438		$	1,539,642
	Support equipment and facilities		185,997			5,910			5,760
	Unevaluated oil and natural gas properties		—			—			5,004
	Accumulated depletion, depreciation, and amortization (1)		(989,103	)		(416,617	)		(265,710	)
	Subtotal	$	2,204,108		$	1,337,731		$	1,284,696
	Eliminations:
	Accumulated depletion, depreciation, and amortization	$	46,013		$	49,884		$	—
	Consolidated:
	Evaluated oil and natural gas properties (1)	$	4,598,211		$	2,974,855		$	2,591,861
	Support equipment and facilities		185,997			5,910			5,760
	Unevaluated oil and natural gas properties		48,229			46,413			31,593
	Accumulated depletion, depreciation, and amortization (1)		(1,334,235	)		(623,362	)		(468,291	)
	Total	$	3,498,202		$	2,403,816		$	2,160,923

	-1	Amounts do not include costs for SPBPC and related support equipment.
Costs Incurred for Property Acquisitions, Exploration and Development	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:
		For the Year Ended December 31,
		2014			2013			2012
		(In thousands)
	MRD Segment:
	Property acquisition costs, proved	$	74,490		$	56,108		$	87,857
	Property acquisition costs, unproved		25,030			19,975			5,293
	Exploration and extension well costs		209,532			13,313			212
	Development		208,459			210,440			135,951
	Subtotal	$	517,511		$	299,836		$	229,313
	MEMP Segment:
	Property acquisition costs, proved	$	983,076		$	37,786		$	278,246
	Exploration and extension well costs		—			—			42,430
	Development (1)		279,318			145,830			62,472
	Subtotal	$	1,262,394		$	183,616		$	383,148
	Consolidated:
	Property acquisition costs, proved	$	1,057,566		$	93,894		$	366,103
	Property acquisition costs, unproved		25,030			19,975			5,293
	Exploration and extension well costs		209,532			13,313			42,642
	Development (1)		487,777			356,270			198,423
	Total	$	1,779,905		$	483,452		$	612,461

	-1	Amounts do not include costs for SPBPC and related support equipment.
Weighted Average Benchmark Product Prices	The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:
		2014			2013			2012
	Oil ($/Bbl)
	West Texas Intermediate (1)	$	91.48		$	93.42		$	91.33

	NGL ($/Bbl)
	West Texas Intermediate (1)	$	91.48		$	93.42		$	91.75

	Natural Gas ($/Mmbtu)
	Henry Hub (2)	$	4.35		$	3.67		$	2.75

	-1	The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.
	-2	The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
MRD [Member]
Reserve Quantity Information	The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively:
		For the Year Ended December 31, 2014
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of the year		11,311			802,254			42,576			1,125,577
	Extensions and discoveries		1,825			183,527			9,876			253,730
	Purchase of minerals in place		269			22,186			1,247			31,283
	Production		(951	)		(63,801	)		(2,220	)		(82,816	)
	Sales of minerals in place		(623	)		(10,815	)		(950	)		(20,253	)
	Revision of previous estimates		772			247,578			12,060			324,558
	End of year		12,603			1,180,929			62,589			1,632,079

	Proved developed reserves:
	Beginning of year		3,402			263,797			13,904			367,641
	End of year		3,905			392,181			19,924			535,151

	Proved undeveloped reserves:
	Beginning of year		7,909			538,457			28,672			757,936
	End of year		8,698			788,748			42,665			1,096,928


		For the Year Ended December 31, 2013
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of the year		11,953			739,378			41,466			1,059,895
	Extensions and discoveries		1,794			149,974			8,319			210,652
	Purchase of minerals in place		211			31,815			1,017			39,183
	Production		(665	)		(34,092	)		(1,457	)		(46,819	)
	Sales of minerals in place		(599	)		(14,137	)		(1,573	)		(27,169	)
	Revision of previous estimates		(1,383	)		(70,684	)		(5,196	)		(110,165	)
	End of year (1)		11,311			802,254			42,576			1,125,577

	Proved developed reserves:
	Beginning of year		3,082			245,449			12,321			337,869
	End of year		3,402			263,797			13,904			367,641

	Proved undeveloped reserves:
	Beginning of year		8,871			493,929			29,145			722,026
	End of year		7,909			538,457			28,672			757,936

	-1		Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners.
	-1

		For the Year Ended December 31, 2012
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of the year		10,834			929,335			53,031			1,312,533
	Extensions and discoveries		689			42,019			2,778			62,819
	Purchase of minerals in place		1,100			28,115			1,879			45,987
	Production		(369	)		(24,131	)		(898	)		(31,731	)
	Sales of minerals in place		(4	)		(728	)		—			(752	)
	Revision of previous estimates		(297	)		(235,232	)		(15,324	)		(328,961	)
	End of year (1)		11,953			739,378			41,466			1,059,895

	Proved developed reserves:
	Beginning of year		2,107			191,557			7,644			250,073
	End of year		3,082			245,449			12,321			337,869

	Proved undeveloped reserves:
	Beginning of year		8,727			737,778			45,387			1,062,460
	End of year		8,871			493,929			29,145			722,026

-1		Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners.

Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows:
		For the Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Future cash inflows	$	8,313,329		$	5,722,848		$	4,921,192
	Future production costs		(1,325,573	)		(1,587,374	)		(1,255,289	)
	Future development costs		(1,443,612	)		(1,352,945	)		(1,060,777	)
	Future income tax expense (1)		(1,789,031	)		—			—
	Future net cash flows for estimated timing of cash flows		3,755,113			2,782,529			2,605,126
	10% annual discount for estimated timing of cash flows		(1,792,579	)		(1,313,577	)		(1,284,531	)
	Standardized measure of discounted future net cash flows (2)	$	1,962,534		$	1,468,952		$	1,320,595

	-1	Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended December 31, 2013 and 2012.
	-2	Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively.
Summary of the Changes in the Standardized Measure of Future Net Cash Flows	The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014:
		For the Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Beginning of year	$	1,468,952		$	1,320,595		$	1,386,071
	Sale of oil and natural gas produced, net of production costs		(363,723	)		(196,444	)		(107,316	)
	Purchase of minerals in place		69,282			51,177			98,384
	Sale of minerals in place		(47,791	)		(54,091	)		—
	Extensions and discoveries		653,186			301,004			127,994
	Changes in income taxes, net		(1,058,814	)		—			—
	Changes in prices and costs		365,030			(11,336	)		(402,202	)
	Previously estimated development costs incurred		256,605			87,297			64,390
	Net changes in future development costs		(126,598	)		57,353			(67,331	)
	Revisions of previous quantities		828,296			(186,804	)		(176,788	)
	Accretion of discount		146,896			128,544			138,607
	Change in production rates and other		(228,787	)		(28,343	)		258,786
	End of year	$	1,962,534		$	1,468,952		$	1,320,595

MEMP [Member]
Reserve Quantity Information	The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively:
		For the Year Ended December 31, 2014
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of the year		39,149			607,139			28,846			1,015,105
	Extensions and discoveries		849			12,723			711			22,085
	Purchase of minerals in place		69,095			13,036			22,351			561,713
	Production		(3,092	)		(41,494	)		(2,143	)		(72,902	)
	Revision of previous estimates		(6,431	)		(31,777	)		(287	)		(72,090	)
	End of year (1)		99,570			559,627			49,478			1,453,911

	Proved developed reserves:
	Beginning of year		22,265			387,548			15,959			616,893
	End of year		54,526			380,397			35,539			920,783

	Proved undeveloped reserves:
	Beginning of year		16,884			219,591			12,887			398,212
	End of year		45,044			179,230			13,939			533,128

	(1) MRD Segment’s share of these reserves is 1,454 MMcfe.
		For the Year Ended December 31, 2013
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of the year		39,089			604,440			29,352			1,015,095
	Extensions and discoveries		5,655			40,770			1,747			85,180
	Purchase of minerals in place		119			16,294			258			18,554
	Production		(1,764	)		(35,924	)		(1,632	)		(56,303	)
	Revision of previous estimates		(3,950	)		(18,441	)		(879	)		(47,421	)
	End of year (1)		39,149			607,139			28,846			1,015,105

	Proved developed reserves:
	Beginning of year		24,515			376,932			15,947			619,704
	End of year		22,265			387,548			15,959			616,893

	Proved undeveloped reserves:
	Beginning of year		14,574			227,508			13,405			395,391
	End of year		16,884			219,591			12,887			398,212

	(1) MRD Segment’s share of these reserves is 89,837 MMcfe.
		For the Year Ended December 31, 2012
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of the year		27,150			579,751			15,045			832,913
	Extensions and discoveries		7,501			19,869			1,053			71,192
	Purchase of minerals in place		11,336			113,617			7,095			224,202
	Production		(1,519	)		(29,744	)		(745	)		(43,329	)
	Sales of minerals in place		(4,214	)		(4,214	)		—			(29,499	)
	Revision of previous estimates		(1,165	)		(74,839	)		6,904			(40,384	)
	End of year (1)		39,089			604,440			29,352			1,015,095

	Proved developed reserves:
	Beginning of year		19,332			413,431			10,015			589,504
	End of year		24,515			376,932			15,947			619,704

	Proved undeveloped reserves:
	Beginning of year		7,818			166,320			5,030			243,409
	End of year		14,574			227,508			13,405			395,391

	(1) MRD Segment’s share of these reserves is 476,550 MMcfe.
Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows:
		For the Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Future cash inflows	$	13,191,866		$	6,892,150		$	6,511,776
	Future production costs		(4,516,077	)		(2,719,024	)		(2,258,554	)
	Future development costs		(1,222,221	)		(685,858	)		(620,944	)
	Future net cash flows for estimated timing of cash flows (1)		7,453,568			3,487,268			3,632,278
	10% annual discount for estimated timing of cash flows		(4,693,960	)		(1,879,156	)		(2,042,362	)
	Standardized measure of discounted future net cash flows (2)	$	2,759,608		$	1,608,112		$	1,589,916

	-1	MEMP is subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the years ended December 31, 2014, 2013 and 2012.
	-2	MRD Segment’s share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively.
Summary of the Changes in the Standardized Measure of Future Net Cash Flows	The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014:
		For the Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Beginning of year	$	1,608,112		$	1,589,916		$	1,499,414
	Sale of oil and natural gas produced, net of production costs		(323,994	)		(234,520	)		(160,023	)
	Purchase of minerals in place		1,489,477			23,160			375,953
	Sale of minerals in place		—			—			(154,963	)
	Extensions and discoveries		44,745			136,423			265,108
	Changes in income taxes, net		—			—			1,947
	Changes in prices and costs		(168,500	)		(74,395	)		(331,760	)
	Previously estimated development costs incurred		223,861			174,490			66,360
	Net changes in future development costs		(74,579	)		(74,867	)		(1,140	)
	Revisions of previous quantities		(163,207	)		(141,122	)		(90,587	)
	Accretion of discount		160,811			158,991			150,136
	Change in production rates and other		(37,118	)		50,036			(30,529	)
	End of year	$	2,759,608		$	1,608,112		$	1,589,916

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation - Additional Information (Detail) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

Jun. 18, 2014

Dec. 31, 2014

Dec. 31, 2010

Oct. 02, 2013

Apr. 30, 2012

Mar. 28, 2013

Jul. 31, 2013

31-May-14

Jul. 16, 2014

31-May-12

Dec. 31, 2013

Jun. 27, 2014

Jun. 15, 2014

Dec. 18, 2013

Segment

Consolidation And Basis Of Presentation [Line Items]

Initial public offering

21,500,000

Common unit price per share

$19

Proceeds from public offering

$380,200,000

Initial public offering completion date

18-Jun-14

Common stock, shares issued

193,435,414

Senior PIK Toggle Notes, Redemption date

16-Jul-14

Number of reportable business segments

Business acquisition purchase price

19,800,000

Tanos Energy LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Business acquisition purchase price

77,400,000

18,500,000

Prospect Energy LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Business acquisition purchase price

16,300,000

Jackson County [Member]

Consolidation And Basis Of Presentation [Line Items]

Business acquisition purchase price

2,600,000

WHT Energy Partners LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Business acquisition purchase price

200,000,000

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%

PIK notes trustee [Member]

Consolidation And Basis Of Presentation [Line Items]

Irrevocable deposits

360,000,000

MRD [Member]

Consolidation And Basis Of Presentation [Line Items]

Revolving credit facility

2,000,000,000

Credit facility used

614,500,000

BlueStone Natural Resources Holdings, LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Sale of assets

117,900,000

Golden Energy [Member]

Consolidation And Basis Of Presentation [Line Items]

Sale of assets

6,700,000

Limited Partners Subordinated Units [Member]

Consolidation And Basis Of Presentation [Line Items]

Subordinated units

5,360,912

PIK notes [Member]

Consolidation And Basis Of Presentation [Line Items]

Aggregate principal amount

350,000,000

Debt Instrument, maturity date

15-Dec-18

Debt interest rate, minimum

10.00%

Debt interest rate, maximum

10.75%

Senior PIK Toggle Notes, Redemption price percentage

102.00%

Irrevocable deposits

360,000,000

MRD Holdco LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership percentage in MRD LLC after contribution from Funds and prior to redemption of PIK notes

100.00%

Common stock, shares issued

128,665,677

WildHorse Resources, LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Proceeds for sale of subsidiary

200,000

Ownership interest percentage

99.90%

Common stock, shares issued

42,334,323

Membership interest percentage

0.10%

Cash consideration paid

30,000,000

Classic [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

Business acquisition purchase price

$27,000,000

Classic GP[Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

Black Diamond [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

Beta Operating [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

Memorial Resource Finance Corp [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

MRD Operating [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

Memorial Production Partners GP LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

MEMP GP & MEMP IDRs [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

50.00%

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2014
Summary Of Significant Accounting Policies [Line Items]
Capitalized exploratory drilling costs	$0	$0	$0
Impairment of proved oil and natural gas properties	432,116,000	6,600,000	28,871,000
Amortization expense, including write-offs of debt issuance costs	7,436,000	8,343,000	3,584,000
Capitalized interest	7,300,000	0	0
Minimum percentage likelihood of tax benefit to be realized	50.00%
Unrecognized tax benefits	0	0	0
Unrecognized tax benefits that would affect effective tax rate	0
Interest or penalties recognized in consolidated statements of operations	0
Interest or penalties recognized in consolidated balance sheets	0
Deferred tax liabilities				$43,300,000
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	7 years

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Individual Customers Each Accounted for 10% or More of Total Reported Revenues (Detail) (Sales Revenue, Net [Member], Customer Concentration Risk [Member])	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Sinclair Oil and Gas Company [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues	12.00%
Consolidated & Combined [Member] \| Energy Transfer Equity, LP. and subsidiaries [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues	33.00%		35.00%		13.00%
MRD [Member] \| Energy Transfer Equity, LP. and subsidiaries [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues	73.00%		77.00%		39.00%
MRD [Member] \| Sunoco Inc [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues					15.00%	[1]
MRD [Member] \| Dominion Gas Ventures LP [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues					15.00%
MEMP [Member] \| Phillips 66 [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues	13.00%	[2]	15.00%	[2]	13.00%	[2]
MEMP [Member] \| ConocoPhillips [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues					14.00%

[1]	Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012.
[2]	Phillips 66 was a subsidiary of ConocoPhillips through AprilB 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to MayB 1, 2012 were reported under ConocoPhillips.

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Accrued capital expenditures	$80,350	$48,579
Accrued lease operating expense	16,403	13,240
Accrued general and administrative expenses	8,516	14,485
Accrued ad valorem and production taxes	8,870	3,541
Accrued interest payable	24,797	11,934
Accrued environmental	2,092	577
Accrued current deferred income taxes	51,929	382
Other miscellaneous, including operator advances	6,043	5,392
Accrued liabilities	$199,000	$98,130

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Schedule of Supplemental Cash flow (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$130,732	$61,140	$23,525
Income tax paid	838	168	22
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities	31,771	41,017	17,158
Assumptions of asset retirement obligations related to properties acquired or drilled	5,420	4,227	7,962
Distributions to noncontrolling interests	0	0	47
Repurchase of equity under repurchase program	3,425	0	0
Accounts receivable related to acquisitions	9,569	0	0
Natural Gas Partners [Member]
Noncash investing and financing activities:
Contribution of oil and gas properties from NGP affiliate	0	0	6,893
Accrued distribution to NGP affiliates related to Cinco Group acquisitions	0	4,352	0
Contribution related to sale of assets to NGP affiliate - restricted cash	0	0	2,013
MEMP [Member]
Noncash investing and financing activities:
Accrued equity offering costs	$0	$0	$171

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Acquisition Related Costs (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Acquisition related costs	$6,668	$8,313	$4,538
General and administrative expense [Member]
Business Acquisition [Line Items]
Acquisition related costs	$6,668	$8,313	$4,538

Acquisitions_and_Divestitures_2

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

12 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

1 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2013

9-May-14

Jul. 11, 2012

Sep. 18, 2012

Dec. 30, 2014

Dec. 31, 2014

Jul. 01, 2014

Mar. 25, 2014

Jan. 01, 2013

10-May-13

1-May-12

Sep. 28, 2012

Jul. 31, 2012

Business Acquisition [Line Items]

Proceeds from the sale of oil and natural gas properties

$6,700,000

$155,712,000

$34,521,000

Subsidiaries [Member]

Business Acquisition [Line Items]

Proceeds from divestitures

3,300,000

Gain (loss) on sale of oil and gas properties

-100,000

Series of Individually Immaterial Business Acquisitions [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

10,200,000

WildHorse Resources, LLC [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

67,100,000

Northern Oklahoma [Member]

Business Acquisition [Line Items]

Proceeds from divestitures

7,600,000

Gain (loss) on sale of oil and gas properties

-3,200,000

Garza County, Texas [Member]

Business Acquisition [Line Items]

Proceeds from divestitures

26,100,000

Gain (loss) on sale of oil and gas properties

7,600,000

Ector County, Texas [Member]

Business Acquisition [Line Items]

Proceeds from divestitures

4,700,000

Gain (loss) on sale of oil and gas properties

2,200,000

Terryville Acquisition [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

71,900,000

24,000,000

Wyoming Acquisition [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

906,100,000

Business acquisition, revenues

72,000,000

Business acquisition, earnings

22,900,000

Eagle Ford Acquisition [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

168,100,000

Business acquisition, revenues

36,500,000

Business acquisition, earnings

16,300,000

Percentage of leasehold interest acquired

30.00%

East Texas Acquisition and Rockies Acquisition [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

29,400,000

Propel Energy [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

9,300,000

Tanos [Member] | Natural Gas Pipe Lines [Member]

Business Acquisition [Line Items]

Gain (loss) on sale of oil and gas properties

1,400,000

Period for drilling any new wells

3 years

Contingent consideration related to sale of natural gas pipeline

400,000

Tanos [Member] | Natural Gas Pipe Lines [Member] | Minimum [Member]

Business Acquisition [Line Items]

Proceeds from divestitures

1,500,000

Tanos [Member] | Natural Gas Pipe Lines [Member] | Maximum [Member]

Business Acquisition [Line Items]

Proceeds from divestitures

2,000,000

Tanos [Member] | Oil And Natural Gas Properties [Member]

Business Acquisition [Line Items]

Proceeds from divestitures

2,900,000

Tanos [Member] | Non Operated Oil And Natural Gas Properties [Member]

Business Acquisition [Line Items]

Gain (loss) on sale of oil and gas properties

1,400,000

Black Diamond [Member]

Business Acquisition [Line Items]

Proceeds from divestitures

33,000,000

Gain (loss) on sale of oil and gas properties

-6,800,000

Net book value of oil and gas properties

39,800,000

BlueStone Natural Resources Holdings, LLC [Member]

Business Acquisition [Line Items]

Gain (loss) on sale of oil and gas properties

89,500,000

Proceeds from the sale of oil and natural gas properties

117,900,000

Undisclosed Seller Acquisition [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

112,100,000

Business acquisition, revenues

22,100,000

Business acquisition, earnings

9,200,000

Goodrich Acquisition [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

90,400,000

Business acquisition, revenues

4,600,000

Business acquisition, earnings

2,000,000

Texas And New Mexico [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

147,900,000

Menemsha Acquisition [Member]

Business Acquisition [Line Items]

Payments to acquire oil and gas properties and leases

74,700,000

Business acquisition, revenues

4,900,000

Business acquisition, earnings

$900,000

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed (Detail) (USD $)	Dec. 30, 2014	Apr. 30, 2013	Sep. 06, 2013	Aug. 30, 2013	1-May-12	Sep. 28, 2012	Jul. 31, 2012	Dec. 31, 2012	Mar. 25, 2014	Jul. 01, 2014
In Thousands, unless otherwise specified	Dec. 30, 2014	Apr. 30, 2013	Sep. 06, 2013	Aug. 30, 2013	1-May-12	Sep. 28, 2012	Jul. 31, 2012	Dec. 31, 2012	Mar. 25, 2014	Jul. 01, 2014
Louisiana [Member]
Business Acquisition [Line Items]
Oil and gas properties	$72,141	$68,887
Asset retirement obligations	-271	-1,789
Total identifiable net assets	71,870	67,098
East Texas Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties			9,974
Asset retirement obligations			-78
Total identifiable net assets			9,896
Rockies Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties				20,744
Asset retirement obligations				-1,163
Accrued liabilities				-118
Total identifiable net assets				19,463
Undisclosed Seller Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties					115,633
Asset retirement obligations					-1,592
Revenue Payable					-1,602
Accrued liabilities					-297
Total identifiable net assets					112,142
Goodrich Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties						91,187
Prepaid expenses and other current assets						425
Asset retirement obligations						-161
Revenue Payable						-875
Accrued liabilities						-153
Total identifiable net assets						90,423
Menemsha Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties							75,114
Asset retirement obligations							-408
Total identifiable net assets							74,706
Other Acquisitions [Member]
Business Acquisition [Line Items]
Oil and gas properties								77,764
Asset retirement obligations								-4,558
Total identifiable net assets								73,206
MEMP [Member] \| Eagle Ford Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties									168,606
Asset retirement obligations									-285
Accrued liabilities									-250
Total identifiable net assets									168,071
MEMP [Member] \| Wyoming Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties										930,168
Asset retirement obligations										-3,980
Revenue Payable										-375
Accrued liabilities										-19,693
Total identifiable net assets										$906,120

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures - Unaudited Pro Forma Results of Operations (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Combinations [Abstract]
Revenues	$990,544	$761,443	$431,060
Net income (loss)	($602,044)	$257,839	$40,940
Basic earnings per share	($4.08)
Diluted earnings per share	($4.08)

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 $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Assets:
Fair value of derivative asset	$847,064	$105,938
Liabilities:
Fair value of derivative liability	74,928	63,824
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	847,064	105,938
Liabilities:
Fair value of derivative liability	74,928	63,824
Commodity derivatives [Member]
Assets:
Fair value of derivative asset	845,759	105,054
Liabilities:
Fair value of derivative liability	71,639	58,234
Commodity derivatives [Member] \| Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	845,759	105,054
Liabilities:
Fair value of derivative liability	71,639	58,234
Interest rate derivatives [Member]
Assets:
Fair value of derivative asset	1,305	884
Liabilities:
Fair value of derivative liability	3,289	5,590
Interest rate derivatives [Member] \| Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	1,305	884
Liabilities:
Fair value of derivative liability	$3,289	$5,590

Fair_Value_Measurements_of_Fin3

Fair Value Measurements of Financial Instruments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	$432,116,000	$6,600,000	$28,871,000
MEMP [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	407,500,000		28,871,000
MEMP [Member] \| Permian Basin Properties [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	234,200,000
Carrying value of oil and gas properties after impairment	88,700,000
MEMP [Member] \| East Texas Properties [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	107,600,000		20,900,000
Carrying value of oil and gas properties after impairment	88,800,000
MEMP [Member] \| South Texas Properties [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	65,600,000
Carrying value of oil and gas properties after impairment	71,200,000
MEMP [Member] \| Elkhorn and Canyon Fields (Member)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties			8,000,000
MRD [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	$24,600,000

Risk_Management_and_Derivative2

Risk Management and Derivative Instruments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Jul. 01, 2014
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	$99,200,000
Effect netting arrangements, counterparty exposure	155,800,000
Derivative asset	255,000,000
Cash settlement receipt	6,100,000
Cash collateral received or pledged	0
Interest rate swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Aggregate termination amount paid to counterparties		700,000
Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure	109,700,000
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	207,300,000
Effect netting arrangements, counterparty exposure	309,800,000
Derivative asset	$517,100,000

Risk_Management_and_Derivative3

Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2014
	MMBTU
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MRD [Member] \| Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,700,000
Weighted-average fixed price	4.15
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
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MRD [Member] \| Put Option [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,000,000
Weighted-average fixed price	3.75
Weighted-average deferred premium	-0.33
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MRD [Member] \| TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,730,000
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MRD [Member] \| TGT Z1 basis swaps [Member] \| Henry Hub [Member]
Derivative [Line Items]
Spread	-0.09
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,605,278
Weighted-average fixed price	4.28
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
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| Call Spreads [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	80,000	[1]
Weighted-average sold strike price	5.25	[1]
Weighted-average bought strike price	6.75	[1]
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,940,000
Spread	-0.12
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,280,000
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| NGPL TexOk basis swaps [Member] \| Henry Hub [Member]
Derivative [Line Items]
Spread	-0.11
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	150,000
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| HSC basis swaps [Member] \| Henry Hub [Member]
Derivative [Line Items]
Spread	-0.08
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| CIG basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	210,000
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| CIG basis swaps [Member] \| Henry Hub [Member]
Derivative [Line Items]
Spread	-0.25
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	300,000
2015 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| TETCO STX basis swaps [Member] \| Henry Hub [Member]
Derivative [Line Items]
Spread	-0.09
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)	46,500
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
2015 [Member] \| Crude Oil Derivative Contracts [Member] \| MRD [Member] \| Put Option [Member]
Derivative [Line Items]
Weighted-average deferred premium	-3.8
Average Monthly Volume (Bbls)	26,000
Weighted-average fixed price	85
2015 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	90.96
Average Monthly Volume (Bbls)	314,281
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
2015 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Basis Swaps [Member]
Derivative [Line Items]
Spread	-7.07
Average Monthly Volume (Bbls)	97,500
2015 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls)	57,500
2015 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Midway-Sunset basis swaps [Member] \| Brent [Member]
Derivative [Line Items]
Spread	-9.73
2015 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Midland Basis Swap [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls)	40,000
2015 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Midland Basis Swap [Member] \| WTI [Member]
Derivative [Line Items]
Spread	-3.25
2015 [Member] \| NGL Derivative Contracts [Member] \| MRD [Member] \| Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	41.61
Average Monthly Volume (Bbls)	151,000
2015 [Member] \| NGL Derivative Contracts [Member] \| MEMP [Member] \| Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	43.02
Average Monthly Volume (Bbls)	149,200
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]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	4,100,000
Weighted-average fixed price	3.75
Weighted-average deferred premium	-0.36
2016 [Member] \| Natural Gas Derivative Contracts [Member] \| MRD [Member] \| TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	220,000
2016 [Member] \| Natural Gas Derivative Contracts [Member] \| MRD [Member] \| TGT Z1 basis swaps [Member] \| Henry Hub [Member]
Derivative [Line Items]
Spread	-0.08
2016 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,692,442
Weighted-average fixed price	4.4
2016 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,508,333
Spread	-0.04
2016 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,103,333
2016 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| NGPL TexOk basis swaps [Member] \| Henry Hub [Member]
Derivative [Line Items]
Spread	-0.06
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	85.83
Average Monthly Volume (Bbls)	332,813
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]
Average Monthly Volume (Bbls)	55,000
2016 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Midway-Sunset basis swaps [Member] \| Brent [Member]
Derivative [Line Items]
Spread	-13.35
2016 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Midland Basis Swap [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls)	40,000
2016 [Member] \| Crude Oil Derivative Contracts [Member] \| MEMP [Member] \| Midland Basis Swap [Member] \| WTI [Member]
Derivative [Line Items]
Spread	-4.34
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	41.49
Average Monthly Volume (Bbls)	84,600
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]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	3,450,000
Weighted-average fixed price	3.75
Weighted-average deferred premium	-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)	2,450,067
Weighted-average fixed price	4.31
2017 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	415,000
Spread	0
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	84.38
Average Monthly Volume (Bbls)	326,600
2018 [Member] \| Natural Gas Derivative Contracts [Member] \| MRD [Member] \| Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,900,000
Weighted-average fixed price	4.27
2018 [Member] \| Natural Gas Derivative Contracts [Member] \| MRD [Member] \| Put Option [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,850,000
Weighted-average fixed price	3.75
Weighted-average deferred premium	-0.35
2018 [Member] \| Natural Gas Derivative Contracts [Member] \| MEMP [Member] \| Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,160,000
Weighted-average fixed price	4.51
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)	1,914,583
Weighted-average fixed price	4.75
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

[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.

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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
2015 [Member]
Derivative [Line Items]
Average Monthly Notional	$314,167
Weighted-average fixed rate	1.35%
Floating rate	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	250,000
Weighted-average fixed rate	1.03%
Floating rate	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	$250,000
Weighted-average fixed rate	1.62%
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 $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$340,056	$9,289
Asset Derivatives, Net recorded fair value	435,369	48,616
Liability Derivatives, Net recorded fair value	3,289	9,711
Liability Derivatives, Net recorded fair value		6,080
Short-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	378,908	22,604
Asset Derivatives, Netting arrangements	-38,852	-13,315
Asset Derivatives, Net recorded fair value	340,056	9,289
Liability Derivatives, Gross fair value	42,141	23,026
Liability Derivatives, Netting arrangements	-38,852	-13,315
Liability Derivatives, Net recorded fair value	3,289	9,711
Short-term derivative instruments [Member] \| Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	378,908	21,759
Liability Derivatives, Gross fair value	38,852	19,739
Short-term derivative instruments [Member] \| Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value		845
Liability Derivatives, Gross fair value	3,289	3,287
Long-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	468,156	83,334
Asset Derivatives, Netting arrangements	-32,787	-34,718
Asset Derivatives, Net recorded fair value	435,369	48,616
Liability Derivatives, Gross fair value	32,787	40,798
Liability Derivatives, Netting arrangements	-32,787	-34,718
Liability Derivatives, Net recorded fair value		6,080
Long-term derivative instruments [Member] \| Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	466,851	83,295
Liability Derivatives, Gross fair value	32,787	38,495
Long-term derivative instruments [Member] \| Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	1,305	39
Liability Derivatives, Gross fair value		$2,303

Risk_Management_and_Derivative6

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	($749,988)	($29,294)	($34,905)
Interest expense, net	133,833	69,250	33,238
Commodity contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	-749,988	-29,294	-34,905
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	$145	($239)	$5,582

Asset_Retirement_Obligations_S

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$111,769	$102,380	$90,699
Liabilities added from acquisitions or drilling	5,420	4,227	7,962
Liabilities removed upon sale of wells	-669	-1,765	-1,931
Liabilities removed upon plugging and abandoning	-588	-170	-119
Revisions	293	1,516	760
Accretion expense	6,306	5,581	5,009
Asset retirement obligations at end of period	122,531	111,769	102,380
Less: Current portion		90	390
Asset retirement obligationsb long-term portion	$122,531	$111,679	$101,990

Restricted_Investments_Restric

Restricted Investments - Restricted Investment Balance (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Investments [Line Items]
Restricted investments	$77,361	$73,385
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	69,954	66,373
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	2,701	2,306
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 $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Total long-term debt	$2,378,413		$1,663,217
MRD [Member]
Debt Instrument [Line Items]
Long-term debt	783,000		871,150
MRD [Member] \| 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility	183,000
MRD [Member] \| PIK notes [Member]
Debt Instrument [Line Items]
Senior Notes			350,000
MRD [Member] \| 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	600,000	[1]
MRD [Member] \| Senior Pik Toggle Notes Unamortized Discounts [Member]
Debt Instrument [Line Items]
Unamortized discounts			-6,950
MRD [Member] \| WildHorse Resources, LLC [Member] \| 1.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility			203,100
MRD [Member] \| WildHorse Resources, LLC [Member] \| 325.0 Million Lien Term Facility [Member]
Debt Instrument [Line Items]
Credit facility			325,000
MEMP [Member]
Debt Instrument [Line Items]
Unamortized discounts	-16,587		-10,933
Long-term debt	1,595,413		792,067
MEMP [Member] \| 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility	412,000		103,000
MEMP [Member] \| 7.625 % Senior Notes Due May 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	700,000	[2]	700,000	[2]
MEMP [Member] \| 6.875% Senior Unsecured Notes Due August 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	$500,000	[3]

[1]	The estimated fair value of this fixed-rate debt was $534.0 million at DecemberB 31, 2014. 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 $563.5 million and $721.0 million at DecemberB 31, 2014 and 2013, 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 $380.0 million at DecemberB 31, 2014. 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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
PIK notes [Member]
Debt Instrument [Line Items]
Senior notes maturity date	15-Dec-18
Debt interest rate, minimum	10.00%
Debt interest rate, maximum	10.75%
7.625 % Senior Notes Due May 2021 [Member]
Debt Instrument [Line Items]
Senior notes maturity date	1-May-21
MRD [Member] \| 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities	2,000
Senior notes maturity date	30-Jun-19
MRD [Member] \| 1.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities		1,000
Termination date of revolving credit facility		30-Jun-14
MRD [Member] \| PIK notes [Member]
Debt Instrument [Line Items]
Debt interest rate, minimum		10.00%
Senior notes redemption date		30-Jun-14
Debt interest rate, maximum		10.75%
MRD [Member] \| 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Senior notes maturity date	31-Jul-22
Debt interest rate	5.88%
Estimated fair value of fixed rate debt	534
MRD [Member] \| WildHorse Resources, LLC [Member] \| 325.0 Million Lien Term Facility [Member]
Debt Instrument [Line Items]
Credit facilities		325
MEMP [Member]
Debt Instrument [Line Items]
Credit facilities	2,000
MEMP [Member] \| 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities	2,000
Senior notes maturity date	31-Mar-18
MEMP [Member] \| 7.625 % Senior Notes Due May 2021 [Member]
Debt Instrument [Line Items]
Senior notes maturity date	31-May-21
Debt interest rate	7.63%
Estimated fair value of fixed rate debt	563.5	721
MEMP [Member] \| 6.875% Senior Unsecured Notes Due August 2022 [Member]
Debt Instrument [Line Items]
Senior notes maturity date	31-Aug-22
Debt interest rate	6.88%
Estimated fair value of fixed rate debt	380

Long_Term_Debt_Borrowing_Base_

Long Term Debt - Borrowing Base Credit Facility (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
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	$1,440,000

Long_Term_Debt_Borrowing_Base_1

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
MRD [Member] \| 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$2,000
MEMP [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	2,000
MEMP [Member] \| 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$2,000

Long_Term_Debt_MRD_Revolving_C

Long Term Debt - MRD Revolving Credit Facility - Additional Information (Detail) (MRD [Member], Revolving Credit Facility [Member], USD $)	0 Months Ended	12 Months Ended
	Jul. 18, 2014	Dec. 31, 2014
Debt Obligations [Line Items]
Revolving credit facility expiration term	5 years
Line of credit facility, aggregate maximum borrowing amount	$2,000,000,000
Line of credit facility, initial borrowing base	725,000,000
Aggregate elected capacity of revolving credit	$725,000,000
Optional Base Rate \| Federal Funds Effective Rate [Member]
Debt Obligations [Line Items]
Lien percentage of assets for credit facility		80.00%
Line of credit, additional margin rate		0.50%
Line of credit, adjusted description		The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%)
Range 1 [Member] \| Alternative Base Rate
Debt Obligations [Line Items]
Line of credit, additional margin rate		0.50%
Range 1 [Member] \| London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Line of credit, additional margin rate		1.50%
Range 2 [Member] \| Alternative Base Rate
Debt Obligations [Line Items]
Line of credit, additional margin rate		1.50%
Range 2 [Member] \| London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Line of credit, additional margin rate		2.50%
Minimum [Member]
Debt Obligations [Line Items]
Percentage of revolving unused commitment fee		0.38%
Debt instrument interest coverage ratio		2.50%
Debt instrument, current asset to current liabilities ratio		1.00%
Maximum [Member]
Debt Obligations [Line Items]
Percentage of revolving unused commitment fee		0.50%

Long_Term_Debt_MRD_5875_Senior

Long Term Debt - MRD 5.875% Senior Unsecured Notes Offering - Additional Information (Detail) (5.875% Senior Unsecured Notes ("MRD Senior Notes") [Member], USD $)	0 Months Ended
In Millions, unless otherwise specified	Jul. 10, 2014
Debt Obligations [Line Items]
Debt Instrument, maturity date	1-Jul-22
Other event of default minimum note holder percentage to accelerate	25.00%
Private Placement of Debt [Member]
Debt Obligations [Line Items]
Aggregate principal amount	600
Senior unsecured notes interest rate	5.88%

Long_Term_Debt_PIK_notes_Addit

Long Term Debt - PIK notes - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 16, 2014	Dec. 18, 2013	Jun. 27, 2014	Jun. 15, 2014
Debt Obligations [Line Items]
Payment of distribution to funds	$0	$732,362,000	$0
Extinguishment loss	37,248,000	0	0
PIK notes [Member]
Debt Obligations [Line Items]
Aggregate principal amount					350,000,000		350,000,000
Percentage of PIK toggle notes issued at par					98.00%
Cash reserve for payment of interest on notes					50,000,000
Payment of distribution to funds					210,000,000
Debt redemption price percentage				102.00%
Irrevocable deposits						360,000,000
Extinguishment loss	$23,600,000

Long_Term_Debt_WildHorse_Resou

Long Term Debt - WildHorse Resources Revolving Credit Facility and Second Lien Facility - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 03, 2013	Jun. 13, 2013
Debt Obligations [Line Items]
Cash distribution paid	$0	$732,362,000	$0
Loss on extinguishment of debt	37,248,000	0	0
Revolving Credit Facility [Member] \| WildHorse Resources, LLC [Member]
Debt Obligations [Line Items]
Initial borrowing base of second lien term facility				1,000,000,000
Line of credit facility, initial borrowing base				300,000,000
Line of credit, minimum collateral percentage				80.00%
Revolving Credit Facility [Member] \| WildHorse Resources, LLC [Member] \| Second Lien Term Loan [Member]
Debt Obligations [Line Items]
Initial borrowing base of second lien term facility					325,000,000
Line of credit, minimum collateral percentage					80.00%
Cash distribution paid					225,000,000
Loss on extinguishment of debt	$13,700,000
Revolving Credit Facility [Member] \| WildHorse Resources, LLC [Member] \| Second Lien Term Loan [Member] \| Alternative Base Rate
Debt Obligations [Line Items]
Debt instrument interest rate					5.25%
Revolving Credit Facility [Member] \| WildHorse Resources, LLC [Member] \| Second Lien Term Loan [Member] \| London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Debt instrument interest rate					6.25%

Long_Term_Debt_MEMP_Revolving_

Long Term Debt - MEMP Revolving Credit Facility and Senior Notes - Additional Information (Detail) (USD $)	12 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Jul. 17, 2014	Oct. 10, 2013	23-May-13	Apr. 17, 2013
7.625 % Senior Notes Due May 2021 [Member]
Debt Obligations [Line Items]
Debt Instrument, maturity date	1-May-21
MEMP [Member]
Debt Obligations [Line Items]
Initial borrowing base of second lien term facility	2,000
MEMP [Member] \| 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member]
Debt Obligations [Line Items]
Other event of default minimum note holder percentage to accelerate		25.00%
Debt Instrument, maturity date		1-Aug-22
Note issued at percentage of par		98.49%
MEMP [Member] \| Private Placement of Debt [Member] \| 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member]
Debt Obligations [Line Items]
Aggregate principal amount		500
Senior unsecured notes interest rate		6.88%
MEMP [Member] \| 7.625 % Senior Notes Due May 2021 [Member]
Debt Obligations [Line Items]
Senior unsecured notes interest rate	7.63%
Other event of default minimum note holder percentage to accelerate	25.00%
Debt Instrument, maturity date	31-May-21
MEMP [Member] \| 7.625 % Senior Notes Due May 2021 [Member] \| Private Placement of Debt [Member]
Debt Obligations [Line Items]
Aggregate principal amount			$300	$100	$300
MEMP [Member] \| Optional Base Rate \| Federal Funds Effective Rate [Member]
Debt Obligations [Line Items]
Lien percentage of assets for credit facility	80.00%
Line of credit, additional margin rate	0.50%
Line of credit, adjusted description	The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%)
MEMP [Member] \| Optional Base Rate \| Adjusted London Interbank Offered Rate
Debt Obligations [Line Items]
Line of credit, additional margin rate	1.00%
MEMP [Member] \| Minimum [Member]
Debt Obligations [Line Items]
Percentage of revolving unused commitment fee	0.38%
MEMP [Member] \| Minimum [Member] \| Alternative Base Rate \| Range 1 [Member]
Debt Obligations [Line Items]
Line of credit, additional margin rate	0.50%
MEMP [Member] \| Minimum [Member] \| London Interbank Offered Rate (LIBOR) \| Range 2 [Member]
Debt Obligations [Line Items]
Line of credit, additional margin rate	1.50%
MEMP [Member] \| Minimum [Member] \| LIBOR Market Index Plus [Member] \| Range 3 [Member]
Debt Obligations [Line Items]
Line of credit, additional margin rate	1.50%
MEMP [Member] \| Maximum [Member]
Debt Obligations [Line Items]
Percentage of revolving unused commitment fee	0.50%
MEMP [Member] \| Maximum [Member] \| Alternative Base Rate \| Range 1 [Member]
Debt Obligations [Line Items]
Line of credit, additional margin rate	1.50%
MEMP [Member] \| Maximum [Member] \| London Interbank Offered Rate (LIBOR) \| Range 2 [Member]
Debt Obligations [Line Items]
Line of credit, additional margin rate	2.50%
MEMP [Member] \| Maximum [Member] \| LIBOR Market Index Plus [Member] \| Range 3 [Member]
Debt Obligations [Line Items]
Line of credit, additional margin rate	2.50%

Long_Term_Debt_Summary_of_Weig

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
MRD [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.99%
MRD [Member] \| MRD LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.17%	4.11%
MRD [Member] \| Classic Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates			4.50%
MRD [Member] \| WildHorse Resources, LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	4.04%	2.30%	3.00%
MRD [Member] \| WildHorse Resources second lien [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	6.44%	7.60%
MRD [Member] \| Black Diamond [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.97%	3.62%
MEMP [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	2.67%	3.25%	2.74%
MEMP [Member] \| Wht [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.29%	2.60%
MEMP [Member] \| Tanos Energy LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.10%	2.31%
MEMP [Member] \| REO Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates			3.40%
MEMP [Member] \| Stanolind [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.52%	3.76%
MEMP [Member] \| Boaz [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.97%	3.12%
MEMP [Member] \| Crown [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.38%	4.20%
MEMP [Member] \| Propel Energy [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.08%	3.28%

Long_Term_Debt_Summary_of_Unam

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Obligations [Line Items]
Unamortized deferred financing costs	$44,474	$40,193
MRD [Member] \| Revolving Credit Facility [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs	4,285
MRD [Member] \| Revolving Credit Facility [Member] \| WildHorse Resources, LLC [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs		2,436
MRD [Member] \| Senior Notes
Debt Obligations [Line Items]
Unamortized deferred financing costs	12,455
MRD [Member] \| Second Lien Credit Facility [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs		9,030
MRD [Member] \| PIK notes [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs		8,261
MEMP [Member] \| Revolving Credit Facility [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs	6,468	5,413
MEMP [Member] \| 2021 Senior Notes [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs	13,308	15,053
MEMP [Member] \| 2022 Senior Notes [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs	$7,958

Stockholders_Equity_and_Noncon2

Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 09, 2014	Jul. 15, 2014	Oct. 08, 2013	Mar. 25, 2013	Apr. 01, 2013	Mar. 16, 2015	Feb. 01, 2015	Jun. 18, 2014
Stockholders Equity Note Disclosure [Line Items]
Common stock, shares authorized	600,000,000	0
Common stock, par value	$0.01	$0.01
Stock repurchase program, authorized amount	$50,000,000
Stock repurchased and retired during period, shares	123,797
Payments for repurchase of common stock	2,215,000
Preferred stock, par value	$0.01
Preferred stock, shares authorized	50,000,000
Preferred stock, shares issued	0
Preferred stock, shares outstanding	0
Public offering price per common unit											$19
Noncontrolling interests	1,120,554,000	580,615,000
Fair value consideration paid	3,292,000	15,135,000	0
Common Stock [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchased and retired during period, shares	123,797
MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchase program, authorized amount	150,000,000
Stock repurchased and retired during period, shares	899,912
Payments for repurchase of common stock	12,900,000
MEMP [Member] \| Common Stock [Member]
Stockholders Equity Note Disclosure [Line Items]
Number of common units sold by subsidiary			11,975,000	14,950,000	9,890,000	16,675,000	9,775,000
Net proceeds from sale of common units by subsidiary			194,100,000	321,300,000	220,000,000	318,300,000	171,800,000
Tanos Energy LLC [Member]
Stockholders Equity Note Disclosure [Line Items]
Percentage of ownership interest sold to company								1.07%
WildHorse Resources, LLC [Member]
Stockholders Equity Note Disclosure [Line Items]
Percentage of interest contributed former management members											0.10%
Cash consideration paid to certain former management members											30,000,000
Noncontrolling interests											400,000
Fair value consideration paid	3,300,000
Subsequent Event [Member] \| MRD [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchased and retired during period, shares									2,764,887
Payments for repurchase of common stock									47,800,000
Subsequent Event [Member] \| MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchased and retired during period, shares										1,909,583
Payments for repurchase of common stock										$28,500,000

Stockholders_Equity_and_Noncon3

Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail)	0 Months Ended	12 Months Ended
	Jun. 18, 2014	Dec. 31, 2014
Class of Stock [Line Items]
Beginning Balance		0
Shares of common stock issued in initial public offering (Note 1)	21,500,000
Shares of common stock repurchased and retired		-123,797
Ending Balance		193,435,414
Common Stock [Member]
Class of Stock [Line Items]
Shares of common stock issued in connection with restructuring transactions (Note 1)		171,000,000
Shares of common stock issued in initial public offering (Note 1)		21,500,000
Shares of common stock repurchased and retired		-123,797
Restricted common shares issued (Note 11)		1,068,422
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			12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator:
Net income (loss) available to common stockholders	$167,198	$9,928	($961,707)	($784,581)	$0	$0
Denominator:
Weighted average common shares outstanding				192,498
Basic EPS	$0.87	$0.05	($5)	($4.08)	$0	$0
Diluted EPS	$0.87	$0.05	($5)	($4.08)	$0	$0

Earnings_per_Share_Summary_of_1

Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Parenthetical) (Detail)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Earnings Per Share [Abstract]
Shares excluded from computation of EPS	202,623

Earnings_per_Share_Summary_of_2

Earnings per Share - Summary of Calculation of Supplemental EPS (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator:
Net income (loss) attributable to Memorial Resource Development Corp.	$167,198	$9,928	($948,349)	$8,372	($30,657)	$84,727	$43,183	$4,249	($762,851)	$101,502	$29,698
Denominator:
Weighted average common shares outstanding									192,498
Basic EPS	$0.87	$0.05	($5)						($4.08)	$0	$0
Diluted EPS	$0.87	$0.05	($5)						($4.08)	$0	$0
Supplemental EPS [Member]
Numerator:
Net income (loss) attributable to Memorial Resource Development Corp.									($762,851)
Denominator:
Weighted average common shares outstanding									192,498
Basic EPS									($3.96)
Diluted EPS									($3.96)

Earnings_per_Share_Summary_of_3

Earnings per Share - Summary of Calculation of Supplemental EPS (Parenthetical) (Detail)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Earnings Per Share [Line Items]
Shares excluded from computation of EPS	202,623
Supplemental EPS [Member]
Earnings Per Share [Line Items]
Shares excluded from computation of EPS	202,623

LongTerm_Incentive_Plans_Addit

Long-Term Incentive Plans - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2011
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common shares that may be delivered	19,250,000
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common units that may be delivered		2,142,221
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate award of restricted stock issued to employees and each independent director	1,052,633
Vesting period of award	4 years
Unrecognized compensation cost	$17.30
Unrecognized compensation cost weighted-average period	3 years 5 months 5 days
Restricted Stock [Member] \| MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$16.50
Unrecognized compensation cost weighted-average period	2 years 1 month 6 days
Restricted Stock [Member] \| Director [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate award of restricted stock issued to employees and each independent director	5,263
Vesting period of award	1 year

LongTerm_Incentive_Plans_Summa

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Units	1,068,422
Forfeited, Number of Units	-9,211
Restricted common shares outstanding, Number of Units, Ending Balance	1,059,211
Granted, Weighted-Average Grant Date Fair Value Per Unit	$19
Forfeited, Weighted-Average Grant Date Fair Value Per Unit	$19
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Ending Balance	$19
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Units	684,954	524,718	287,943
Forfeited, Number of Units	-38,294	-11,734	-2,334
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Beginning Balance	$18.62	$18.08
Granted, Weighted-Average Grant Date Fair Value Per Unit	$22.39	$18.83	$18.07
Forfeited, Weighted-Average Grant Date Fair Value Per Unit	$20.54	$17.24	$17.14
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Ending Balance	$20.93	$18.62	$18.08
Restricted common shares outstanding, Number of Units, Beginning Balance	706,927	285,609
Vested, Number of Units	-260,067	-91,666
Restricted common shares outstanding, Number of Units, Ending Balance	1,093,520	706,927	285,609
Vested, Weighted-Average Grant Date Fair Value Per Unit	$18.56	$18.31

LongTerm_Incentive_Plans_Summa1

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) (Restricted Stock [Member], USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$20.30
Granted, Weighted-Average Grant Date Fair Value Per Unit	$19
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$15.30	$9.90	$5.20
Granted, Weighted-Average Grant Date Fair Value Per Unit	$20.93	$18.62	$18.08
MEMP [Member] \| Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value, market price range	$21.99	$18.33	$17.14
MEMP [Member] \| Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value, market price range	$23.40	$20.35	$18.58

LongTerm_Incentive_Plans_Summa2

Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Compensation Related Costs Disclosure [Line Items]
Amortization of equity awards	$954,627	$46,837	$10,933
MEMP [Member]
Compensation Related Costs Disclosure [Line Items]
Amortization of equity awards	7,874	3,558	1,423
Restricted Stock [Member] \| MRD [Member]
Compensation Related Costs Disclosure [Line Items]
Amortization of equity awards	$2,804

Incentive_Units_Additional_Inf

Incentive Units - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended
Incentive Units - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 01, 2013	Nov. 30, 2013	Dec. 31, 2013	Jun. 18, 2014
Equity Incentive Plan [Line Items]
Compensation expense	$954,627,000	$46,837,000	$10,933,000
Accrued liabilities	199,000,000	98,130,000				98,130,000
Exchange of incentive units	193,435,414	0				0
Carrying amount of the noncontrolling interest	1,120,554,000	580,615,000				580,615,000
Fair value of consideration paid for noncontrolling interests	3,292,000	15,135,000	0
BlueStone Natural Resources Holdings, LLC [Member]
Equity Incentive Plan [Line Items]
Compensation expense	1,000,000	20,700,000	0
BlueStone Natural Resources Holdings, LLC [Member] \| Special Tier and Tier I Unit Holders [Member]
Equity Incentive Plan [Line Items]
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved	16.50%
Tanos Energy LLC [Member]
Equity Incentive Plan [Line Items]
Percentage of ownership interest sold to company				1.07%
Compensation expense as component of general and administrative expense		5,800,000
Black Diamond, Classic GP and Classic
Equity Incentive Plan [Line Items]
Compensation expense					12,600,000
WildHorse Resources, LLC [Member]
Equity Incentive Plan [Line Items]
Compensation expense	831,100,000					10,000,000
Accrued liabilities		10,000,000				10,000,000
Percentage of interest contributed former management members							0.10%
Exchange of incentive units							42,334,323
Cash consideration paid to certain former management members							30,000,000
Carrying amount of the noncontrolling interest							400,000
Fair value of consideration paid for noncontrolling interests	3,300,000
Cash component of incentive unit compensation expense	26,700,000
Incentive units exchanges for shares of our common stock	804,400,000
MRD Holdco LLC [Member]
Equity Incentive Plan [Line Items]
The number of incentive units authorized by governing documents	1,000
Remaining expected life	3 years
MRD Holdco LLC [Member] \| Exchanged Incentive Units [Member]
Equity Incentive Plan [Line Items]
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved	9.30%
Compensation expense	111,500,000
Incentive units granted in an exchange for cancelled predecessor awards	930
Unrecognized compensation expense	105,500,000
Remaining expected life	2 years 4 months 28 days
MRD Holdco LLC [Member] \| Subsequent Incentive Units [Member]
Equity Incentive Plan [Line Items]
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved	0.70%
Compensation expense	400,000
Unrecognized compensation expense	$1,700,000
Remaining expected life	2 years 4 months 28 days
Subsequent incentive units	70
Minimum [Member]
Equity Incentive Plan [Line Items]
Ranging of distributions for incentive units	10.00%
Maximum [Member]
Equity Incentive Plan [Line Items]
Ranging of distributions for incentive units	31.50%

Incentive_Units_Fair_Value_of_

Incentive Units - Fair Value of Incentive Units Estimated (Detail)	12 Months Ended
	Dec. 31, 2014
Exchanged Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	31-Dec-14
Dividend yield	0.00%
Expected volatility	39.54%
Risk-free rate	0.85%
Expected life (years)	2 years 4 months 28 days
Subsequent Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	31-Dec-14
Dividend yield	0.00%
Expected volatility	39.54%
Risk-free rate	0.85%
Expected life (years)	2 years 4 months 28 days

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

1-May-14

Nov. 01, 2011

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2010

Oct. 11, 2012

Mar. 28, 2014

Dec. 12, 2012

Mar. 17, 2014

Mar. 10, 2014

Mar. 01, 2012

Feb. 28, 2014

Oct. 01, 2013

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

10.00%

Cash received

$19,800,000

General and administrative

87,673,000

82,079,000

59,677,000

Received an equity contribution of oil and gas properties

6,900,000

Fee per MMBTU

0.3

Natural gas produced per day

50,000

Annual inflationary escalation

3.50%

Price per unit

0.07

NGP Controlled Entity [Member]

Related Party Transaction [Line Items]

Proceeds from divestitures

40,100,000

Proceeds from sale exceeded net book value of properties sold

6,300,000

Propel Energy [Member]

Related Party Transaction [Line Items]

Cash received

3,300,000

NGPCIF [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

3.13%

Cash received

19,500,000

Fixed overhead cost per month

20,000

Business acquisition common control purchase price

63,400,000

Date of acquisition common control

28-Feb-14

REO Sponsorship [Member]

Related Party Transaction [Line Items]

Business acquisition common control purchase price

270,600,000

Working capital and other customary adjustments to Beta acquisition

3,000,000

General and administrative

1,600,000

Cinco Group [Member]

Related Party Transaction [Line Items]

Business acquisition common control purchase price

603,000,000

Financing fees equal to a percentage of capital contributions

400,000

Cinco Group [Member] | Advisory Fees [Member]

Related Party Transaction [Line Items]

Expenses incurred with related parties

300,000

400,000

MEMP [Member]

Related Party Transaction [Line Items]

Payable to related party

800,000

Oil And Gas Production [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

23.50%

Oil And Gas Production [Member] | NGPCIF [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

6.25%

WildHorse Resources, LLC [Member]

Related Party Transaction [Line Items]

Common stock lock-up agreement period

180 days

Cash received from related party

4,400,000

Primary term of gas processing agreement

15 years

Minimum annual processing fee

18,300,000

WildHorse Resources, LLC [Member] | NGPCIF [Member]

Related Party Transaction [Line Items]

Payment to related party

2,600,000

2,300,000

Payable to related party

200,000

Natural Gas Partners [Member] | Cinco Group [Member]

Related Party Transaction [Line Items]

Business acquisition common control purchase price

507,100,000

BlueStone Natural Resources Holdings, LLC [Member]

Related Party Transaction [Line Items]

Total cash consideration

1,200,000

7,000,000

Amount of gain over the book value

500,000

Gain recognized as contribution

500,000

6,400,000

Undivided interest sold to affiliate

25.00%

WHR Management Company [Member]

Related Party Transaction [Line Items]

Payable to related party

2,400,000

Management fee per month

1,000,000

Employee [Member]

Related Party Transaction [Line Items]

Expenses incurred with related parties

1,000,000

Boaz [Member]

Related Party Transaction [Line Items]

Expenses incurred with related parties

300,000

Classic [Member]

Related Party Transaction [Line Items]

Water disposal fee per barrel

1.1

Water disposal agreement period

3 years

Adjustments [Member]

Related Party Transaction [Line Items]

Cash received

19,900,000

Adjustments [Member] | NGPCIF [Member]

Related Party Transaction [Line Items]

Cash received

19,100,000

Received Upon Closing [Member] | NGP Controlled Entity [Member]

Related Party Transaction [Line Items]

Proceeds from divestitures

$38,100,000

Related_Party_Transactions_Sch

Related Party Transactions - Schedule of Net Assets Recorded (Detail) (USD $)	Feb. 28, 2014	Sep. 01, 2012	Oct. 01, 2013
In Thousands, unless otherwise specified	Feb. 28, 2014	Sep. 01, 2012	Oct. 01, 2013
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
REO Sponsorship [Member]
Related Party Transaction [Line Items]
Cash and cash equivalents		6,021
Accounts receivable		16,284
Short-term derivative instruments, net		2,926
Prepaid expenses and other current assets		4,521
Oil and natural gas properties, net		108,342
Restricted investments		68,009
Accounts payable		-9,092
Accrued liabilities		-9,140
Asset retirement obligations		-58,746
Credit facilities		-28,500
Deferred tax liability		-1,674
Noncontrolling interest		-5,255
Net assets		93,696
Cinco Group Acquisition [Member]
Related Party Transaction [Line Items]
Cash and cash equivalents			2,820
Accounts receivable			5,184
Prepaid expenses and other current assets			1,454
Oil and natural gas properties, net			342,759
Long-term derivative instruments, net			-826
Other long-term assets			344
Accounts payable			-2,346
Revenue payable			-2,910
Accrued liabilities			-1,799
short-term derivative instruments, net			-1,828
Asset retirement obligations			-9,606
Credit facilities			-151,690
Net assets			$181,556

Related_Party_Transactions_Boo

Related Party Transactions - Book Value of Assets Sold (Detail) (WHR Management Company [Member], USD $)	Jun. 18, 2014
In Thousands, unless otherwise specified	Jun. 18, 2014
WHR Management Company [Member]
Related Party Transaction [Line Items]
Cash and cash equivalents	$33,001
Restricted cash	300
Accounts receivable	5,256
Prepaid expenses and other current assets	379
Property, plant and equipment, net	3,410
Other long-term assets	4
Accounts payable	-19,959
Accounts payable - affiliates	-17,099
Accrued liabilities	-5,061
Net assets	$231

Business_Segment_Data_Addition

Business Segment Data - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014
	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								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Total revenues	$226,460	$245,493	$236,564	$190,828	$152,282	$153,515	$147,045	$122,181	$899,345	$575,023	$396,868
Adjusted EBITDA									647,733	394,856	287,992
Segment assets	4,593,547				2,829,161				4,593,547	2,829,161
Total cash expenditures for additions to long-lived assets									1,869,133	468,447	636,686
Operating Segments [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA									653,877	420,088	311,439
Operating Segments [Member] \| MRD [Member]
Segment Reporting Information [Line Items]
Total revenues									405,286	231,558	138,814
Adjusted EBITDA									343,976	197,903	132,105
Segment assets	1,632,313				1,281,134				1,632,313	1,281,134
Total cash expenditures for additions to long-lived assets									521,038	267,870	249,526
Operating Segments [Member] \| MEMP [Member]
Segment Reporting Information [Line Items]
Total revenues									494,105	343,616	258,423
Adjusted EBITDA									309,901	222,185	179,334
Segment assets	2,930,559				1,552,307				2,930,559	1,552,307
Total cash expenditures for additions to long-lived assets									1,348,095	200,577	387,160
Other, Adjustments & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues									-46	-151	-369
Adjusted EBITDA									-6,144	-25,232	-23,447
Segment assets	$30,675				($4,280)				$30,675	($4,280)

Business_Segment_Data_Summary_1

Business Segment Data - Summary of Selected Business Segment Information (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Cash distributions from MEMP	$6,144,000	$26,006,000	$19,263,000
Other, Adjustments & Eliminations [Member]
Segment Reporting Information [Line Items]
Impairment charges	46,000,000	49,900,000
Other, Adjustments & Eliminations [Member] \| MEMP [Member]
Segment Reporting Information [Line Items]
Cash distributions from MEMP	$6,100,000	$26,000,000	$19,300,000

Business_Segment_Data_Schedule

Business Segment Data - Schedule of Calculation of Reportable Segment's Adjusted EBITDA (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Net income (loss)	$328,859	$112,037	($1,053,443)	($23,516)	($22,968)	$95,962	$78,158	$180	($636,063)	$151,332	$26,997
Interest expense, net									133,833	69,250	33,238
Loss on extinguishment of debt									37,248	0	0
Income tax expense (benefit)									100,971	1,619	107
DD&A									314,193	184,717	138,672
Impairment of proved oil and natural gas properties									432,116	6,600	28,871
Accretion of AROs									6,306	5,581	5,009
(Gain) loss on commodity derivative instruments									-749,988	-29,294	-34,905
Cash settlements received (paid) on commodity derivative instruments									22,688	32,119	74,299
(Gain) loss on sale of properties									3,057	-85,621	-9,761
Acquisition related costs									6,668	8,313	4,538
Compensation expense									954,627	46,837	10,933
Amortization of investment premium									0	0	194
Non-cash compensation expense										1,057
Exploration costs									16,603	2,356	9,800
Provision for environmental remediation									2,852
Loss on office lease									2,622
Cash distributions from MEMP									6,144	26,006	19,263
Adjusted EBITDA									647,733	394,856	287,992
MEMP [Member]
Segment Reporting Information [Line Items]
Impairment of proved oil and natural gas properties									407,500		28,871
Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income (loss)									-644,847	102,511	31,877
Interest expense, net									133,833	69,250	33,238
Loss on extinguishment of debt									37,248
Income tax expense (benefit)									100,971	1,619	107
DD&A									310,321	184,312	138,672
Impairment of proved oil and natural gas properties									432,116	56,889	28,871
Accretion of AROs									6,306	5,581	5,009
(Gain) loss on commodity derivative instruments									-749,988	-29,294	-34,905
Cash settlements received (paid) on commodity derivative instruments									22,688	32,119	74,299
(Gain) loss on sale of properties									3,057	-85,621	-9,761
Acquisition related costs									6,668	8,313	4,538
Compensation expense									954,627	46,837	10,933
Amortization of investment premium											194
Non-cash compensation expense										1,057
Exploration costs									16,603	2,356	9,800
Provision for environmental remediation									2,852
Loss on office lease									2,622
Non-cash equity (income) loss from MEMP									12,656	-1,847	-696
Cash distributions from MEMP									6,144	26,006	19,263
Adjusted EBITDA									653,877	420,088	311,439
Operating Segments [Member] \| MRD [Member]
Segment Reporting Information [Line Items]
Net income (loss)									-762,926	82,243	-14,641
Interest expense, net									50,283	27,349	12,802
Loss on extinguishment of debt									37,248
Income tax expense (benefit)									99,850	1,311	-178
DD&A									154,917	87,043	62,636
Impairment of proved oil and natural gas properties									24,576	2,527	18,339
Accretion of AROs									688	728	632
(Gain) loss on commodity derivative instruments									-257,734	-3,013	-13,488
Cash settlements received (paid) on commodity derivative instruments									9,166	12,240	30,188
(Gain) loss on sale of properties									3,057	-82,773	-2
Acquisition related costs									2,305	1,584	403
Compensation expense									946,753	43,279	9,510
Exploration costs									15,813	1,226	7,337
Loss on office lease									1,180
Non-cash equity (income) loss from MEMP									12,656	-1,847	-696
Cash distributions from MEMP									6,144	26,006	19,263
Adjusted EBITDA									343,976	197,903	132,105
Operating Segments [Member] \| MEMP [Member]
Segment Reporting Information [Line Items]
Net income (loss)									118,079	20,268	46,518
Interest expense, net									83,550	41,901	20,436
Income tax expense (benefit)									1,121	308	285
DD&A									155,404	97,269	76,036
Impairment of proved oil and natural gas properties									407,540	54,362	10,532
Accretion of AROs									5,618	4,853	4,377
(Gain) loss on commodity derivative instruments									-492,254	-26,281	-21,417
Cash settlements received (paid) on commodity derivative instruments									13,522	19,879	44,111
(Gain) loss on sale of properties										-2,848	-9,759
Acquisition related costs									4,363	6,729	4,135
Compensation expense									7,874	3,558	1,423
Amortization of investment premium											194
Non-cash compensation expense										1,057
Exploration costs									790	1,130	2,463
Provision for environmental remediation									2,852
Loss on office lease									1,442
Adjusted EBITDA									$309,901	$222,185	$179,334

Business_Segment_Data_Reconcil

Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA									$647,733	$394,856	$287,992
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net									-133,833	-69,250	-33,238
Loss on extinguishment of debt									-37,248	0	0
Income tax benefit (expense)									-100,971	-1,619	-107
DD&A									-314,193	-184,717	-138,672
Impairment of proved oil and natural gas properties									-432,116	-6,600	-28,871
Accretion of AROs									-6,306	-5,581	-5,009
Gains (losses) on commodity derivative instruments									749,988	29,294	34,905
Cash settlements paid (received) on commodity derivative instruments									-22,688	-32,119	-74,299
Gain (loss) on sale of properties									-3,057	85,621	9,761
Acquisition related costs									-6,668	-8,313	-4,538
Incentive-based compensation expense									-954,627	-46,837	-10,933
Non-cash compensation expense										-1,057
Exploration costs									-16,603	-2,356	-9,800
Amortization of investment premium									0	0	-194
Cash distributions from MEMP									-6,144	-26,006	-19,263
Provision for environmental remediation									-2,852
Loss on office lease									-2,622
Other non-cash equity (income) loss										784	-4,184
Net income (loss)	328,859	112,037	-1,053,443	-23,516	-22,968	95,962	78,158	180	-636,063	151,332	26,997
Reportable Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA									$653,877	$420,088	$311,439

Business_Segment_Data_Schedule1

Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil & natural gas sales									$894,967	$571,948	$393,631
Other revenues									4,378	3,075	3,237
Total revenues	226,460	245,493	236,564	190,828	152,282	153,515	147,045	122,181	899,345	575,023	396,868
Costs and expenses:
Lease operating									161,303	113,640	103,754
Pipeline operating									2,068	1,835	2,114
Exploration									16,603	2,356	9,800
Production and ad valorem taxes									45,751	27,146	23,624
Depreciation, depletion, and amortization									314,193	184,717	138,672
Impairment of proved oil and natural gas properties									432,116	6,600	28,871
Incentive unit compensation expense									943,949	43,279	9,510
General and administrative									87,673	82,079	59,677
Accretion of asset retirement obligations									6,306	5,581	5,009
(Gain) loss on commodity derivative instruments									-749,988	-29,294	-34,905
(Gain) loss on sale of properties									3,057	-85,621	-9,761
Other, net									-12	649	502
Total costs and expenses									1,263,019	352,967	336,867
Operating income (loss)	444,776	174,201	-993,256	10,605	4,411	117,797	90,327	9,521	-363,674	222,056	60,001
Other income (expense):
Interest expense, net									-133,833	-69,250	-33,238
Amortization of investment premium									0	0	-194
Loss on extinguishment of debt									-37,248	0	0
Earnings from equity investments										-784	4,184
Other, net									-337	145	535
Total other income (expense)									-171,418	-69,105	-32,897
Income (loss) before income taxes									-535,092	152,951	27,104
Income tax benefit (expense)									-100,971	-1,619	-107
Net income (loss)									-636,063	151,332	26,997
Operating Segments [Member]
Costs and expenses:
Exploration									16,603	2,356	9,800
Depreciation, depletion, and amortization									310,321	184,312	138,672
Impairment of proved oil and natural gas properties									432,116	56,889	28,871
Accretion of asset retirement obligations									6,306	5,581	5,009
(Gain) loss on commodity derivative instruments									-749,988	-29,294	-34,905
(Gain) loss on sale of properties									3,057	-85,621	-9,761
Other income (expense):
Interest expense, net									-133,833	-69,250	-33,238
Amortization of investment premium											-194
Loss on extinguishment of debt									-37,248
Income tax benefit (expense)									-100,971	-1,619	-107
Other, Adjustments & Eliminations [Member]
Revenues:
Oil & natural gas sales											-9
Other revenues									-46	-151	-360
Total revenues									-46	-151	-369
Costs and expenses:
Lease operating									-46	-259	-800
Depreciation, depletion, and amortization									3,872	405
Impairment of proved oil and natural gas properties										-50,289
General and administrative										105	431
Total costs and expenses									3,826	-50,038	-369
Operating income (loss)									-3,872	49,887
Other income (expense):
Earnings from equity investments									12,656	-1,066	-4,880
Total other income (expense)									12,656	-1,066	-4,880
Income (loss) before income taxes									8,784	48,821	-4,880
Net income (loss)									8,784	48,821	-4,880
MRD [Member] \| Operating Segments [Member]
Revenues:
Oil & natural gas sales									404,718	230,751	138,032
Other revenues									568	807	782
Total revenues									405,286	231,558	138,814
Costs and expenses:
Lease operating									26,695	25,006	24,438
Exploration									15,813	1,226	7,337
Production and ad valorem taxes									14,150	9,362	7,576
Depreciation, depletion, and amortization									154,917	87,043	62,636
Impairment of proved oil and natural gas properties									24,576	2,527	18,339
Incentive unit compensation expense									943,949	43,279	9,510
General and administrative									42,054	38,479	28,904
Accretion of asset retirement obligations									688	728	632
(Gain) loss on commodity derivative instruments									-257,734	-3,013	-13,488
(Gain) loss on sale of properties									3,057	-82,773	-2
Other, net										2	364
Total costs and expenses									968,165	121,866	146,246
Operating income (loss)									-562,879	109,692	-7,432
Other income (expense):
Interest expense, net									-50,283	-27,349	-12,802
Loss on extinguishment of debt									-37,248
Earnings from equity investments									-12,656	1,066	4,880
Other, net									-10	145	535
Total other income (expense)									-100,197	-26,138	-7,387
Income (loss) before income taxes									-663,076	83,554	-14,819
Income tax benefit (expense)									-99,850	-1,311	178
Net income (loss)									-762,926	82,243	-14,641
MEMP [Member]
Costs and expenses:
Impairment of proved oil and natural gas properties									407,500		28,871
MEMP [Member] \| Operating Segments [Member]
Revenues:
Oil & natural gas sales									490,249	341,197	255,608
Other revenues									3,856	2,419	2,815
Total revenues									494,105	343,616	258,423
Costs and expenses:
Lease operating									134,654	88,893	80,116
Pipeline operating									2,068	1,835	2,114
Exploration									790	1,130	2,463
Production and ad valorem taxes									31,601	17,784	16,048
Depreciation, depletion, and amortization									155,404	97,269	76,036
Impairment of proved oil and natural gas properties									407,540	54,362	10,532
General and administrative									45,619	43,495	30,342
Accretion of asset retirement obligations									5,618	4,853	4,377
(Gain) loss on commodity derivative instruments									-492,254	-26,281	-21,417
(Gain) loss on sale of properties										-2,848	-9,759
Other, net									-12	647	138
Total costs and expenses									291,028	281,139	190,990
Operating income (loss)									203,077	62,477	67,433
Other income (expense):
Interest expense, net									-83,550	-41,901	-20,436
Amortization of investment premium											-194
Other, net									-327
Total other income (expense)									-83,877	-41,901	-20,630
Income (loss) before income taxes									119,200	20,576	46,803
Income tax benefit (expense)									-1,121	-308	-285
Net income (loss)									$118,079	$20,268	$46,518

Income_Taxes_Components_of_Inc

Income Taxes - Components of Income Tax Expense (Benefit) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current taxes:
State	$22	($1,619)	$178
Deferred taxes:
Federal	-88,994
State	-11,999		-285
Total income tax benefit (expense)	($100,971)	($1,619)	($107)

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Details) (USD $)	12 Months Ended
Income Taxes - Additional Information (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Federal statutory corporate tax rate	35.00%
Unrecognized tax benefits	$0	$0	$0
Interest and penalties on unrecognized benefits	0	0	0
United States [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	74,300,000
Operating loss carryforwards expiration start year	2027
Operating loss carryforwards expiration end year	2035
State [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$65,000,000
Minimum [Member] \| State [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards periods	10 years
Maximum [Member] \| State [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards periods	20 years

Income_Taxes_Reconciliation_of

Income Taxes - Reconciliation of Income Tax Benefit (Provision) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Income Tax Disclosure [Abstract]
Expected tax benefit (expense)	$187,282		($53,533)		($9,486)
State income tax expense, net of federal benefit	-9,660		-1,619		-107
Pass-through entities (1)	49,989	[1]	53,533	[1]	9,486	[1]
Stock compensation (2)	-330,024	[2]
Other	1,442
Total income tax benefit (expense)	($100,971)		($1,619)		($107)

[1]	MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes.
[2]	As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes.

Income_Taxes_Components_of_Net

Income Taxes - Components of Net Deferred Income Tax Assets and (Liabilities) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred current income tax assets:
Unrealized hedging transactions	$109	$37
Accrued liabilities		5
Other	342	-42
Deferred current income tax assets:	451
Deferred current income tax liabilities:
Unrealized hedging transactions	-52,328
Other	-52	-382
Deferred current income tax liabilities:	-52,380	-382
Deferred noncurrent income tax assets:
Net operating loss carryforward	28,043	2,350
Asset retirement obligation	5,757	971
Other	3,224	1
Net deferred tax valuation allowance	-2,634	-2,896
Deferred noncurrent income tax assets:	34,390	426
Deferred noncurrent income tax liabilities:
Property, plant and equipment	-80,198	-3,318
Unrealized hedging transactions	-48,929	-275
Other	-280	61
Deferred noncurrent income tax liabilities:	-129,407	-3,532
Net current deferred income tax assets (liabilities)	-51,929	-382
Net noncurrent deferred income tax assets (liabilities)	($95,017)	($3,106)

Commitments_and_Contingencies_1

Commitments and Contingencies - Environmental Reserves Activity (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies Disclosure [Abstract]
Balance at beginning of period	$577	$1,469	$1,747
Charged to costs and expenses	2,852		193
Payments	-1,337	-892	-471
Balance at end of period	$2,092	$577	$1,469

Commitments_and_Contingencies_2

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 01, 2014	Jan. 01, 2015	Dec. 31, 2011	Jun. 30, 2010	Mar. 01, 2007
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 01, 2014	MMBTU_day	Dec. 31, 2011	Jun. 30, 2010	Mar. 01, 2007
Commitments And Contingencies (Additional Textual) [Abstract]
Accrued liabilities	$2,092,000	$577,000	$1,469,000			$1,747,000
Amount per barrel of oil	0.25
Aggregate value of account required to cease fund	4,300,000
Restricted investment	2,700,000
Percentage of working interest under sinking fund trust agreement	51.75%
Additional quarterly payments							600,000
Maximum remaining obligation	8,700,000
Rent expense	10,800,000	8,300,000	5,000,000
Dubach [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Expansion of processing plant			70
Dubberly [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Payback demand fee received by the third party		110.00%
Payback demand quality per day				192,950
Payback of fee in excess of demand quantity				0.275
Subsequent Event [Member] \| Dubberly [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Monthly demand quantity					249,700
December 31, 2016 [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Minimum balances attributable to net working interest	78,660,000
REO Sponsorship [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Supplemental bond for decommissioning liabilities trust agreement								90,000,000
Maximum [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Remaining obligation	$800,000

Commitments_and_Contingencies_3

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
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

Commitments_and_Contingencies_4

Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Held-to-maturity Securities [Abstract]
Less: Outside working interest owners share, Amortized Cost	($65,222)
Restricted investments	77,361	73,385
BOEM platform abandonment [Member]
Held-to-maturity Securities [Abstract]
Restricted investments	69,954	66,373
Money Market Funds [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$135,176

Commitments_and_Contingencies_5

Commitments and Contingencies - CO2 Minimum Purchase Commitment (Detail) (Wyoming Acquisition [Member], USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Wyoming Acquisition [Member]
Minimum Purchase Commitment [Line Items]
Estimated payment obligation, Total	$50,495
Estimated payment obligation, 2015	9,608
Estimated payment obligation, 2016	10,179
Estimated payment obligation, 2017	10,151
Estimated payment obligation, 2018	6,995
Estimated payment obligation, 2019	7,060
Estimated payment obligation, Thereafter	$6,502

Commitments_and_Contingencies_6

Commitments and Contingencies - Minimum Commitments to Gather before Other Owner Contributions (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Dubach [Member]
Other Commitments [Line Items]
2015	$13,671
2016	13,709
2017	13,671
2018	12,772
Total	53,823
Dubberly [Member]
Other Commitments [Line Items]
2015	11,393
2016	11,424
2017	11,393
2018	10,643
Total	$44,853

Commitments_and_Contingencies_7

Commitments and Contingencies - Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
MRD [Member]
Operating leases
Total	$43,625
2015	6,534
2016	6,607
2017	6,694
2018	6,259
2019	5,960
Thereafter	11,571
Sublease rental income
Sublease rental income, Total	5,786
Sublease rental income, 2015	1,691
Sublease rental income, 2016	1,579
Sublease rental income, 2017	1,197
Sublease rental income, 2018	814
Sublease rental income, 2019	431
Sublease rental income, Thereafter	74
MEMP [Member]
Operating leases
Total	3,665
2015	788
2016	416
2017	205
2018	205
2019	205
Thereafter	$1,846

Defined_Contribution_Plans_Add

Defined Contribution Plans - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Contribution Plan Disclosure [Line Items]
Employee eligibility age	18 years
Tax-deferred contributions	100.00%
Matching contribution	100.00%
Contribution By Participants, Percentage	6.00%
Employer contributions	$1.40	$0.90	$0.40
REO Sponsorship [Member]
Defined Contribution Plan Disclosure [Line Items]
Employee eligibility age	21 years
Tax-deferred contributions	100.00%
Matching contribution	100.00%
Contribution By Participants, Percentage	6.00%
Employer contributions		0.6	0.5
Defined contribution plan, company contribution, vesting period, years	3 years
Defined benefit plan cost and expense		0.3	0.3
WildHorse, Tanos, BlueStone, Classic and Black Diamond [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer contributions	0.2	0.5	0.6
Crown and Stanolind [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer contributions		$0.10	$0.10

Quarterly_Financial_Informatio2

Quarterly Financial Information (Unaudited) - Schedule of Quarterly Financial Information (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Abstract]
Revenues	$226,460	$245,493	$236,564	$190,828	$152,282	$153,515	$147,045	$122,181	$899,345	$575,023	$396,868
Operating income (loss)	444,776	174,201	-993,256	10,605	4,411	117,797	90,327	9,521	-363,674	222,056	60,001
Net income (loss)	328,859	112,037	-1,053,443	-23,516	-22,968	95,962	78,158	180	-636,063	151,332	26,997
Net income (loss) attributable to noncontrolling interest	161,661	102,109	-105,094	-31,888	7,689	11,235	34,975	-4,069	126,788	49,830	-2,701
Net income (loss) attributable to Memorial Resource Development Corp.	167,198	9,928	-948,349	8,372	-30,657	84,727	43,183	4,249	-762,851	101,502	29,698
Net income (loss) allocated to members			13,358	6,947	-31,917	84,754	35,278	2,597	20,305	90,712	-7,620
Net income (loss) allocated to previous owners				1,425	1,260	-27	7,905	1,652	1,425	10,790	37,318
Net income (loss) available to common stockholders	$167,198	$9,928	($961,707)						($784,581)	$0	$0
Basic EPS	$0.87	$0.05	($5)						($4.08)	$0	$0
Diluted EPS	$0.87	$0.05	($5)						($4.08)	$0	$0

Capitalized_Costs_Relating_to_

Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated oil and natural gas properties	$4,598,211	[1]	$2,974,855	[1]	$2,591,861	[1]
Support equipment and facilities	185,997		5,910		5,760
Unevaluated oil and natural gas properties	48,229		46,413		31,593
Accumulated depletion, depreciation, and amortization	-1,334,235	[1]	-623,362	[1]	-468,291	[1]
Subtotal	3,498,202		2,403,816		2,160,923
Eliminations [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Accumulated depletion, depreciation, and amortization	46,013		49,884
MRD [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated oil and natural gas properties	1,590,997		1,226,417		1,052,219
Unevaluated oil and natural gas properties	48,229		46,413		26,589
Accumulated depletion, depreciation, and amortization	-391,145		-256,629		-202,581
Subtotal	1,248,081		1,016,201		876,227
MEMP [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated oil and natural gas properties	3,007,214	[1]	1,748,438	[1]	1,539,642	[1]
Support equipment and facilities	185,997		5,910		5,760
Unevaluated oil and natural gas properties					5,004
Accumulated depletion, depreciation, and amortization	-989,103	[1]	-416,617	[1]	-265,710	[1]
Subtotal	$2,204,108		$1,337,731		$1,284,696

[1]	Amounts do not include costs for SPBPC and related support equipment.

Costs_Incurred_for_Property_Ac

Costs Incurred for Property Acquisition, Exploration and Development (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved	$1,057,566		$93,894		$366,103
Property acquisition costs, unproved	25,030		19,975		5,293
Exploration and extension well costs	209,532		13,313		42,642
Development	487,777	[1]	356,270	[1]	198,423	[1]
Subtotal	1,779,905		483,452		612,461
MRD [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved	74,490		56,108		87,857
Property acquisition costs, unproved	25,030		19,975		5,293
Exploration and extension well costs	209,532		13,313		212
Development	208,459		210,440		135,951
Subtotal	517,511		299,836		229,313
MEMP [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved	983,076		37,786		278,246
Exploration and extension well costs					42,430
Development	279,318	[1]	145,830	[1]	62,472	[1]
Subtotal	$1,262,394		$183,616		$383,148

[1]	Amounts do not include costs for SPBPC and related support equipment.

Weighted_Average_Product_Price

Weighted Average Product Price (Detail)	12 Months Ended
Weighted Average Product Price (Detail)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Oil [Member] \| West Texas Intermediate [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price	91.48	[1]	93.42	[1]	91.33	[1]
Natural Gas Liquids [Member] \| West Texas Intermediate [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price	91.48	[1]	93.42	[1]	91.75	[1]
Natural Gas [Member] \| Henry Hub [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price	4.35	[2]	3.67	[2]	2.75	[2]

[1]	The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.
[2]	The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

Reserve_Quantity_Information_D

Reserve Quantity Information (Detail)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	MBbls		MBbls		MBbls
MRD [Member] \| Oil [Member]
Proved developed and undeveloped reserves:
Beginning of the year	11,311	[1]	11,953	[2]	10,834
Extensions and discoveries	1,825		1,794		689
Purchase of minerals in place	269		211		1,100
Production	-951		-665		-369
Sales of minerals in place	-623		-599		-4
Revision of previous estimates	772		-1,383		-297
End of year	12,603		11,311	[1]	11,953	[2]
Proved developed reserves:
Beginning of year	3,402		3,082		2,107
End of year	3,905		3,402		3,082
Proved undeveloped reserves:
Beginning of year	7,909		8,871		8,727
End of year	8,698		7,909		8,871
MRD [Member] \| Natural Gas [Member]
Proved developed and undeveloped reserves:
Beginning of the year	802,254	[1]	739,378	[2]	929,335
Extensions and discoveries	183,527		149,974		42,019
Purchase of minerals in place	22,186		31,815		28,115
Production	-63,801		-34,092		-24,131
Sales of minerals in place	-10,815		-14,137		-728
Revision of previous estimates	247,578		-70,684		-235,232
End of year	1,180,929		802,254	[1]	739,378	[2]
Proved developed reserves:
Beginning of year	263,797		245,449		191,557
End of year	392,181		263,797		245,449
Proved undeveloped reserves:
Beginning of year	538,457		493,929		737,778
End of year	788,748		538,457		493,929
MRD [Member] \| Natural Gas Liquids [Member]
Proved developed and undeveloped reserves:
Beginning of the year	42,576	[1]	41,466	[2]	53,031
Extensions and discoveries	9,876		8,319		2,778
Purchase of minerals in place	1,247		1,017		1,879
Production	-2,220		-1,457		-898
Sales of minerals in place	-950		-1,573
Revision of previous estimates	12,060		-5,196		-15,324
End of year	62,589		42,576	[1]	41,466	[2]
Proved developed reserves:
Beginning of year	13,904		12,321		7,644
End of year	19,924		13,904		12,321
Proved undeveloped reserves:
Beginning of year	28,672		29,145		45,387
End of year	42,665		28,672		29,145
MRD [Member] \| Natural Gas Equivalent [Member]
Proved developed and undeveloped reserves:
Beginning of the year	1,125,577	[1]	1,059,895	[2]	1,312,533
Extensions and discoveries	253,730		210,652		62,819
Purchase of minerals in place	31,283		39,183		45,987
Production	-82,816		-46,819		-31,731
Sales of minerals in place	-20,253		-27,169		-752
Revision of previous estimates	324,558		-110,165		-328,961
End of year	1,632,079		1,125,577	[1]	1,059,895	[2]
Proved developed reserves:
Beginning of year	367,641		337,869		250,073
End of year	535,151		367,641		337,869
Proved undeveloped reserves:
Beginning of year	757,936		722,026		1,062,460
End of year	1,096,928		757,936		722,026
MEMP [Member] \| Oil [Member]
Proved developed and undeveloped reserves:
Beginning of the year	39,149	[3]	39,089	[4]	27,150
Extensions and discoveries	849		5,655		7,501
Purchase of minerals in place	69,095		119		11,336
Production	-3,092		-1,764		-1,519
Sales of minerals in place					-4,214
Revision of previous estimates	-6,431		-3,950		-1,165
End of year	99,570	[5]	39,149	[3]	39,089	[4]
Proved developed reserves:
Beginning of year	22,265		24,515		19,332
End of year	54,526		22,265		24,515
Proved undeveloped reserves:
Beginning of year	16,884		14,574		7,818
End of year	45,044		16,884		14,574
MEMP [Member] \| Natural Gas [Member]
Proved developed and undeveloped reserves:
Beginning of the year	607,139	[3]	604,440	[4]	579,751
Extensions and discoveries	12,723		40,770		19,869
Purchase of minerals in place	13,036		16,294		113,617
Production	-41,494		-35,924		-29,744
Sales of minerals in place					-4,214
Revision of previous estimates	-31,777		-18,441		-74,839
End of year	559,627	[5]	607,139	[3]	604,440	[4]
Proved developed reserves:
Beginning of year	387,548		376,932		413,431
End of year	380,397		387,548		376,932
Proved undeveloped reserves:
Beginning of year	219,591		227,508		166,320
End of year	179,230		219,591		227,508
MEMP [Member] \| Natural Gas Liquids [Member]
Proved developed and undeveloped reserves:
Beginning of the year	28,846	[3]	29,352	[4]	15,045
Extensions and discoveries	711		1,747		1,053
Purchase of minerals in place	22,351		258		7,095
Production	-2,143		-1,632		-745
Revision of previous estimates	-287		-879		6,904
End of year	49,478	[5]	28,846	[3]	29,352	[4]
Proved developed reserves:
Beginning of year	15,959		15,947		10,015
End of year	35,539		15,959		15,947
Proved undeveloped reserves:
Beginning of year	12,887		13,405		5,030
End of year	13,939		12,887		13,405
MEMP [Member] \| Natural Gas Equivalent [Member]
Proved developed and undeveloped reserves:
Beginning of the year	1,015,105	[3]	1,015,095	[4]	832,913
Extensions and discoveries	22,085		85,180		71,192
Purchase of minerals in place	561,713		18,554		224,202
Production	-72,902		-56,303		-43,329
Sales of minerals in place					-29,499
Revision of previous estimates	-72,090		-47,421		-40,384
End of year	1,453,911	[5]	1,015,105	[3]	1,015,095	[4]
Proved developed reserves:
Beginning of year	616,893		619,704		589,504
End of year	920,783		616,893		619,704
Proved undeveloped reserves:
Beginning of year	398,212		395,391		243,409
End of year	533,128		398,212		395,391

[1]	Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners.
[2]	Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners.
[3]	MRD Segmentbs share of these reserves is 89,837 MMcfe.
[4]	MRD Segmentbs share of these reserves is 476,550 MMcfe.
[5]	MRD Segmentbs share of these reserves is 1,454 MMcfe.

Reserve_Quantity_Information_P

Reserve Quantity Information (Parenthetical) (Detail) (Natural Gas Equivalent [Member])	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	MMcfe	MMcfe		MMcfe		MMcfe
MRD [Member]
Reserve Quantities [Line Items]
End of year	1,632,079	1,125,577	[1]	1,059,895	[2]	1,312,533
Parent Company \| MRD [Member]
Reserve Quantities [Line Items]
End of year	1,454	89,837		476,550
Noncontrolling Interest [Member]
Reserve Quantities [Line Items]
End of year		41,077		67,135

[1]	Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners.
[2]	Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners.

Recovered_Sheet1

Supplemental Oil And Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013
	Bcfe	Bcfe	Bcfe
Reserve Quantities [Line Items]
Multiple acquisitions	561.7	224.2
MRD [Member]
Reserve Quantities [Line Items]
Upward revisions in proved reserve	324.6
MRD [Member] \| WildHorse Resources, LLC [Member]
Reserve Quantities [Line Items]
Extensions and discoveries			148.6
Multiple acquisitions		43.5
Terryville Acquisition [Member] \| MRD [Member]
Reserve Quantities [Line Items]
Extensions and discoveries	253.7
Multiple acquisitions	31.3
Wyoming Acquisition [Member]
Reserve Quantities [Line Items]
Multiple acquisitions, Largest acquisition	497.2
Eagle Ford Acquisition [Member]
Reserve Quantities [Line Items]
Multiple acquisitions	45
Goodrich [Member]
Reserve Quantities [Line Items]
Multiple acquisitions, Largest acquisition		148.9
Stanolind [Member]
Reserve Quantities [Line Items]
Multiple acquisitions		43.6
Menemsha [Member]
Reserve Quantities [Line Items]
Multiple acquisitions, Largest acquisition		23.9
Propel [Member]
Reserve Quantities [Line Items]
Divestiture of Oil and Gas Properties		19

Discounted_Future_Net_Cash_Flo

Discounted Future Net Cash Flows (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
MRD [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Future cash inflows	$8,313,329		$5,722,848		$4,921,192
Future production costs	-1,325,573		-1,587,374		-1,255,289
Future development costs	-1,443,612		-1,352,945		-1,060,777
Future income tax expense	-1,789,031	[1]
Future net cash flows for estimated timing of cash flows	3,755,113		2,782,529		2,605,126
10% annual discount for estimated timing of cash flows	-1,792,579		-1,313,577		-1,284,531
Standardized measure of discounted future net cash flows	1,962,534	[2]	1,468,952	[2]	1,320,595	[2]	1,386,071
MEMP [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Future cash inflows	13,191,866		6,892,150		6,511,776
Future production costs	-4,516,077		-2,719,024		-2,258,554
Future development costs	-1,222,221		-685,858		-620,944
Future net cash flows for estimated timing of cash flows	7,453,568	[3]	3,487,268	[3]	3,632,278	[3]
10% annual discount for estimated timing of cash flows	-4,693,960		-1,879,156		-2,042,362
Standardized measure of discounted future net cash flows	$2,759,608	[4]	$1,608,112	[4]	$1,589,916	[4]	$1,499,414

[1]	Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended DecemberB 31, 2013 and 2012.
[2]	Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended DecemberB 31, 2013 and 2012, respectively.
[3]	MEMP is subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the years ended DecemberB 31, 2014, 2013 and 2012.
[4]	MRD Segmentbs share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively.

Discounted_Future_Net_Cash_Flo1

Discounted Future Net Cash Flows (Parenthetical) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
MRD [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	1,962,534	[1]	1,468,952	[1]	1,320,595	[1]	$1,386,071
MRD [Member] \| Parent Company
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	2,760		142,318		554,981
MRD [Member] \| Maximum [Member] \| Texas Margin Tax [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Franchise effective tax rate	0.70%		0.70%		0.70%
MEMP [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	2,759,608	[2]	1,608,112	[2]	1,589,916	[2]	1,499,414
MEMP [Member] \| Maximum [Member] \| Texas Margin Tax [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Franchise effective tax rate	0.70%		0.70%		0.70%
Noncontrolling Interest [Member] \| Previous Owners [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows			63,422		78,518

[1]	Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended DecemberB 31, 2013 and 2012, respectively.
[2]	MRD Segmentbs share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively.

Summary_of_the_Changes_in_the_

Summary of the Changes in the Standardized Measure of Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014						Dec. 31, 2013		Dec. 31, 2012
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
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 the offshore Southern California oil and gas properties owned by MEMP.
	The components of the restricted investment balance are as follows at December 31, 2014 and 2013:
		2014		2013
		(In thousands)
	BOEM platform abandonment (See Note 16)	$	69,954	$	66,373
	BOEM lease bonds		794		794

	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,701		2,306
	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	$	77,361	$	73,385

MRD [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Beginning of year	$1,468,952					[1]	$1,320,595	[1]	$1,386,071
Sale of oil and natural gas produced, net of production costs	-363,723						-196,444		-107,316
Purchase of minerals in place	69,282						51,177		98,384
Sale of minerals in place	-47,791						-54,091
Extensions and discoveries	653,186						301,004		127,994
Changes in income taxes, net	-1,058,814
Changes in prices and costs	365,030						-11,336		-402,202
Previously estimated development costs incurred	256,605						87,297		64,390
Net changes in future development costs	-126,598						57,353		-67,331
Revisions of previous quantities	828,296						-186,804		-176,788
Accretion of discount	146,896						128,544		138,607
Change in production rates and other	-228,787						-28,343		258,786
End of year	1,962,534					[1]	1,468,952	[1]	1,320,595	[1]
MEMP [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Beginning of year	1,608,112					[2]	1,589,916	[2]	1,499,414
Sale of oil and natural gas produced, net of production costs	-323,994						-234,520		-160,023
Purchase of minerals in place	1,489,477						23,160		375,953
Sale of minerals in place									-154,963
Extensions and discoveries	44,745						136,423		265,108
Changes in income taxes, net									1,947
Changes in prices and costs	-168,500						-74,395		-331,760
Previously estimated development costs incurred	223,861						174,490		66,360
Net changes in future development costs	-74,579						-74,867		-1,140
Revisions of previous quantities	-163,207						-141,122		-90,587
Accretion of discount	160,811						158,991		150,136
Change in production rates and other	-37,118						50,036		-30,529
End of year	$2,759,608					[2]	$1,608,112	[2]	$1,589,916	[2]

[1]	Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended DecemberB 31, 2013 and 2012, respectively.
[2]	MRD Segmentbs share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively.