Memorial Resource Development 10-Q 5 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Trading Symbol	MRD
Entity Registrant Name	MEMORIAL RESOURCE DEVELOPMENT CORP.
Entity Central Index Key	1,599,222
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		191,532,159

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 4,701	$ 5,958
Accounts receivable:
Oil and natural gas sales	59,627	82,263
Joint interest owners and other	49,712	49,313
Short-term derivative instruments	290,045	340,056
Prepaid expenses and other current assets	29,882	28,027
Total current assets	433,967	505,617
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	5,183,656	4,844,529
Other	26,715	33,815
Accumulated depreciation, depletion and impairment	(1,740,452)	(1,340,688)
Property and equipment, net	3,469,919	3,537,656
Long-term derivative instruments	461,844	435,369
Restricted investments	80,096	77,361
Other long-term assets	34,477	37,544
Total assets	4,480,303	4,593,547
Current liabilities:
Accounts payable	25,367	25,772
Accounts payable - affiliates	5,184	624
Revenues payable	66,940	57,352
Accrued liabilities	249,266	199,000
Short-term derivative instruments	2,986	3,289
Total current liabilities	349,743	286,037
Noncurrent liabilities:
Long-term debt	2,588,650	2,378,413
Asset retirement obligations	126,708	122,531
Long-term derivative instruments	674
Deferred tax liabilities	80,675	95,017
Other long-term liabilities	7,394	8,585
Total liabilities	$ 3,153,844	$ 2,890,583
Commitments and contingencies (Note 15)
Stockholders' equity (deficit):
Preferred stock, $.01 par value: 50,000,000 shares authorized; no shares issued and outstanding
Common stock, $.01 par value: 600,000,000 shares authorized; 191,527,728 shares issued and outstanding at June 30, 2015; 193,435,414 shares issued and outstanding at December 31, 2014	$ 1,915	$ 1,935
Additional paid-in capital	1,297,944	1,367,346
Accumulated earnings (deficit)	(813,779)	(786,871)
Total stockholders' equity	486,080	582,410
Noncontrolling interests	840,379	1,120,554
Total equity	1,326,459	1,702,964
Total liabilities and equity	4,480,303	4,593,547
MRD Segment [Member]
Noncurrent liabilities:
Long-term debt	765,000	783,000
MEMP [Member]
Noncurrent liabilities:
Long-term debt	$ 1,823,650	1,595,413
Deferred tax liabilities		$ 29,200

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Jun. 30, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	191,527,728	193,435,414
Common stock, shares outstanding	191,527,728	193,435,414

UNAUDITED CONDENSED STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Oil & natural gas sales	$ 175,826	$ 253,436	$ 354,798	$ 457,146
Other revenues	917	1,341	1,786	2,252
Total revenues	176,743	254,777	356,584	459,398
Costs and expenses:
Lease operating	48,742	32,321	94,442	65,676
Gathering, processing, and transportation	23,337	17,886	46,320	32,006
Gathering, processing, and transportation - affiliate (Note 13)	3,813		3,813
Pipeline operating	500	676	946	1,165
Exploration	2,262	1,144	3,078	1,290
Production and ad valorem taxes	9,198	10,999	18,628	19,583
Depreciation, depletion, and amortization	82,113	73,780	173,911	131,459
Impairment of proved oil and natural gas properties			251,347
Incentive unit compensation expense (Note 12)	16,116	942,817	26,340	943,840
General and administrative	24,700	22,126	52,187	39,865
Accretion of asset retirement obligations	1,779	1,527	3,536	3,048
(Gain) loss on commodity derivative instruments	91,866	141,590	(161,783)	201,072
(Gain) loss on sale of properties	50	3,167	50	3,057
Other, net	(943)		(943)	(12)
Total costs and expenses	303,533	1,248,033	511,872	1,442,049
Operating income (loss)	(126,790)	(993,256)	(155,288)	(982,651)
Other income (expense):
Interest expense, net	(37,523)	(34,531)	(76,097)	(68,583)
Loss on extinguishment of debt		(37,248)		(37,248)
Other, net	72	56	183	87
Total other income (expense)	(37,451)	(71,723)	(75,914)	(105,744)
Income (loss) before income taxes	(164,241)	(1,064,979)	(231,202)	(1,088,395)
Income tax benefit (expense)	23,768	11,536	(21,420)	11,436
Net income (loss)	(140,473)	(1,053,443)	(252,622)	(1,076,959)
Net income (loss) attributable to noncontrolling interest	(113,771)	(105,094)	(274,666)	(136,982)
Net income (loss) attributable to Memorial Resource Development Corp.	(26,702)	(948,349)	22,044	(939,977)
Net (income) loss allocated to members		(13,358)		(20,305)
Net (income) loss allocated to previous owners				(1,425)
Net (income) allocated to participating restricted stockholders			(150)
Net income (loss) available to common stockholders	$ (26,702)	$ (961,707)	$ 21,894	$ (961,707)
Earnings per common share: (Note 10)
Basic	$ (0.14)	$ (5)	$ 0.12	$ (5)
Diluted	$ (0.14)	$ (5)	$ 0.12	$ (5)
Weighted average common and common equivalent shares outstanding:
Basic	189,628	192,500	190,163	192,500
Diluted	189,628	192,500	190,163	192,500

UNAUDITED CONDENSED STATEMENTS5

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net income (loss)	$ (252,622)	$ (1,076,959)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	173,911	131,459
Impairment of proved oil and natural gas properties	251,347
(Gain) loss on derivatives	(158,697)	202,395
Cash settlements (paid) received on expired derivative instruments	182,603	(25,447)
Cash settlements on terminated derivatives	27,063
Premiums paid for derivatives	(27,063)
Loss on extinguishment of debt		30,248
Amortization of deferred financing costs	4,449	3,587
Accretion of senior notes net discount	1,204	1,319
Accretion of asset retirement obligations	3,536	3,048
Amortization of equity awards	8,349	3,134
Settlement of asset retirement obligations	(780)
(Gain) loss on sale of properties	50	3,057
Non-cash compensation expense	26,340	916,109
Deferred income tax expense (benefit)	13,560	(11,955)
Changes in operating assets and liabilities:
Accounts receivable	11,882	(26,847)
Prepaid expenses and other assets	1,282	(119)
Payables and accrued liabilities	36,702	21,574
Other	(1,329)	3,144
Net cash provided by operating activities	301,787	177,747
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(6,095)	(173,000)
Acquisition post-closing adjustment receipts	9,570
Additions to oil and gas properties	(335,426)	(293,567)
Additions to other property and equipment	(3,370)	(1,268)
Additions to restricted investments	(2,735)	(2,121)
Deposits for property acquisitions		(70,125)
Decrease (increase) in restricted cash		49,946
Proceeds from the sale of oil and natural gas properties	13,612	6,700
Other		(301)
Net cash used in investing activities	(324,444)	(483,736)
Cash flows from financing activities:
Advances on revolving credit facilities	433,000	1,548,800
Payments on revolving credit facilities	(221,000)	(776,900)
Termination of second lien credit facility		(328,282)
Redemption of senior notes	(2,914)	(351,808)
Deferred financing costs	(235)	(6,234)
Purchase of additional interests in consolidated subsidiaries		(3,292)
Proceeds from initial public offering		408,500
Costs incurred in conjunction with initial public offering		(26,875)
Distributions to noncontrolling interests	(92,477)	(61,844)
Repurchased shares under repurchase program	(94,974)
Other		270
Net cash provided by financing activities	21,400	244,234
Net change in cash and cash equivalents	(1,257)	(61,755)
Cash and cash equivalents, beginning of period	5,958	77,721
Cash and cash equivalents, end of period	4,701	15,966
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of assets		1,165
Distribution to NGP affiliates related to purchase of assets		(66,693)
Distribution to NGP affiliates related to sale of assets, net of cash received		(32,770)
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distribution to MRD Holdco		(59,803)
MRD Segment [Member]
Cash flows from financing activities:
Proceeds from initial public offering		$ 408,500
Repurchased shares under repurchase program	(51,197)
MEMP [Member]
Cash flows from financing activities:
Repurchased shares under repurchase program	$ (43,777)

UNAUDITED CONDENSED STATEMENTS6

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ in Thousands	Total	MEMP [Member]	MRD Segment [Member]	Member Equity [Member]	Common Stock [Member]	Common Stock [Member]MRD Segment [Member]	Additional paid in capital [Member]	Accumulated earnings (deficit) [Member]	Accumulated earnings (deficit) [Member]MRD Segment [Member]	Previous Owners [Member]Member Equity [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member]MEMP [Member]
Total equity, beginning balance at Dec. 31, 2013	$ 858,132										$ 580,615
Members' equity, beginning balance at Dec. 31, 2013				$ 237,186						$ 40,331
Net income (loss)	(1,076,959)			20,305				$ (961,707)		1,425	(136,982)
Issuance of shares in connection with restructuring transactions	914,862				$ 1,710		$ 913,152
Issuance of shares in connection with initial public offering	380,668				215		380,453
Restricted stock awards					11		(11)
Tax related effects in connection with restructuring transactions and initial public offering	(43,251)						(43,251)
Contribution related to MRD Holdco incentive unit compensation expense	111,757						111,757
Contribution related to sale of assets to NGP affiliate	1,165			1,165
Net book value of assets sold to NGP affiliate	(621)			(621)
Distributions	(61,844)										(61,844)
Net book value of assets acquired from NGP affiliates	3,303			45,059						$ (41,756)
Purchase of noncontrolling interest	(3,292)						(2,881)				(411)
Distribution of net assets to MRD Holdco	(93,084)			(123,078)							29,994
Distribution of shares received in connection with restructuring transactions to MRD Holdco	(110,510)			(110,510)
Distribution to NGP affiliates in connection with acquisition of assets	(66,693)			(66,693)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP				(2,659)							2,659
Amortization of MEMP equity awards	3,134						174				2,960
Other	(115)			$ (154)			384				(345)
Total equity, ending balance at Jun. 30, 2014	816,652										416,646
Total stockholders equity, ending balance at Jun. 30, 2014					1,936		1,359,777	(961,707)
Total equity, beginning balance at Dec. 31, 2014	1,702,964										1,120,554
Total stockholders equity, beginning balance at Dec. 31, 2014	582,410				1,935		1,367,346	(786,871)
Net income (loss)	(252,622)							22,044			(274,666)
Share repurchase	(47,785)	$ (45,117)			(28)			(47,757)				$ (45,117)
Restricted stock awards					9		(9)
Amortization of restricted stock awards	3,443						3,443
Contribution related to MRD Holdco incentive unit compensation expense	26,340						26,340
Deferred tax effect of MEMP property exchange (Note 2)	28,020						28,020
Distributions	(92,477)										(92,477)
Amortization of MEMP equity awards	4,906										4,906
Restricted stock awards			$ (1,196)			$ (1)			$ (1,195)
Other	(17)						(47)				30
Total equity, ending balance at Jun. 30, 2015	1,326,459										840,379
Total stockholders equity, ending balance at Jun. 30, 2015	$ 486,080				$ 1,908		1,234,021	$ (785,591)
Net equity deemed contribution (distribution) related to MEMP property exchange (Note 1)							$ (127,149)				$ 127,149

Background, Organization and Ba

Background, Organization and Basis of Presentation	6 Months Ended
	Jun. 30, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Background, Organization and Basis of Presentation	Note 1. Background, Organization and Basis of Presentation Overview Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to the net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of certain acquisitions in 2010, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. Our unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI. Basis of Presentation The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: · MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries. · MEMP—reflects the combined operations of MEMP and its subsidiaries. Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction. Use of Estimates The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations, income taxes and asset retirement obligations.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies A discussion of our critical accounting policies and estimates is included in our Current Report on Form 8-K filed on July 8, 2015 (our “Recast Form 8-K”). Our Recast Form 8-K was filed to retrospectively revise certain historical segment financial information to give effect to the Property Swap for comparability purposes and Accrued liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): June 30, December 31, 2015 2014 Accrued capital expenditures $ 107,344 $ 80,350 Accrued lease operating expense 23,524 16,403 Accrued general and administrative expenses 13,324 8,516 Accrued ad valorem taxes 11,442 8,870 Accrued interest payable 27,118 24,797 Accrued environmental 1,147 2,092 Accrued current and deferred income taxes 58,597 51,929 Other miscellaneous, including operator advances 6,770 6,043 $ 249,266 $ 199,000 Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2015 June 30, 2014 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 85,019 $ 65,641 Cash paid for taxes 2,055 550 Noncash investing and financing activities: (Increase) decrease in capital expenditures in payables and accrued liabilities (26,994 ) (3,526 ) (Increase) decrease in accounts receivable related to acquisitions and divestitures 9,570 (4,732 ) Repurchases under MEMP repurchase program 2,710 — Income Tax MRD is a corporation subject to federal and certain state income taxes. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes. As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. MRD’s predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes. MRD reported no liability for unrecognized tax benefits as of June 30, 2015 and expects no significant change to the unrecognized tax benefits in the next twelve months. MRD’s effective tax rate for the three and six months ended June 30, 2015 was 14.5% and negative 9.3%, respectively, and the effective tax rate for both the three and six months ended June 30, 2014 was 1.1%. The effective tax rate for the three and six months ended June 30, 2014 and 2015 differs from the statutory federal income tax rate primarily due to the following recurring items: · earnings from the MEMP Segment pass-through entities; · non-deductible incentive unit compensation; and · state income tax, net of federal benefit. MRD had a net noncurrent deferred income tax liability of $95.0 million at December 31, 2014, of which $29.2 million was attributable to certain oil and gas properties in East Texas that MEMP acquired from MRD in February 2015 as noted above. A deferred income tax benefit of $1.2 million associated with these oil and gas properties was recorded during February 2015. As such, a net deferred income tax liability of $28.0 million has been reversed through additional paid in capital in MRD’s equity statement. New Accounting Pronouncements Presentation of Debt Issuance Cost. In April 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the impact of adopting this guidance to be material to the Company's financial statements and related disclosures. Amendments to Consolidation Analysis . In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Acquisitions and Divestitures

Acquisitions and Divestitures	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Transaction-related costs, which include costs associated with acquisitions and divestitures, are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 $ 423 $ 1,593 $ 3,003 $ 4,055 2015 Divestitures On April 17, 2015, MRD sold certain oil and natural gas properties to a third party in Colorado and Wyoming for approximately $13.6 million (the “Rockies Divestiture”) and recorded a loss of less than $0.1 million related to the sale. 2014 Acquisitions On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $168.1 million, including customary post-closing adjustments (the “Eagle Ford Acquisition”). On July 1, 2014, MEMP closed a transaction to acquire certain oil and natural gas liquids properties from a third party in Wyoming for approximately $906.1 million, including customary post-closing adjustments (the “Wyoming Acquisition”). The following unaudited pro forma combined results of operations are provided for the three and six months ended June 30, 2014 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 Three Months Ended For the Six Months Ended June 30, June 30, 2014 2014 MRD Consolidated and Combined (In thousands) Revenues $ 298,578 $ 550,597 Net income (loss) (1,028,123 ) (1,042,940 ) Basic and diluted earnings per share $ (5.00 ) $ (5.00 ) 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.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at June 30, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt. Assets and Liabilities Measured at Fair Value on a Recurring Basis The fair market values of the derivative financial instruments reflected on the balance sheets as of June 30, 2015 and December 31, 2014 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at June 30, 2015 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 821,489 $ — $ 821,489 Interest rate derivatives — — — — Total assets $ — $ 821,489 $ — $ 821,489 Liabilities: Commodity derivatives $ — $ 70,349 $ — $ 70,349 Interest rate derivatives — 2,911 — 2,911 Total liabilities $ — $ 73,260 $ — $ 73,260 Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 845,759 $ — $ 845,759 Interest rate derivatives — 1,305 — 1,305 Total assets $ — $ 847,064 $ — $ 847,064 Liabilities: Commodity derivatives $ — $ 71,639 $ — $ 71,639 Interest rate derivatives — 3,289 — 3,289 Total liabilities $ — $ 74,928 $ — $ 74,928 See Note 5 for additional information regarding our derivative instruments. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: · The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs. · If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. · Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. · During the six month period ended June 30, 2015, MEMP recognized $251.3 million of impairments primarily related to certain properties located in East Texas, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable due to declining commodity prices. The carrying value of these properties after the impairment was approximately $157.6 million. MEMP did not record any impairments during the three and six months ended June 30, 2014.

Risk Management and Derivative

Risk Management and Derivative Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At June 30, 2015, MEMP had net derivative assets of $485.8 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $199.7 million related to its derivative instruments of which $78.1 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $286.1 million against amounts outstanding under its revolving credit facility at June 30, 2015. At June 30, 2015, MRD had net derivative assets of $262.5 million. After taking into effect netting arrangements, MRD had counterparty exposure of $171.5 million related to derivative instruments of which $56.6 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $91.0 million against amounts outstanding under its revolving credit facility at June 30, 2015. See Note 8 for additional information regarding our revolving credit facilities. Commodity Derivatives We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and the Company agrees to defer the premium paid or received until the time of settlement. Cash settlements received on settled derivative positions during the six months ended June 30, 2015 is net of deferred premiums of $3.4 million. In February 2015, MEMP restructured a portion of its commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives. We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At June 30, 2015, the MRD Segment had the following open commodity positions: Remaining 2015 2016 2017 2018 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,400,000 2,570,000 1,770,000 4,600,000 Weighted-average fixed price $ 4.15 $ 4.09 $ 4.24 $ 4.06 Collar contracts: Average Monthly Volume (MMBtu) 130,000 1,100,000 1,050,000 — Weighted-average floor price $ 4.00 $ 4.00 $ 4.00 $ — Weighted-average ceiling price $ 4.64 $ 4.71 $ 5.06 $ — Purchased put option contracts: Average Monthly Volume (MMBtu) 4,100,000 6,000,000 5,350,000 3,450,000 Weighted-average strike price $ 3.75 $ 3.51 $ 3.48 $ 3.62 Weighted-average deferred premium paid $ (0.33 ) $ (0.34 ) $ (0.32 ) $ (0.34 ) Written call option contracts (1): Average Monthly Volume (MMBtu) 3,225,000 — — — Weighted-average sold strike price $ 3.75 $ — $ — $ — Weighted-average deferred premium received $ 0.08 $ — $ — $ — TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 3,380,000 1,120,000 200,000 — Spread - Henry Hub $ (0.10 ) $ (0.10 ) $ (0.08 ) $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 42,000 8,500 28,000 31,625 Weighted-average fixed price $ 91.67 $ 84.80 $ 84.70 $ 84.50 Collar contracts: Average Monthly Volume (Bbls) 2,000 27,000 — — Weighted-average floor price $ 85.00 $ 80.00 $ — $ — Weighted-average ceiling price $ 101.35 $ 99.70 $ — $ — Purchased put option contracts: Average Monthly Volume (Bbls) 39,000 — — — Weighted-average strike price $ 85.00 $ — $ — $ — Weighted-average deferred premium paid $ (3.80 ) $ — $ — $ — Written call option contracts (1): Average Monthly Volume (Bbls) 29,250 — — — Weighted-average sold strike price $ 85.00 $ — $ — $ — Weighted-average deferred premium received $ 0.48 $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 163,000 185,658 — — Weighted-average fixed price $ 41.52 $ 34.06 $ — $ — (1 ) These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps. At June 30, 2015, the MEMP Segment had the following open commodity positions: Remaining 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,370,903 3,592,442 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.08 $ 4.14 $ 4.06 $ 4.18 $ 4.31 Collar contracts: Average Monthly Volume (MMBtu) 350,000 — — — — Weighted-average floor price $ 4.62 $ — $ — $ — $ — Weighted-average ceiling price $ 5.80 $ — $ — $ — $ — Call spreads (1): Average Monthly Volume (MMBtu) 80,000 — — — — Weighted-average sold strike price $ 5.25 $ — $ — $ — $ — Weighted-average bought strike price $ 6.75 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (MMBtu) 3,690,000 3,578,333 2,210,000 1,315,000 900,000 Spread $ (0.12 ) $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 272,531 279,813 301,600 312,000 160,000 Weighted-average fixed price $ 91.34 $ 86.87 $ 84.70 $ 83.74 $ 85.52 Collar contracts: Average Monthly Volume (Bbls) 5,000 — — — — Weighted-average floor price $ 80.00 $ — $ — $ — $ — Weighted-average ceiling price $ 94.00 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (Bbls) 97,000 95,000 30,000 — — Spread $ (7.06 ) $ (9.56 ) $ (2.35 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 210,200 213,100 43,300 — — Weighted-average fixed price $ 42.35 $ 35.64 $ 37.55 $ — $ — (1 ) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: Remaining 2015 2016 2017 2018 2018 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 3,030,000 3,003,333 1,800,000 1,200,000 900,000 Spread - Henry Hub $ (0.11 ) $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 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) 210,000 170,000 — — — Spread - Henry Hub $ (0.25 ) $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 300,000 270,000 295,000 — — Spread - Henry Hub $ (0.09 ) $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 57,000 55,000 — — — Spread - Brent $ (9.73 ) $ (13.35 ) $ — $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 40,000 30,000 — — Spread - WTI $ (3.25 ) $ (4.34 ) $ (2.35 ) $ — $ — Interest Rate Swaps Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreements to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At June 30, 2015, we had the following interest rate swap open positions: Remaining Credit Facility 2015 2016 2017 2018 MEMP: Average Monthly Notional (in thousands) $ 391,667 $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 1.123 % 0.943 % 1.612 % 1.946 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at June 30, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives June 30, December 31, June 30, December 31, Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 323,437 $ 378,908 $ 34,066 $ 38,852 Interest rate swaps Short-term derivative instruments — — 2,312 3,289 Gross fair value 323,437 378,908 36,378 42,141 Netting arrangements Short-term derivative instruments (33,392 ) (38,852 ) (33,392 ) (38,852 ) Net recorded fair value Short-term derivative instruments $ 290,045 $ 340,056 $ 2,986 $ 3,289 Commodity contracts Long-term derivative instruments $ 498,052 $ 466,851 $ 36,283 $ 32,787 Interest rate swaps Long-term derivative instruments — 1,305 599 — Gross fair value 498,052 468,156 36,882 32,787 Netting arrangements Long-term derivative instruments (36,208 ) (32,787 ) (36,208 ) (32,787 ) Net recorded fair value Long-term derivative instruments $ 461,844 $ 435,369 $ 674 $ — (Gains) Losses on Derivatives All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the three and six months ended June 30, 2015 and 2014 (in thousands): For the Three Months Ended For the Six Months Ended Statements of June 30, June 30, Operations Location 2015 2014 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ 91,866 $ 141,590 $ (161,783 ) $ 201,072 Interest rate derivatives Interest expense, net 644 821 3,085 1,323

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations Asset retirement obligations primarily relate to our portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2015 (in thousands): Asset retirement obligations at beginning of period $ 122,531 Liabilities added from acquisitions or drilling 1,025 Liabilities settled (780 ) Revision of estimates 572 Liabilities removed upon sale of wells (176 ) Accretion expense 3,536 Asset retirement obligations at end of period $ 126,708

Restricted Investments

Restricted Investments	6 Months Ended
	Jun. 30, 2015
Schedule Of Investments [Abstract]
Restricted Investments	Note 7. Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with offshore Southern California oil and gas properties owned by MEMP. The components of the restricted investment balance consisted of the following at the dates indicated: June 30, December 31, 2015 2014 (In thousands) BOEM platform abandonment (See Note 15) $ 72,452 $ 69,954 BOEM lease bonds 794 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 2,938 2,701 California State Lands Commission pipeline right-of-way bond 3,005 3,005 City of Long Beach pipeline facility permit 500 500 Federal pipeline right-of-way bond 307 307 Port of Long Beach pipeline license 100 100 Restricted investments $ 80,096 $ 77,361

Long Term Debt

Long Term Debt	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Long Term Debt	Note 8. Long Term Debt The following table presents our consolidated debt obligations at the dates indicated: June 30, December 31, 2015 2014 (In thousands) MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 165,000 $ 183,000 5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) 600,000 600,000 Subtotal 765,000 783,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 642,000 412,000 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) 700,000 700,000 6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) 496,990 500,000 Unamortized discounts (15,340 ) (16,587 ) Subtotal 1,823,650 1,595,413 Total long-term debt $ 2,588,650 $ 2,378,413 (1) The estimated fair value of this fixed-rate debt was $574.5 million and $534.0 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (2) The estimated fair value of this fixed-rate debt was $669.4 million and $563.5 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (3) The estimated fair value of this fixed-rate debt was $454.8 million and $380.0 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. Borrowing Base Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities’ borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for each credit facility was the following at the date indicated (in thousands): June 30, 2015 MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 725,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 1,300,000 Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended For the Six Months Ended Credit Facility June 30, June 30, 2015 2014 2015 2014 MRD Segment: MRD revolving credit facility 1.70 % 2.24 % 1.80 % 2.24 % WildHorse Resources revolver terminated June 2014 n/a 4.13 % n/a 4.04 % WildHorse Resources second lien terminated June 2014 n/a 6.44 % n/a 6.44 % MEMP Segment: MEMP revolving credit facility 2.08 % 2.09 % 2.01 % 1.98 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: June 30, December 31, 2015 2014 (In thousands) MRD Segment: MRD revolving credit facility $ 4,175 $ 4,285 MRD Senior Notes 11,766 12,455 MEMP Segment: MEMP revolving credit facility 4,972 6,468 2021 Senior Notes 12,251 13,308 2022 Senior Notes 7,582 7,958 $ 40,746 $ 44,474

Stockholders' Equity and Noncon

Stockholders' Equity and Noncontrolling Interests	6 Months Ended
	Jun. 30, 2015
Equity [Abstract]
Stockholders' Equity and Noncontrolling Interests	Note 9. Stockholders’ Equity and Noncontrolling Interests Common Stock The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the six months ended June 30, 2015: Balance December 31, 2014 193,435,414 Shares of common stock repurchased (2,764,887 ) Restricted common shares issued (Note 11) 931,724 Restricted common shares repurchased (1) (60,773 ) Restricted common shares forfeited (13,750 ) Balance June 30, 2015 191,527,728 (1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Participants surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company. See Note 11 for additional information regarding restricted common shares. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award. Share Repurchase Program MRD repurchased 2,764,887 shares of common stock under the December 2014 repurchase program for an aggregate price of $47.8 million through March 16, 2015, which exhausted the December 2014 repurchase program. MRD has retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding. In April 2015, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which may be suspended or discontinued at any time. The amount, timing and price of purchases will depend on market conditions and other factors. The Company did not repurchase any shares of common stock under this program through June 30, 2015. Noncontrolling Interests Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries. Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC prior to our initial public offering. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. During the six months ended June 30, 2015, MEMP repurchased 2,951,612 common units under its repurchase program for an aggregate price of $43.9 million. MEMP has retired all common units repurchased and those common units are no longer issued or outstanding.

Earnings per Share

Earnings per Share	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Earnings per Share	Note 10. Earnings per Share The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts): For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 Numerator: Net income (loss) available to common stockholders $ (26,702 ) $ (961,707 ) $ 21,894 $ (961,707 ) Denominator: Weighted average common shares outstanding 189,628 192,500 190,163 192,500 Basic EPS $ (0.14 ) $ (5.00 ) $ 0.12 $ (5.00 ) Diluted EPS (1) $ (0.14 ) $ (5.00 ) $ 0.12 $ (5.00 ) (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. Under the treasury stock method, 364,321 and 329,312 incremental shares were included in the diluted EPS computation for the three and six months ended June 30, 2015, respectively.

Long-Term Incentive Plans

Long-Term Incentive Plans	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Long-Term Incentive Plans	Note 11. Long-Term Incentive Plans MRD The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at December 31, 2014 1,059,211 $ 19.00 Granted (2) 931,724 $ 18.80 Forfeited (13,750 ) $ 18.73 Vested (274,355 ) $ 19.00 Restricted common shares outstanding at June 30, 2015 1,702,830 $ 18.89 (1) Determined by dividing the aggregate grant date fair value of awards issued. (2) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.5 million based on a grant date market price ranging from $18.05 to $18.91 per share. The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 $ 1,957 $ 175 $ 3,443 $ 175 The unrecognized compensation cost associated with restricted common share awards was $30.9 million at June 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.91 years. MEMP The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented: Number of Units Weighted-Average Grant Date Fair Value per Unit (1) Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 Granted (2) 795,077 $ 15.04 Forfeited (19,739 ) $ 19.48 Vested (476,057 ) $ 20.36 Restricted common units outstanding at June 30, 2015 1,392,801 $ 17.78 (1) Determined by dividing the aggregate grant date fair value of awards issued. ( 2 ) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.0 million based on a grant date market price ranging from $14.94 to $15.45 per unit. The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 $ 2,565 $ 1,665 $ 4,906 $ 2,960 The unrecognized compensation cost associated with restricted common unit awards was $23.2 million at June 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.23 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to noncontrolling interests as presented on our unaudited condensed statements of consolidated and combined cash flows.

Incentive Units

Incentive Units	6 Months Ended
	Jun. 30, 2015
Compensation Related Costs [Abstract]
Incentive Units	Note 12. Incentive Units MRD Holdco MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”). We recognized $16.1 million and $26.3 million of compensation expense for the three and six months ending June 30, 2015, respectively, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $87.7 million as of June 30, 2015 will be recognized over the remaining expected service period of 1.92 years. The fair value of the Exchanged and Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by deemed capital contributions. As such, these awards are not dilutive to our stockholders. The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: Exchanged Incentive Units Subsequent Incentive Units Valuation date 6/30/2015 6/30/2015 Dividend yield 0 % 0 % Expected volatility 46.42 % 46.42 % Risk-free rate 0.61 % 0.61 % Expected life (years) 1.92 1.92

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 13. Related Party Transactions Amounts due to (due from) MRD Holdco and certain affiliates of NGP at June 30, 2015 and December 31, 2014 are presented as “Accounts receivable – – NGP Affiliated Companies During the three and six months ended June 30, 2015, MRD paid approximately $0.6 million and $1.1 million, respectively to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. NGPCIF NPI Acquisition WildHorse Resources purchased a net profits interest from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands): Accounts receivable $ 2,274 Oil and natural gas properties, net 40,056 Accrued liabilities (297 ) Asset retirement obligations (277 ) Net assets $ 41,756 Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates. Other Acquisitions or Dispositions On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution. On March 28, 2014, our predecessor acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from a NGP affiliated company for $3.3 million. On June 18, 2014, in connection with our initial public offering and the related restructuring transactions, 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. Services Agreement In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WildHorse Resource Management Company, LLC (“WHR Management Company”), pursuant to which WHR Management Company agreed to provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we paid a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits. Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company (“WHR II”). NGP and certain former management members of WildHorse Resources own WHR II. The services agreement was terminated effective March 1, 2015. WildHorse Management Services Agreement A discussion of the WildHorse and WHR II management services and related agreements is included in our Recast Form 8-K. These agreements were terminated in connection with our initial public offering. Midstream Agreements On April 14, 2015, we, through our wholly-owned subsidiary, MRD Operating, entered into an amended and restated gas processing agreement (“GPA”) with PennTex North Louisiana Operating, LLC (“PennTex Operating”), a wholly-owned subsidiary of PennTex North Louisiana, LLC (“PennTex”). WildHorse Resources, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015, initially entered into a gas processing agreement with PennTex in March 2014, prior to our initial public offering. PennTex is a joint venture among certain affiliates of NGP in which MRD Midstream LLC, a wholly-owned subsidiary of MRD Holdco, owns a minority interest. Once PennTex Operating’s first processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The GPA has a 15-year primary term, subject to one-year extensions at either party’s election. We will pay PennTex Operating a monthly volume processing fee, subject to annual inflation escalators, based on volumes of natural gas processed by PennTex Operating. Once the first plant is declared operational, we will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions until the second processing plant is declared operational. Once the second plant is declared operational, we will be obligated to pay a minimum volume processing fee equal to approximately $55.0 million on an annual basis, subject to certain adjustments and conditions. In addition, on April 14, 2015, we entered into (i) an amended and restated area of mutual interest and midstream exclusivity agreement (“AMI”) with PennTex NLA Holdings, LLC, which owns a majority interest in PennTex, MRD WHR LA Midstream LLC, an affiliate of MRD Holdco, and PennTex, (ii) a gas transportation agreement (“GTA”) with PennTex Operating, (iii) a gas gathering agreement (“GGA”) with PennTex Operating, and (iv) a transportation services agreement (“TSA” and, together with the GPA, AMI, GTA, and GGA, the “Midstream Agreements”) with PennTex Operating to provide gathering, residue gas and natural gas liquids transportation services to us in the state of Louisiana. The Midstream Agreements have a 15-year primary term, subject to one-year extensions at either party’s elections. Under the GGA, once the first processing plant is declared operational, we will pay PennTex Operating a commodity usage charge equal to at least the minimum volume commitment (115,000 MMBtu per day) times $0.02 per MMBtu until PennTex Operating’s second processing plant is declared operational. Once the second processing plant is declared operational, we will pay PennTex Operating a commodity usage charge equal to at least an increased minimum volume commitment (345,000 MMBtu per day) times $0.02 MMBtu through November 30, 2019. The minimum volume commitment will increase to 460,000 MMBtu on July 1, 2016 and may further increase subject to the terms of the GGA. Prior to December 1, 2019, PennTex Operating is also entitled to a payback demand fee from us equal to the monthly demand quantity (460,000 MMBtu per day) times a $0.03 MMBtu through November 30, 2019. Beginning on December 1, 2019, PennTex Operating is not entitled to a monthly demand charge, the commodity usage charge escalates to $0.05 per MMBtu, and PennTex Operating is entitled to receive a commodity usage charge from us equal to the minimum volume commitment (460,000 MMBtu per day through June 30, 2026, and 345,000 MMBtu per day thereafter) times $0.05 MMBtu. Similarly, under the GTA which commences concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per MMBtu for all volumes of residue gas produced on our behalf. Under the TSA, which commences concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per gallon for all volumes of natural gas liquids produced on our behalf. Under the AMI, we granted PennTex Operating the exclusive right to build all of our midstream infrastructure in northern Louisiana and to provide midstream services to support our current and future production on our operated acreage within such area (other than production subject to existing third-party commitments). All net costs associated with these gas processing agreements are reflected in the statement of operations in the “Gathering processing, and transportation – affiliate” line. Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement In November 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. In February 2015, in connection with and as part of the Property Swap, Classic sold all of the equity interests owned by it in Classic Operating to Memorial Production Operating LLC, a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015.

Business Segment Data

Business Segment Data	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Business Segment Data	MEMORIAL RESOURCE DEVELOPMENT CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS Note 14. Business Segment Data Our reportable business segments are organized in a manner that reflects how management manages those business activities. We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties. Our reportable business segments are as follows: · MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries. · MEMP—reflects the combined operations of MEMP and its subsidiaries. We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of goodwill and long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); transaction related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid on expired positions; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items. Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available. Segment revenues and expenses include intersegment transactions. Our consolidated 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: Three Months Ended June 30, 2015 $ 78,605 $ 98,138 $ — $ 176,743 Three Months Ended June 30, 2014 110,569 144,208 — 254,777 Six Months Ended June 30, 2015 165,628 190,956 — 356,584 Six Months Ended June 30, 2014 198,305 261,093 — 459,398 Adjusted EBITDA: (1) Three Months Ended June 30, 2015 82,831 82,875 (75 ) 165,631 Three Months Ended June 30, 2014 81,471 84,475 (3,002 ) 162,944 Six Months Ended June 30, 2015 169,661 169,307 (151 ) 338,817 Six Months Ended June 30, 2014 146,223 146,521 (6,004 ) 286,740 Segment assets: (2) As of June 30, 2015 1,553,851 2,934,433 (7,981 ) 4,480,303 As of December 31, 2014 1,413,768 3,189,760 (9,981 ) 4,593,547 Total cash expenditures for additions to long-lived assets: Six Months Ended June 30, 2015 210,390 134,501 — 344,891 Six Months Ended June 30, 2014 156,630 311,205 — 467,835 (1) Adjustments and eliminations for the three and six months ended June 30, 2015 and 2014 include cash distributions that MEMP paid to MRD during the three and six months ended June 30, 2015 and 2014, related to the ownership of partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014. (2) As of June 30, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment. Calculation of Reportable Segments’ Adjusted EBITDA For the Three Months Ended June 30, 2015 Combined MRD MEMP Totals (In thousands) Net income (loss) $ (26,703 ) $ (113,859 ) $ (140,562 ) Interest expense, net 9,613 27,910 37,523 Income tax expense (benefit) (24,644 ) 876 (23,768 ) DD&A 35,827 46,286 82,113 Accretion of AROs 93 1,686 1,779 (Gain) loss on commodity derivative instruments 30,463 61,403 91,866 Cash settlements received (paid) on expired commodity derivative instruments 37,539 54,351 91,890 Transaction related costs 126 297 423 Incentive-based compensation expense 18,073 2,565 20,638 Exploration costs 2,230 32 2,262 Gain (loss) on sale of properties 50 — 50 Loss on settlement of AROs — 1,328 1,328 Non-cash equity (income) loss from MEMP 89 — 89 Cash distributions from MEMP 75 — 75 Adjusted EBITDA $ 82,831 $ 82,875 $ 165,706 For the Three Months Ended June 30, 2014 Combined MRD MEMP Totals (In thousands) Net income (loss) $ (951,747 ) $ (111,640 ) $ (1,063,387 ) Interest expense, net 16,494 18,037 34,531 Loss on debt extinguishment 37,248 — 37,248 Income tax expense (benefit) (11,846 ) 310 (11,536 ) DD&A 30,814 42,966 73,780 Accretion of AROs 127 1,400 1,527 (Gain) loss on commodity derivative instruments 3,244 138,346 141,590 Cash settlements received (paid) on expired commodity derivative instruments (3,408 ) (7,906 ) (11,314 ) (Gain) loss on sale of properties 3,167 — 3,167 Transaction related costs 500 1,093 1,593 Incentive-based compensation expense 942,992 1,665 944,657 Exploration costs 940 204 1,144 Non-cash equity (income) loss from MEMP 9,944 — 9,944 Cash distributions from MEMP 3,002 — 3,002 Adjusted EBITDA $ 81,471 $ 84,475 $ 165,946 For the Six Months Ended June 30, 2015 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 23,668 $ (276,517 ) $ (252,849 ) Interest expense, net 19,369 56,728 76,097 Income tax expense (benefit) 22,914 (1,494 ) 21,420 DD&A 76,359 97,552 173,911 Impairment of proved oil and natural gas properties — 251,347 251,347 Accretion of AROs 216 3,320 3,536 (Gain) loss on commodity derivative instruments (77,727 ) (84,056 ) (161,783 ) Cash settlements received (paid) on expired commodity derivative instruments 70,288 114,475 184,763 (Gain) loss on sale of properties 50 — 50 Transaction related costs 1,407 1,596 3,003 Incentive-based compensation expense 29,783 4,906 34,689 Exploration costs 2,956 122 3,078 Loss on settlement of AROs — 1,328 1,328 Non-cash equity (income) loss from MEMP 227 — 227 Cash distributions from MEMP 151 — 151 Adjusted EBITDA $ 169,661 $ 169,307 $ 338,968 For the Six Months Ended June 30, 2014 Combined MRD MEMP Totals (In thousands) Net income (loss) $ (945,357 ) $ (144,532 ) $ (1,089,889 ) Interest expense, net 34,468 34,115 68,583 Loss on debt extinguishment 37,248 — 37,248 Income tax expense (benefit) (11,821 ) 385 (11,436 ) DD&A 55,943 75,516 131,459 Accretion of AROs 257 2,791 3,048 (Gain) loss on commodity derivative instruments 15,960 185,112 201,072 Cash settlements received (paid) on expired commodity derivative instruments (8,629 ) (15,875 ) (24,504 ) (Gain) loss on sale of properties 3,057 — 3,057 Transaction related costs 1,068 2,987 4,055 Incentive-based compensation expense 944,015 2,960 946,975 Exploration costs 1,080 210 1,290 Non-cash equity (income) loss from MEMP 12,930 — 12,930 Provision for environmental remediation — 2,852 2,852 Cash distributions from MEMP 6,004 — 6,004 Adjusted EBITDA $ 146,223 $ 146,521 $ 292,744 The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands). For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 Total Reportable Segments' Adjusted EBITDA $ 165,706 $ 165,946 $ 338,968 $ 292,744 Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net (37,523 ) (34,531 ) (76,097 ) (68,583 ) Loss on debt extinguishment — (37,248 ) — (37,248 ) Income tax benefit (expense) 23,768 11,536 (21,420 ) 11,436 DD&A (82,113 ) (73,780 ) (173,911 ) (131,459 ) Impairment of proved oil and natural gas properties — — (251,347 ) — Accretion of AROs (1,779 ) (1,527 ) (3,536 ) (3,048 ) Gains (losses) on commodity derivative instruments (91,866 ) (141,590 ) 161,783 (201,072 ) Cash settlements paid (received) on expired commodity derivative instruments (91,890 ) 11,314 (184,763 ) 24,504 Gain (loss) on sale of properties (50 ) (3,167 ) (50 ) (3,057 ) Transaction related costs (423 ) (1,593 ) (3,003 ) (4,055 ) Incentive-based compensation expense (20,638 ) (944,657 ) (34,689 ) (946,975 ) Exploration costs (2,262 ) (1,144 ) (3,078 ) (1,290 ) Provision for environmental remediation — — — (2,852 ) Loss on settlement of AROs (1,328 ) — (1,328 ) — Cash distributions from MEMP (75 ) (3,002 ) (151 ) (6,004 ) Net income (loss) $ (140,473 ) $ (1,053,443 ) $ (252,622 ) $ (1,076,959 ) Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): Three Months Ended June 30, 2015 MRD MEMP Other, Adjustments & Eliminations Consolidated Revenues: Oil & natural gas sales $ 78,605 $ 97,221 $ — $ 175,826 Other revenues — 917 — 917 Total revenues 78,605 98,138 — 176,743 Costs and expenses: Lease operating 3,854 44,888 — 48,742 Gathering, processing, and transportation 14,289 9,048 — 23,337 Gathering, processing, and transportation - affiliate 3,813 — — 3,813 Pipeline operating — 500 — 500 Exploration 2,230 32 — 2,262 Production and ad valorem taxes 3,140 6,058 — 9,198 Depreciation, depletion, and amortization 35,827 46,286 — 82,113 Incentive unit compensation expense 16,116 — — 16,116 General and administrative 10,323 14,377 — 24,700 Accretion of asset retirement obligations 93 1,686 — 1,779 (Gain) loss on commodity derivative instruments 30,463 61,403 — 91,866 (Gain) loss on sale of properties 50 — — 50 Other, net — (943 ) (943 ) Total costs and expenses 120,198 183,335 — 303,533 Operating income (loss) (41,593 ) (85,197 ) — (126,790 ) Other income (expense): Interest expense, net (9,613 ) (27,910 ) — (37,523 ) Earnings from equity investments (89 ) — 89 — Other, net (52 ) 124 — 72 Total other income (expense) (9,754 ) (27,786 ) 89 (37,451 ) Income (loss) before income taxes (51,347 ) (112,983 ) 89 (164,241 ) Income tax benefit (expense) 24,644 (876 ) — 23,768 Net income (loss) $ (26,703 ) $ (113,859 ) $ 89 $ (140,473 ) Three Months Ended June 30, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated Revenues: Oil & natural gas sales $ 110,566 $ 142,870 $ — $ 253,436 Other revenues 3 1,338 — 1,341 Total revenues 110,569 144,208 — 254,777 Costs and expenses: Lease operating 4,793 27,528 — 32,321 Gathering, processing, and transportation 10,295 7,591 — 17,886 Pipeline operating — 676 — 676 Exploration 940 204 — 1,144 Production and ad valorem taxes 3,581 7,418 — 10,999 Depreciation, depletion, and amortization 30,814 42,966 — 73,780 Incentive unit compensation expense 942,817 — — 942,817 General and administrative 10,754 11,372 — 22,126 Accretion of asset retirement obligations 127 1,400 — 1,527 (Gain) loss on commodity derivative instruments 3,244 138,346 — 141,590 (Gain) loss on sale of properties 3,167 — — 3,167 Total costs and expenses 1,010,532 237,501 — 1,248,033 Operating income (loss) (899,963 ) (93,293 ) — (993,256 ) Other income (expense): Interest expense, net (16,494 ) (18,037 ) — (34,531 ) Loss on extinguishment of debt (37,248 ) — — (37,248 ) Earnings from equity investments (9,944 ) — 9,944 — Other, net 56 — — 56 Total other income (expense) (63,630 ) (18,037 ) 9,944 (71,723 ) Income (loss) before income taxes (963,593 ) (111,330 ) 9,944 (1,064,979 ) Income tax benefit (expense) 11,846 (310 ) — 11,536 Net income (loss) $ (951,747 ) $ (111,640 ) $ 9,944 $ (1,053,443 ) Six Months Ended June 30, 2015 MRD MEMP Other, Adjustments & Eliminations Consolidated Revenues: Oil & natural gas sales $ 165,628 $ 189,170 $ — $ 354,798 Other revenues — 1,786 — 1,786 Total revenues 165,628 190,956 — 356,584 Costs and expenses: Lease operating 9,076 85,366 — 94,442 Gathering, processing, and transportation 29,052 17,268 — 46,320 Gathering, processing, and transportation - affiliate 3,813 — — 3,813 Pipeline operating — 946 — 946 Exploration 2,956 122 — 3,078 Production and ad valorem taxes 5,915 12,713 — 18,628 Depreciation, depletion, and amortization 76,359 97,552 — 173,911 Impairment of proved oil and natural gas properties — 251,347 — 251,347 Incentive unit compensation expense 26,340 — — 26,340 General and administrative 23,299 28,888 — 52,187 Accretion of asset retirement obligations 216 3,320 — 3,536 (Gain) loss on commodity derivative instruments (77,727 ) (84,056 ) — (161,783 ) (Gain) loss on sale of properties 50 — — 50 Other, net — (943 ) — (943 ) Total costs and expenses 99,349 412,523 — 511,872 Operating income (loss) 66,279 (221,567 ) — (155,288 ) Other income (expense): Interest expense, net (19,369 ) (56,728 ) — (76,097 ) Earnings from equity investments (227 ) — 227 — Other, net (101 ) 284 — 183 Total other income (expense) (19,697 ) (56,444 ) 227 (75,914 ) Income (loss) before income taxes 46,582 (278,011 ) 227 (231,202 ) Income tax benefit (expense) (22,914 ) 1,494 — (21,420 ) Net income (loss) $ 23,668 $ (276,517 ) $ 227 $ (252,622 ) Six Months Ended June 30, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Revenues: Oil & natural gas sales $ 198,299 $ 258,847 $ — $ 457,146 Other revenues 6 2,246 — 2,252 Total revenues 198,305 261,093 — 459,398 Costs and expenses: Lease operating 8,028 57,648 — 65,676 Gathering, processing, and transportation 18,852 13,154 — 32,006 Pipeline operating — 1,165 — 1,165 Exploration 1,080 210 — 1,290 Production and ad valorem taxes 6,154 13,429 — 19,583 Depreciation, depletion, and amortization 55,943 75,516 — 131,459 Incentive unit compensation expense 943,840 — — 943,840 General and administrative 17,753 22,112 — 39,865 Accretion of asset retirement obligations 257 2,791 — 3,048 (Gain) loss on commodity derivative instruments 15,960 185,112 — 201,072 (Gain) loss on sale of properties 3,057 — — 3,057 Other, net — (12 ) — (12 ) Total costs and expenses 1,070,924 371,125 — 1,442,049 Operating income (loss) (872,619 ) (110,032 ) — (982,651 ) Other income (expense): Interest expense, net (34,468 ) (34,115 ) — (68,583 ) Loss on extinguishment on debt (37,248 ) — — (37,248 ) Earnings from equity investments (12,930 ) — 12,930 — Other, net 87 — — 87 Total other income (expense) (84,559 ) (34,115 ) 12,930 (105,744 ) Income before income taxes (957,178 ) (144,147 ) 12,930 (1,088,395 ) Income tax benefit (expense) 11,821 (385 ) — 11,436 Net income (loss) $ (945,357 ) $ (144,532 ) $ 12,930 $ (1,076,959 )

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 15. Commitments and Contingencies Litigation & Environmental As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. At June 30, 2015 and December 31, 2014, we had $1.1 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively. Midstream Agreements See Note 13 for additional information. Supplemental Bond for Decommissioning Liabilities Trust Agreement In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities. The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of June 30, 2015 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 140,003 Less: Outside working interest owners share (67,551 ) $ 72,452 The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): June 30, 2016 $ 76,590 December 31, 2016 $ 78,660 As of June 30, 2015, the maximum remaining obligation net to REO’s interest was approximately $6.2 million. Processing Plant Expansions by Third Party Gatherer A discussion of processing plant expansions by a third party gatherer is included in our Recast Form 8-K. Related Party Agreements See Note 13 for additional information.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	6 Months Ended
	Jun. 30, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Condensed Consolidating Financial Information	Note 16. Condensed Consolidating Financial Information The Company owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under the MRD Senior Notes outstanding are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests (i.e. MEMP) and certain de minimis subsidiaries are non-guarantors. The following condensed consolidating financial information presents the financial information of the Company on a unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities. As of June 30, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 1,485 $ 3,053 $ 163 $ — $ 4,701 Accounts receivable - trade 4,776 48,370 62,311 (6,118 ) 109,339 Accounts receivable - affiliates 8,783 — 1,069 (9,852 ) — Short-term derivative instruments 117,401 — 172,644 — 290,045 Prepaid expenses and other current assets 4,670 10,322 14,890 — 29,882 Total current assets 137,115 61,745 251,077 (15,970 ) 433,967 Property and equipment, net 17,433 1,187,230 2,265,256 — 3,469,919 Long-term derivative instruments 145,086 — 316,758 — 461,844 Investments in subsidiaries 1,025,875 — — (1,025,875 ) — Other long-term assets 13,211 — 101,362 — 114,573 Total assets $ 1,338,720 $ 1,248,975 $ 2,934,453 $ (1,041,845 ) $ 4,480,303 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 19,413 $ 143,658 $ 112,259 $ (697 ) $ 274,633 Accounts payable - affiliates 20 19,257 618 (14,711 ) 5,184 Revenues payable 142 35,080 31,718 — 66,940 Short-term derivative instruments 6 — 2,980 — 2,986 Total current liabilities 19,581 197,995 147,575 (15,408 ) 349,743 Long-term debt 765,000 — 1,823,650 — 2,588,650 Asset retirement obligations — 7,743 118,965 — 126,708 Long-term derivative instruments 5 — 669 — 674 Deferred tax liabilities 60,660 17,656 2,359 — 80,675 Other long-term liabilities 7,394 — — — 7,394 Total liabilities 852,640 223,394 2,093,218 (15,408 ) 3,153,844 Equity: — Equity 486,080 1,025,581 835,451 (1,861,032 ) 486,080 Noncontrolling interest — — 5,784 834,595 840,379 Total equity 486,080 1,025,581 841,235 (1,026,437 ) 1,326,459 Total liabilities & equity $ 1,338,720 $ 1,248,975 $ 2,934,453 $ (1,041,845 ) $ 4,480,303 As of December 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,241 $ 3,762 $ 970 $ (1,015 ) $ 5,958 Accounts receivable- trade 5,995 44,952 83,346 (2,717 ) 131,576 Accounts receivable - affiliates 10,047 — 28 (10,075 ) — Short-term derivative instruments 131,471 — 208,585 — 340,056 Prepaid expenses and other current assets 5,833 7,993 14,201 — 28,027 Total current assets 155,587 56,707 307,130 (13,807 ) 505,617 Property and equipment, net 16,601 1,050,722 2,470,333 — 3,537,656 Long-term derivative instruments 123,567 — 311,802 — 435,369 Investments in subsidiaries 1,139,792 — — (1,139,792 ) — Other long-term assets 14,124 5,660 100,521 (5,400 ) 114,905 Total assets $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued expenses $ 6,245 $ 107,068 $ 114,584 $ (3,125 ) $ 224,772 Accounts payable - affiliates — 3,638 6,409 (9,423 ) 624 Revenues payable — 27,242 30,110 — 57,352 Short-term derivative instruments — — 3,289 — 3,289 Total current liabilities 6,245 137,948 154,392 (12,548 ) 286,037 Long-term debt 783,000 1,595,413 — 2,378,413 Asset retirement obligations — 9,830 112,701 — 122,531 Deferred tax liabilities 69,431 — 30,986 (5,400 ) 95,017 Other long-term liabilities 8,585 — — — 8,585 Total liabilities 867,261 147,778 1,893,492 (17,948 ) 2,890,583 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interest — — 5,560 1,114,994 1,120,554 Total equity 582,410 965,311 1,296,294 (1,141,051 ) 1,702,964 Total liabilities & equity $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 Three Months Ended June 30, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 78,605 $ 97,221 $ — $ 175,826 Other income — — 917 — 917 Total revenues — 78,605 98,138 — 176,743 Costs and expenses: Lease operating — 3,854 44,888 — 48,742 Gathering, processing and transportation — 14,289 9,048 — 23,337 Gathering, processing and transportation - affiliate — 3,813 — — 3,813 Pipeline operating — — 500 — 500 Exploration — 2,230 32 — 2,262 Production and ad valorem taxes — 3,140 6,058 — 9,198 Depreciation, depletion and amortization 1,084 34,743 46,286 — 82,113 Incentive unit compensation expense 16,116 — — — 16,116 General and administrative 10,404 (81 ) 14,377 — 24,700 Accretion of asset retirement obligations — 93 1,686 — 1,779 (Gain) loss on commodity derivatives 30,463 — 61,403 — 91,866 (Gain) loss on sale of properties — 50 — — 50 Other, net — — (943 ) — (943 ) Total costs and expenses 58,067 62,131 183,335 — 303,533 Operating income (loss) (58,067 ) 16,474 (85,197 ) — (126,790 ) Other income (expense): Interest expense, net (9,526 ) (87 ) (27,910 ) — (37,523 ) Equity earnings from subsidiaries 7,469 — — (7,469 ) — Other, net — (52 ) 124 — 72 Total other income (expense) (2,057 ) (139 ) (27,786 ) (7,469 ) (37,451 ) Income before income taxes (60,124 ) 16,335 (112,983 ) (7,469 ) (164,241 ) Income tax benefit (expense) 33,422 (8,778 ) (876 ) — 23,768 Net income (loss) (26,702 ) 7,557 (113,859 ) (7,469 ) (140,473 ) Net income (loss) attributable to noncontrolling interest — — 65 (113,836 ) (113,771 ) Net income (loss) attributable to Memorial Resource Development Corp. $ (26,702 ) $ 7,557 $ (113,924 ) $ 106,367 $ (26,702 ) Three Months Ended June 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 110,566 $ 142,870 $ — $ 253,436 Other income — 3 1,338 — 1,341 Total revenues — 110,569 144,208 — 254,777 Costs and expenses: Lease operating — 4,793 27,528 — 32,321 Gathering, processing and transportation — 10,295 7,591 — 17,886 Pipeline operating — — 676 — 676 Exploration — 940 204 — 1,144 Production and ad valorem taxes — 3,581 7,418 — 10,999 Depreciation, depletion and amortization — 30,814 42,966 — 73,780 Incentive unit compensation expense 111,757 831,060 — — 942,817 General and administrative 175 10,579 11,372 — 22,126 Accretion of asset retirement obligations — 127 1,400 — 1,527 (Gain) loss on commodity derivatives (3,435 ) 6,679 138,346 — 141,590 (Gain) loss on sale of properties — 3,167 — — 3,167 Total costs and expenses 108,497 902,035 237,501 — 1,248,033 Operating income (loss) (108,497 ) (791,466 ) (93,293 ) — (993,256 ) Other income (expense): Interest expense, net (976 ) (15,518 ) (18,037 ) — (34,531 ) Debt extinguishment costs (23,562 ) (13,686 ) — — (37,248 ) Equity earnings from subsidiaries (836,746 ) 3,260 — 833,486 — Other, net — 56 — — 56 Total other income (expense) (861,284 ) (25,888 ) (18,037 ) 833,486 (71,723 ) Income before income taxes (969,781 ) (817,354 ) (111,330 ) 833,486 (1,064,979 ) Income tax benefit (expense) 8,074 3,772 (310 ) — 11,536 Net income (loss) (961,707 ) (813,582 ) (111,640 ) 833,486 (1,053,443 ) Net income (loss) attributable to noncontrolling interest — — (12 ) (105,082 ) (105,094 ) Net income (loss) attributable to Memorial Resource Development Corp. $ (961,707 ) $ (813,582 ) $ (111,628 ) $ 938,568 $ (948,349 ) Six Months Ended June 30, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 165,628 $ 189,170 $ — $ 354,798 Other income — — 1,786 — 1,786 Total revenues — 165,628 190,956 — 356,584 Costs and expenses: Lease operating — 9,076 85,366 — 94,442 Gathering, processing and transportation — 29,052 17,268 — 46,320 Gathering, processing and transportation -affiliate — 3,813 — — 3,813 Pipeline operating — — 946 — 946 Exploration — 2,956 122 — 3,078 Production and ad valorem taxes — 5,915 12,713 — 18,628 Depreciation, depletion and amortization 2,052 74,307 97,552 — 173,911 Impairment of proved oil and natural gas properties — — 251,347 — 251,347 Incentive unit compensation expense 26,340 — — — 26,340 General and administrative 21,329 1,970 28,888 — 52,187 Accretion of asset retirement obligations — 216 3,320 — 3,536 (Gain) loss on commodity derivatives (77,727 ) — (84,056 ) — (161,783 ) (Gain) loss on sale of properties — 50 — — 50 Other, net — — (943 ) — (943 ) Total costs and expenses (28,006 ) 127,355 412,523 — 511,872 Operating income (loss) 28,006 38,273 (221,567 ) — (155,288 ) Other income (expense): Interest expense, net (19,282 ) (87 ) (56,728 ) — (76,097 ) Equity earnings from subsidiaries 17,343 — — (17,343 ) — Other, net — (101 ) 284 — 183 Total other income (expense) (1,939 ) (188 ) (56,444 ) (17,343 ) (75,914 ) Income before income taxes 26,067 38,085 (278,011 ) (17,343 ) (231,202 ) Income tax benefit (expense) (4,023 ) (18,891 ) 1,494 — (21,420 ) Net income (loss) 22,044 19,194 (276,517 ) (17,343 ) (252,622 ) Net income (loss) attributable to noncontrolling interest — — 224 (274,890 ) (274,666 ) Net income (loss) attributable to Memorial Resource Development Corp. $ 22,044 $ 19,194 $ (276,741 ) $ 257,547 $ 22,044 Six Months Ended June 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 198,299 $ 258,847 $ — $ 457,146 Other income — 6 2,246 — 2,252 Total revenues — 198,305 261,093 — 459,398 Costs and expenses: Lease operating — 8,028 57,648 — 65,676 Gathering, processing and transportation — 18,852 13,154 — 32,006 Pipeline operating — — 1,165 — 1,165 Exploration — 1,080 210 — 1,290 Production and ad valorem taxes — 6,154 13,429 — 19,583 Depreciation, depletion and amortization — 55,943 75,516 — 131,459 Incentive unit compensation expense 111,757 831,060 1,023 — 943,840 General and administrative 175 17,561 22,129 — 39,865 Accretion of asset retirement obligations — 257 2,791 — 3,048 (Gain) loss on commodity derivatives (3,435 ) 19,395 185,112 — 201,072 (Gain) loss on sale of properties — 3,167 (110 ) — 3,057 Other, net — — (12 ) — (12 ) Total costs and expenses 108,497 961,497 372,055 — 1,442,049 Operating income (loss) (108,497 ) (763,192 ) (110,962 ) — (982,651 ) Other income (expense): Interest expense, net (976 ) (33,492 ) (34,115 ) — (68,583 ) Debt extinguishment costs (23,562 ) (13,686 ) — — (37,248 ) Equity earnings from subsidiaries (836,746 ) — — 836,746 — Other, net — 87 — — 87 Total other income (expense) (861,284 ) (47,091 ) (34,115 ) 836,746 (105,744 ) Income before income taxes (969,781 ) (810,283 ) (145,077 ) 836,746 (1,088,395 ) Income tax benefit (expense) 8,074 3,747 (385 ) — 11,436 Net income (loss) (961,707 ) (806,536 ) (145,462 ) 836,746 (1,076,959 ) Net income (loss) attributable to noncontrolling interest — — 43 (137,025 ) (136,982 ) Net income (loss) attributable to Memorial Resource Development Corp. (961,707 ) (806,536 ) (145,505 ) 973,771 (939,977 ) Six Months Ended June 30, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by (used in) operating activities $ 37,045 $ 152,009 $ 111,718 $ 1,015 $ 301,787 Cash flows from investing activities: Acquisitions of oil and natural gas properties — — (6,095 ) — (6,095 ) Acquisition post-closing adjustment receipts — — 9,570 — 9,570 Additions to oil and gas properties — (207,103 ) (128,323 ) — (335,426 ) Additions to other property and equipment (2,871 ) (416 ) (83 ) — (3,370 ) Additions to restricted investments — — (2,735 ) — (2,735 ) Investments in subsidiaries (44,280 ) — — 44,280 — Distributions from subsidiaries 78,547 — — (78,547 ) — Proceeds from the sale of oil and gas properties — 13,612 — — 13,612 Net cash used in investing activities 31,396 (193,907 ) (127,666 ) (34,267 ) (324,444 ) Cash flows from financing activities: Advances on revolving credit facility 181,000 — 252,000 — 433,000 Payments on revolving credit facility (199,000 ) — (22,000 ) — (221,000 ) Repayment of senior notes — — (2,914 ) — (2,914 ) Deferred finance costs — — (235 ) — (235 ) Capital contributions — 41,189 3,091 (44,280 ) — Distributions to MRD — — (78,396 ) 78,396 — Distribution to partners — — (92,628 ) 92,628 — Distribution to noncontrolling interests — — — (92,477 ) (92,477 ) Repurchases of equity (51,197 ) — (43,777 ) — (94,974 ) Net cash provided by financing activities (69,197 ) 41,189 15,141 34,267 21,400 Net change in cash and cash equivalents (756 ) (709 ) (807 ) 1,015 (1,257 ) Cash and cash equivalents, beginning of period 2,241 3,762 970 (1,015 ) 5,958 Cash and cash equivalents, end of period $ 1,485 $ 3,053 $ 163 $ — $ 4,701 Six Months Ended June 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) operating activities $ (5,169 ) $ 73,471 $ 109,445 $ — $ 177,747 Cash flows from investing activities: Acquisitions of oil and natural gas properties — — (173,000 ) — (173,000 ) Additions to oil and gas properties — (155,362 ) (138,205 ) — (293,567 ) Additions to other property and equipment (263 ) (1,005 ) — — (1,268 ) Additions to restricted investments — — (2,121 ) — (2,121 ) Investments in subsidiaries (616,353 ) (3,304 ) — 619,657 — Distributions from subsidiaries — 48,596 — (48,596 ) — Change in restricted cash — 49,946 — — 49,946 Deposits for property acquisitions — — (70,125 ) — (70,125 ) Proceeds from the sale of oil and gas properties — — 6,700 — 6,700 Other — — (301 ) — (301 ) Net cash used in investing activities (616,616 ) (61,129 ) (377,052 ) 571,061 (483,736 ) Cash flows from financing activities: Advances on revolving credit facility 1,004,000 126,800 418,000 — 1,548,800 Payments on revolving credit facility (385,000 ) (329,900 ) (62,000 ) — (776,900 ) Termination of second lien credit facility — (328,282 ) — — (328,282 ) Redemption of senior notes (351,808 ) — — — (351,808 ) Deferred finance costs (4,679 ) (965 ) (590 ) — (6,234 ) Proceeds from MRD initial public offering 408,500 — — — 408,500 Costs incurred in conjunction with initial public offering (26,875 ) — — — (26,875 ) Capital contributions — 614,350 5,307 (619,657 ) — Contributions from NGP affiliates related to sale of properties — — 1,165 — 1,165 Purchase of additional interests in subsidiaries (3,292 ) — — — (3,292 ) Distribution to equity owners — — (110,440 ) 110,440 — Distribution to NGP affiliates related to purchase of assets — (63,389 ) (3,304 ) — (66,693 ) Distribution to noncontrolling interests — — — (61,844 ) (61,844 ) Distributions to MRD Holdco (17,207 ) (39,520 ) (3,076 ) — (59,803 ) Distribution to NGP affiliates related to sale of assets, net of cash received — (32,770 ) — — (32,770 ) Other — 270 — — 270 Net cash provided by financing activities 623,639 (53,406 ) 245,062 (571,061 ) 244,234 Net change in cash and cash equivalents 1,854 (41,064 ) (22,545 ) — (61,755 ) Cash and cash equivalents, beginning of period — 48,619 29,102 — 77,721 Cash and cash equivalents, end of period $ 1,854 $ 7,555 $ 6,557 $ — $ 15,966

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Overview	Overview Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds.
Previous Owners	Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to the net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of certain acquisitions in 2010, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. Our unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI.
Basis of Presentation	Basis of Presentation The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: · MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries. · MEMP—reflects the combined operations of MEMP and its subsidiaries. Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction.
Use of Estimates	Use of Estimates The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations, income taxes and asset retirement obligations.
Accrued Liabilities	Accrued liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): June 30, December 31, 2015 2014 Accrued capital expenditures $ 107,344 $ 80,350 Accrued lease operating expense 23,524 16,403 Accrued general and administrative expenses 13,324 8,516 Accrued ad valorem taxes 11,442 8,870 Accrued interest payable 27,118 24,797 Accrued environmental 1,147 2,092 Accrued current and deferred income taxes 58,597 51,929 Other miscellaneous, including operator advances 6,770 6,043 $ 249,266 $ 199,000
Supplemental Cash Flow Information	Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2015 June 30, 2014 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 85,019 $ 65,641 Cash paid for taxes 2,055 550 Noncash investing and financing activities: (Increase) decrease in capital expenditures in payables and accrued liabilities (26,994 ) (3,526 ) (Increase) decrease in accounts receivable related to acquisitions and divestitures 9,570 (4,732 ) Repurchases under MEMP repurchase program 2,710 —
Income Tax	Income Tax MRD is a corporation subject to federal and certain state income taxes. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes. As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. MRD’s predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes. MRD reported no liability for unrecognized tax benefits as of June 30, 2015 and expects no significant change to the unrecognized tax benefits in the next twelve months. MRD’s effective tax rate for the three and six months ended June 30, 2015 was 14.5% and negative 9.3%, respectively, and the effective tax rate for both the three and six months ended June 30, 2014 was 1.1%. The effective tax rate for the three and six months ended June 30, 2014 and 2015 differs from the statutory federal income tax rate primarily due to the following recurring items: · earnings from the MEMP Segment pass-through entities; · non-deductible incentive unit compensation; and · state income tax, net of federal benefit. MRD had a net noncurrent deferred income tax liability of $95.0 million at December 31, 2014, of which $29.2 million was attributable to certain oil and gas properties in East Texas that MEMP acquired from MRD in February 2015 as noted above. A deferred income tax benefit of $1.2 million associated with these oil and gas properties was recorded during February 2015. As such, a net deferred income tax liability of $28.0 million has been reversed through additional paid in capital in MRD’s equity statement.
New Accounting Pronouncements	New Accounting Pronouncements Presentation of Debt Issuance Cost. In April 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the impact of adopting this guidance to be material to the Company's financial statements and related disclosures. Amendments to Consolidation Analysis . In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Schedule of Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): June 30, December 31, 2015 2014 Accrued capital expenditures $ 107,344 $ 80,350 Accrued lease operating expense 23,524 16,403 Accrued general and administrative expenses 13,324 8,516 Accrued ad valorem taxes 11,442 8,870 Accrued interest payable 27,118 24,797 Accrued environmental 1,147 2,092 Accrued current and deferred income taxes 58,597 51,929 Other miscellaneous, including operator advances 6,770 6,043 $ 249,266 $ 199,000
Schedule of Supplemental Cash Flow	Supplemental cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2015 June 30, 2014 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 85,019 $ 65,641 Cash paid for taxes 2,055 550 Noncash investing and financing activities: (Increase) decrease in capital expenditures in payables and accrued liabilities (26,994 ) (3,526 ) (Increase) decrease in accounts receivable related to acquisitions and divestitures 9,570 (4,732 ) Repurchases under MEMP repurchase program 2,710 —

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Transaction-Related Costs	Transaction-related costs, which include costs associated with acquisitions and divestitures, are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 $ 423 $ 1,593 $ 3,003 $ 4,055
Unaudited Pro Forma Results of Operations	The following unaudited pro forma combined results of operations are provided for the three and six months ended June 30, 2014 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 Three Months Ended For the Six Months Ended June 30, June 30, 2014 2014 MRD Consolidated and Combined (In thousands) Revenues $ 298,578 $ 550,597 Net income (loss) (1,028,123 ) (1,042,940 ) Basic and diluted earnings per share $ (5.00 ) $ (5.00 )

Fair Value Measurements of Fi26

Fair Value Measurements of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at June 30, 2015 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 821,489 $ — $ 821,489 Interest rate derivatives — — — — Total assets $ — $ 821,489 $ — $ 821,489 Liabilities: Commodity derivatives $ — $ 70,349 $ — $ 70,349 Interest rate derivatives — 2,911 — 2,911 Total liabilities $ — $ 73,260 $ — $ 73,260 Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 845,759 $ — $ 845,759 Interest rate derivatives — 1,305 — 1,305 Total assets $ — $ 847,064 $ — $ 847,064 Liabilities: Commodity derivatives $ — $ 71,639 $ — $ 71,639 Interest rate derivatives — 3,289 — 3,289 Total liabilities $ — $ 74,928 $ — $ 74,928

Risk Management and Derivativ27

Risk Management and Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Open Commodity Positions	At June 30, 2015, the MRD Segment had the following open commodity positions: Remaining 2015 2016 2017 2018 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,400,000 2,570,000 1,770,000 4,600,000 Weighted-average fixed price $ 4.15 $ 4.09 $ 4.24 $ 4.06 Collar contracts: Average Monthly Volume (MMBtu) 130,000 1,100,000 1,050,000 — Weighted-average floor price $ 4.00 $ 4.00 $ 4.00 $ — Weighted-average ceiling price $ 4.64 $ 4.71 $ 5.06 $ — Purchased put option contracts: Average Monthly Volume (MMBtu) 4,100,000 6,000,000 5,350,000 3,450,000 Weighted-average strike price $ 3.75 $ 3.51 $ 3.48 $ 3.62 Weighted-average deferred premium paid $ (0.33 ) $ (0.34 ) $ (0.32 ) $ (0.34 ) Written call option contracts (1): Average Monthly Volume (MMBtu) 3,225,000 — — — Weighted-average sold strike price $ 3.75 $ — $ — $ — Weighted-average deferred premium received $ 0.08 $ — $ — $ — TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 3,380,000 1,120,000 200,000 — Spread - Henry Hub $ (0.10 ) $ (0.10 ) $ (0.08 ) $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 42,000 8,500 28,000 31,625 Weighted-average fixed price $ 91.67 $ 84.80 $ 84.70 $ 84.50 Collar contracts: Average Monthly Volume (Bbls) 2,000 27,000 — — Weighted-average floor price $ 85.00 $ 80.00 $ — $ — Weighted-average ceiling price $ 101.35 $ 99.70 $ — $ — Purchased put option contracts: Average Monthly Volume (Bbls) 39,000 — — — Weighted-average strike price $ 85.00 $ — $ — $ — Weighted-average deferred premium paid $ (3.80 ) $ — $ — $ — Written call option contracts (1): Average Monthly Volume (Bbls) 29,250 — — — Weighted-average sold strike price $ 85.00 $ — $ — $ — Weighted-average deferred premium received $ 0.48 $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 163,000 185,658 — — Weighted-average fixed price $ 41.52 $ 34.06 $ — $ — (1 ) These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps. At June 30, 2015, the MEMP Segment had the following open commodity positions: Remaining 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,370,903 3,592,442 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.08 $ 4.14 $ 4.06 $ 4.18 $ 4.31 Collar contracts: Average Monthly Volume (MMBtu) 350,000 — — — — Weighted-average floor price $ 4.62 $ — $ — $ — $ — Weighted-average ceiling price $ 5.80 $ — $ — $ — $ — Call spreads (1): Average Monthly Volume (MMBtu) 80,000 — — — — Weighted-average sold strike price $ 5.25 $ — $ — $ — $ — Weighted-average bought strike price $ 6.75 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (MMBtu) 3,690,000 3,578,333 2,210,000 1,315,000 900,000 Spread $ (0.12 ) $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 272,531 279,813 301,600 312,000 160,000 Weighted-average fixed price $ 91.34 $ 86.87 $ 84.70 $ 83.74 $ 85.52 Collar contracts: Average Monthly Volume (Bbls) 5,000 — — — — Weighted-average floor price $ 80.00 $ — $ — $ — $ — Weighted-average ceiling price $ 94.00 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (Bbls) 97,000 95,000 30,000 — — Spread $ (7.06 ) $ (9.56 ) $ (2.35 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 210,200 213,100 43,300 — — Weighted-average fixed price $ 42.35 $ 35.64 $ 37.55 $ — $ — (1 ) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: Remaining 2015 2016 2017 2018 2018 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 3,030,000 3,003,333 1,800,000 1,200,000 900,000 Spread - Henry Hub $ (0.11 ) $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 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) 210,000 170,000 — — — Spread - Henry Hub $ (0.25 ) $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 300,000 270,000 295,000 — — Spread - Henry Hub $ (0.09 ) $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 57,000 55,000 — — — Spread - Brent $ (9.73 ) $ (13.35 ) $ — $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 40,000 30,000 — — Spread - WTI $ (3.25 ) $ (4.34 ) $ (2.35 ) $ — $ —
Schedule of Entity's Interest Rate Swap Open Positions	At June 30, 2015, we had the following interest rate swap open positions: Remaining Credit Facility 2015 2016 2017 2018 MEMP: Average Monthly Notional (in thousands) $ 391,667 $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 1.123 % 0.943 % 1.612 % 1.946 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR
Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at June 30, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives June 30, December 31, June 30, December 31, Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 323,437 $ 378,908 $ 34,066 $ 38,852 Interest rate swaps Short-term derivative instruments — — 2,312 3,289 Gross fair value 323,437 378,908 36,378 42,141 Netting arrangements Short-term derivative instruments (33,392 ) (38,852 ) (33,392 ) (38,852 ) Net recorded fair value Short-term derivative instruments $ 290,045 $ 340,056 $ 2,986 $ 3,289 Commodity contracts Long-term derivative instruments $ 498,052 $ 466,851 $ 36,283 $ 32,787 Interest rate swaps Long-term derivative instruments — 1,305 599 — Gross fair value 498,052 468,156 36,882 32,787 Netting arrangements Long-term derivative instruments (36,208 ) (32,787 ) (36,208 ) (32,787 ) Net recorded fair value Long-term derivative instruments $ 461,844 $ 435,369 $ 674 $ —
Schedule of Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the three and six months ended June 30, 2015 and 2014 (in thousands): For the Three Months Ended For the Six Months Ended Statements of June 30, June 30, Operations Location 2015 2014 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ 91,866 $ 141,590 $ (161,783 ) $ 201,072 Interest rate derivatives Interest expense, net 644 821 3,085 1,323

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2015 (in thousands): Asset retirement obligations at beginning of period $ 122,531 Liabilities added from acquisitions or drilling 1,025 Liabilities settled (780 ) Revision of estimates 572 Liabilities removed upon sale of wells (176 ) Accretion expense 3,536 Asset retirement obligations at end of period $ 126,708

Restricted Investments (Tables)

Restricted Investments (Tables)	6 Months Ended
	Jun. 30, 2015
Schedule Of Investments [Abstract]
Restricted Investment Balance	The components of the restricted investment balance consisted of the following at the dates indicated: June 30, December 31, 2015 2014 (In thousands) BOEM platform abandonment (See Note 15) $ 72,452 $ 69,954 BOEM lease bonds 794 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 2,938 2,701 California State Lands Commission pipeline right-of-way bond 3,005 3,005 City of Long Beach pipeline facility permit 500 500 Federal pipeline right-of-way bond 307 307 Port of Long Beach pipeline license 100 100 Restricted investments $ 80,096 $ 77,361

Long Term Debt (Tables)

Long Term Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated: June 30, December 31, 2015 2014 (In thousands) MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 165,000 $ 183,000 5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) 600,000 600,000 Subtotal 765,000 783,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 642,000 412,000 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) 700,000 700,000 6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) 496,990 500,000 Unamortized discounts (15,340 ) (16,587 ) Subtotal 1,823,650 1,595,413 Total long-term debt $ 2,588,650 $ 2,378,413 (1) The estimated fair value of this fixed-rate debt was $574.5 million and $534.0 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (2) The estimated fair value of this fixed-rate debt was $669.4 million and $563.5 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (3) The estimated fair value of this fixed-rate debt was $454.8 million and $380.0 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
Borrowing Base Credit Facility	The borrowing base for each credit facility was the following at the date indicated (in thousands): June 30, 2015 MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 725,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 1,300,000
Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended For the Six Months Ended Credit Facility June 30, June 30, 2015 2014 2015 2014 MRD Segment: MRD revolving credit facility 1.70 % 2.24 % 1.80 % 2.24 % WildHorse Resources revolver terminated June 2014 n/a 4.13 % n/a 4.04 % WildHorse Resources second lien terminated June 2014 n/a 6.44 % n/a 6.44 % MEMP Segment: MEMP revolving credit facility 2.08 % 2.09 % 2.01 % 1.98 %
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: June 30, December 31, 2015 2014 (In thousands) MRD Segment: MRD revolving credit facility $ 4,175 $ 4,285 MRD Senior Notes 11,766 12,455 MEMP Segment: MEMP revolving credit facility 4,972 6,468 2021 Senior Notes 12,251 13,308 2022 Senior Notes 7,582 7,958 $ 40,746 $ 44,474

Stockholders' Equity and Nonc31

Stockholders' Equity and Noncontrolling Interests (Tables)	6 Months Ended
	Jun. 30, 2015
Equity [Abstract]
Summary of Changes In Common Shares Issued	The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the six months ended June 30, 2015: Balance December 31, 2014 193,435,414 Shares of common stock repurchased (2,764,887 ) Restricted common shares issued (Note 11) 931,724 Restricted common shares repurchased (1) (60,773 ) Restricted common shares forfeited (13,750 ) Balance June 30, 2015 191,527,728 (1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Participants surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company.

Earnings per Share (Tables)

Earnings per Share (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Summary of Calculation of Earnings (Loss) Per Share, or EPS	The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts): For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 Numerator: Net income (loss) available to common stockholders $ (26,702 ) $ (961,707 ) $ 21,894 $ (961,707 ) Denominator: Weighted average common shares outstanding 189,628 192,500 190,163 192,500 Basic EPS $ (0.14 ) $ (5.00 ) $ 0.12 $ (5.00 ) Diluted EPS (1) $ (0.14 ) $ (5.00 ) $ 0.12 $ (5.00 ) (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. Under the treasury stock method, 364,321 and 329,312 incremental shares were included in the diluted EPS computation for the three and six months ended June 30, 2015, respectively.

Long-Term Incentive Plans (Tabl

Long-Term Incentive Plans (Tables)	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at December 31, 2014 1,059,211 $ 19.00 Granted (2) 931,724 $ 18.80 Forfeited (13,750 ) $ 18.73 Vested (274,355 ) $ 19.00 Restricted common shares outstanding at June 30, 2015 1,702,830 $ 18.89 (1) Determined by dividing the aggregate grant date fair value of awards issued. (2) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.5 million based on a grant date market price ranging from $18.05 to $18.91 per share. The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented: Number of Units Weighted-Average Grant Date Fair Value per Unit (1) Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 Granted (2) 795,077 $ 15.04 Forfeited (19,739 ) $ 19.48 Vested (476,057 ) $ 20.36 Restricted common units outstanding at June 30, 2015 1,392,801 $ 17.78 (1) Determined by dividing the aggregate grant date fair value of awards issued. ( 2 ) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.0 million based on a grant date market price ranging from $14.94 to $15.45 per unit.
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 $ 1,957 $ 175 $ 3,443 $ 175 The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 $ 2,565 $ 1,665 $ 4,906 $ 2,960

Incentive Units (Tables)

Incentive Units (Tables)	6 Months Ended
	Jun. 30, 2015
Compensation Related Costs [Abstract]
Fair Value of Incentive Units Estimated	The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: Exchanged Incentive Units Subsequent Incentive Units Valuation date 6/30/2015 6/30/2015 Dividend yield 0 % 0 % Expected volatility 46.42 % 46.42 % Risk-free rate 0.61 % 0.61 % Expected life (years) 1.92 1.92

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Schedule of Net Assets Recorded	WildHorse Resources recorded the following net assets (in thousands): Accounts receivable $ 2,274 Oil and natural gas properties, net 40,056 Accrued liabilities (297 ) Asset retirement obligations (277 ) Net assets $ 41,756
Book Value of Assets Sold	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)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Summary of Selected Business Segment Information	The following table presents selected business segment information for the periods indicated (in thousands): Other, Consolidated Adjustments & & Combined MRD MEMP Eliminations Totals Total revenues: Three Months Ended June 30, 2015 $ 78,605 $ 98,138 $ — $ 176,743 Three Months Ended June 30, 2014 110,569 144,208 — 254,777 Six Months Ended June 30, 2015 165,628 190,956 — 356,584 Six Months Ended June 30, 2014 198,305 261,093 — 459,398 Adjusted EBITDA: (1) Three Months Ended June 30, 2015 82,831 82,875 (75 ) 165,631 Three Months Ended June 30, 2014 81,471 84,475 (3,002 ) 162,944 Six Months Ended June 30, 2015 169,661 169,307 (151 ) 338,817 Six Months Ended June 30, 2014 146,223 146,521 (6,004 ) 286,740 Segment assets: (2) As of June 30, 2015 1,553,851 2,934,433 (7,981 ) 4,480,303 As of December 31, 2014 1,413,768 3,189,760 (9,981 ) 4,593,547 Total cash expenditures for additions to long-lived assets: Six Months Ended June 30, 2015 210,390 134,501 — 344,891 Six Months Ended June 30, 2014 156,630 311,205 — 467,835 (1) Adjustments and eliminations for the three and six months ended June 30, 2015 and 2014 include cash distributions that MEMP paid to MRD during the three and six months ended June 30, 2015 and 2014, related to the ownership of partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014. (2) As of June 30, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment.
Schedule of Calculation of Reportable Segment's Adjusted EBITDA	Calculation of Reportable Segments’ Adjusted EBITDA For the Three Months Ended June 30, 2015 Combined MRD MEMP Totals (In thousands) Net income (loss) $ (26,703 ) $ (113,859 ) $ (140,562 ) Interest expense, net 9,613 27,910 37,523 Income tax expense (benefit) (24,644 ) 876 (23,768 ) DD&A 35,827 46,286 82,113 Accretion of AROs 93 1,686 1,779 (Gain) loss on commodity derivative instruments 30,463 61,403 91,866 Cash settlements received (paid) on expired commodity derivative instruments 37,539 54,351 91,890 Transaction related costs 126 297 423 Incentive-based compensation expense 18,073 2,565 20,638 Exploration costs 2,230 32 2,262 Gain (loss) on sale of properties 50 — 50 Loss on settlement of AROs — 1,328 1,328 Non-cash equity (income) loss from MEMP 89 — 89 Cash distributions from MEMP 75 — 75 Adjusted EBITDA $ 82,831 $ 82,875 $ 165,706 For the Three Months Ended June 30, 2014 Combined MRD MEMP Totals (In thousands) Net income (loss) $ (951,747 ) $ (111,640 ) $ (1,063,387 ) Interest expense, net 16,494 18,037 34,531 Loss on debt extinguishment 37,248 — 37,248 Income tax expense (benefit) (11,846 ) 310 (11,536 ) DD&A 30,814 42,966 73,780 Accretion of AROs 127 1,400 1,527 (Gain) loss on commodity derivative instruments 3,244 138,346 141,590 Cash settlements received (paid) on expired commodity derivative instruments (3,408 ) (7,906 ) (11,314 ) (Gain) loss on sale of properties 3,167 — 3,167 Transaction related costs 500 1,093 1,593 Incentive-based compensation expense 942,992 1,665 944,657 Exploration costs 940 204 1,144 Non-cash equity (income) loss from MEMP 9,944 — 9,944 Cash distributions from MEMP 3,002 — 3,002 Adjusted EBITDA $ 81,471 $ 84,475 $ 165,946 For the Six Months Ended June 30, 2015 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 23,668 $ (276,517 ) $ (252,849 ) Interest expense, net 19,369 56,728 76,097 Income tax expense (benefit) 22,914 (1,494 ) 21,420 DD&A 76,359 97,552 173,911 Impairment of proved oil and natural gas properties — 251,347 251,347 Accretion of AROs 216 3,320 3,536 (Gain) loss on commodity derivative instruments (77,727 ) (84,056 ) (161,783 ) Cash settlements received (paid) on expired commodity derivative instruments 70,288 114,475 184,763 (Gain) loss on sale of properties 50 — 50 Transaction related costs 1,407 1,596 3,003 Incentive-based compensation expense 29,783 4,906 34,689 Exploration costs 2,956 122 3,078 Loss on settlement of AROs — 1,328 1,328 Non-cash equity (income) loss from MEMP 227 — 227 Cash distributions from MEMP 151 — 151 Adjusted EBITDA $ 169,661 $ 169,307 $ 338,968 For the Six Months Ended June 30, 2014 Combined MRD MEMP Totals (In thousands) Net income (loss) $ (945,357 ) $ (144,532 ) $ (1,089,889 ) Interest expense, net 34,468 34,115 68,583 Loss on debt extinguishment 37,248 — 37,248 Income tax expense (benefit) (11,821 ) 385 (11,436 ) DD&A 55,943 75,516 131,459 Accretion of AROs 257 2,791 3,048 (Gain) loss on commodity derivative instruments 15,960 185,112 201,072 Cash settlements received (paid) on expired commodity derivative instruments (8,629 ) (15,875 ) (24,504 ) (Gain) loss on sale of properties 3,057 — 3,057 Transaction related costs 1,068 2,987 4,055 Incentive-based compensation expense 944,015 2,960 946,975 Exploration costs 1,080 210 1,290 Non-cash equity (income) loss from MEMP 12,930 — 12,930 Provision for environmental remediation — 2,852 2,852 Cash distributions from MEMP 6,004 — 6,004 Adjusted EBITDA $ 146,223 $ 146,521 $ 292,744
Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss)	The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands). For the Three Months Ended For the Six Months Ended June 30, June 30, 2015 2014 2015 2014 Total Reportable Segments' Adjusted EBITDA $ 165,706 $ 165,946 $ 338,968 $ 292,744 Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net (37,523 ) (34,531 ) (76,097 ) (68,583 ) Loss on debt extinguishment — (37,248 ) — (37,248 ) Income tax benefit (expense) 23,768 11,536 (21,420 ) 11,436 DD&A (82,113 ) (73,780 ) (173,911 ) (131,459 ) Impairment of proved oil and natural gas properties — — (251,347 ) — Accretion of AROs (1,779 ) (1,527 ) (3,536 ) (3,048 ) Gains (losses) on commodity derivative instruments (91,866 ) (141,590 ) 161,783 (201,072 ) Cash settlements paid (received) on expired commodity derivative instruments (91,890 ) 11,314 (184,763 ) 24,504 Gain (loss) on sale of properties (50 ) (3,167 ) (50 ) (3,057 ) Transaction related costs (423 ) (1,593 ) (3,003 ) (4,055 ) Incentive-based compensation expense (20,638 ) (944,657 ) (34,689 ) (946,975 ) Exploration costs (2,262 ) (1,144 ) (3,078 ) (1,290 ) Provision for environmental remediation — — — (2,852 ) Loss on settlement of AROs (1,328 ) — (1,328 ) — Cash distributions from MEMP (75 ) (3,002 ) (151 ) (6,004 ) Net income (loss) $ (140,473 ) $ (1,053,443 ) $ (252,622 ) $ (1,076,959 )
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): Three Months Ended June 30, 2015 MRD MEMP Other, Adjustments & Eliminations Consolidated Revenues: Oil & natural gas sales $ 78,605 $ 97,221 $ — $ 175,826 Other revenues — 917 — 917 Total revenues 78,605 98,138 — 176,743 Costs and expenses: Lease operating 3,854 44,888 — 48,742 Gathering, processing, and transportation 14,289 9,048 — 23,337 Gathering, processing, and transportation - affiliate 3,813 — — 3,813 Pipeline operating — 500 — 500 Exploration 2,230 32 — 2,262 Production and ad valorem taxes 3,140 6,058 — 9,198 Depreciation, depletion, and amortization 35,827 46,286 — 82,113 Incentive unit compensation expense 16,116 — — 16,116 General and administrative 10,323 14,377 — 24,700 Accretion of asset retirement obligations 93 1,686 — 1,779 (Gain) loss on commodity derivative instruments 30,463 61,403 — 91,866 (Gain) loss on sale of properties 50 — — 50 Other, net — (943 ) (943 ) Total costs and expenses 120,198 183,335 — 303,533 Operating income (loss) (41,593 ) (85,197 ) — (126,790 ) Other income (expense): Interest expense, net (9,613 ) (27,910 ) — (37,523 ) Earnings from equity investments (89 ) — 89 — Other, net (52 ) 124 — 72 Total other income (expense) (9,754 ) (27,786 ) 89 (37,451 ) Income (loss) before income taxes (51,347 ) (112,983 ) 89 (164,241 ) Income tax benefit (expense) 24,644 (876 ) — 23,768 Net income (loss) $ (26,703 ) $ (113,859 ) $ 89 $ (140,473 ) Three Months Ended June 30, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated Revenues: Oil & natural gas sales $ 110,566 $ 142,870 $ — $ 253,436 Other revenues 3 1,338 — 1,341 Total revenues 110,569 144,208 — 254,777 Costs and expenses: Lease operating 4,793 27,528 — 32,321 Gathering, processing, and transportation 10,295 7,591 — 17,886 Pipeline operating — 676 — 676 Exploration 940 204 — 1,144 Production and ad valorem taxes 3,581 7,418 — 10,999 Depreciation, depletion, and amortization 30,814 42,966 — 73,780 Incentive unit compensation expense 942,817 — — 942,817 General and administrative 10,754 11,372 — 22,126 Accretion of asset retirement obligations 127 1,400 — 1,527 (Gain) loss on commodity derivative instruments 3,244 138,346 — 141,590 (Gain) loss on sale of properties 3,167 — — 3,167 Total costs and expenses 1,010,532 237,501 — 1,248,033 Operating income (loss) (899,963 ) (93,293 ) — (993,256 ) Other income (expense): Interest expense, net (16,494 ) (18,037 ) — (34,531 ) Loss on extinguishment of debt (37,248 ) — — (37,248 ) Earnings from equity investments (9,944 ) — 9,944 — Other, net 56 — — 56 Total other income (expense) (63,630 ) (18,037 ) 9,944 (71,723 ) Income (loss) before income taxes (963,593 ) (111,330 ) 9,944 (1,064,979 ) Income tax benefit (expense) 11,846 (310 ) — 11,536 Net income (loss) $ (951,747 ) $ (111,640 ) $ 9,944 $ (1,053,443 ) Six Months Ended June 30, 2015 MRD MEMP Other, Adjustments & Eliminations Consolidated Revenues: Oil & natural gas sales $ 165,628 $ 189,170 $ — $ 354,798 Other revenues — 1,786 — 1,786 Total revenues 165,628 190,956 — 356,584 Costs and expenses: Lease operating 9,076 85,366 — 94,442 Gathering, processing, and transportation 29,052 17,268 — 46,320 Gathering, processing, and transportation - affiliate 3,813 — — 3,813 Pipeline operating — 946 — 946 Exploration 2,956 122 — 3,078 Production and ad valorem taxes 5,915 12,713 — 18,628 Depreciation, depletion, and amortization 76,359 97,552 — 173,911 Impairment of proved oil and natural gas properties — 251,347 — 251,347 Incentive unit compensation expense 26,340 — — 26,340 General and administrative 23,299 28,888 — 52,187 Accretion of asset retirement obligations 216 3,320 — 3,536 (Gain) loss on commodity derivative instruments (77,727 ) (84,056 ) — (161,783 ) (Gain) loss on sale of properties 50 — — 50 Other, net — (943 ) — (943 ) Total costs and expenses 99,349 412,523 — 511,872 Operating income (loss) 66,279 (221,567 ) — (155,288 ) Other income (expense): Interest expense, net (19,369 ) (56,728 ) — (76,097 ) Earnings from equity investments (227 ) — 227 — Other, net (101 ) 284 — 183 Total other income (expense) (19,697 ) (56,444 ) 227 (75,914 ) Income (loss) before income taxes 46,582 (278,011 ) 227 (231,202 ) Income tax benefit (expense) (22,914 ) 1,494 — (21,420 ) Net income (loss) $ 23,668 $ (276,517 ) $ 227 $ (252,622 ) Six Months Ended June 30, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Revenues: Oil & natural gas sales $ 198,299 $ 258,847 $ — $ 457,146 Other revenues 6 2,246 — 2,252 Total revenues 198,305 261,093 — 459,398 Costs and expenses: Lease operating 8,028 57,648 — 65,676 Gathering, processing, and transportation 18,852 13,154 — 32,006 Pipeline operating — 1,165 — 1,165 Exploration 1,080 210 — 1,290 Production and ad valorem taxes 6,154 13,429 — 19,583 Depreciation, depletion, and amortization 55,943 75,516 — 131,459 Incentive unit compensation expense 943,840 — — 943,840 General and administrative 17,753 22,112 — 39,865 Accretion of asset retirement obligations 257 2,791 — 3,048 (Gain) loss on commodity derivative instruments 15,960 185,112 — 201,072 (Gain) loss on sale of properties 3,057 — — 3,057 Other, net — (12 ) — (12 ) Total costs and expenses 1,070,924 371,125 — 1,442,049 Operating income (loss) (872,619 ) (110,032 ) — (982,651 ) Other income (expense): Interest expense, net (34,468 ) (34,115 ) — (68,583 ) Loss on extinguishment on debt (37,248 ) — — (37,248 ) Earnings from equity investments (12,930 ) — 12,930 — Other, net 87 — — 87 Total other income (expense) (84,559 ) (34,115 ) 12,930 (105,744 ) Income before income taxes (957,178 ) (144,147 ) 12,930 (1,088,395 ) Income tax benefit (expense) 11,821 (385 ) — 11,436 Net income (loss) $ (945,357 ) $ (144,532 ) $ 12,930 $ (1,076,959 )

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
Gross Held-to-Maturity Investments	The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of June 30, 2015 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 140,003 Less: Outside working interest owners share (67,551 ) $ 72,452
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): June 30, 2016 $ 76,590 December 31, 2016 $ 78,660

Condensed Consolidating Finan38

Condensed Consolidating Financial Information (Tables)	6 Months Ended
	Jun. 30, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Condensed Consolidating Balance Sheets	The following condensed consolidating financial information presents the financial information of the Company on a unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities. As of June 30, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 1,485 $ 3,053 $ 163 $ — $ 4,701 Accounts receivable - trade 4,776 48,370 62,311 (6,118 ) 109,339 Accounts receivable - affiliates 8,783 — 1,069 (9,852 ) — Short-term derivative instruments 117,401 — 172,644 — 290,045 Prepaid expenses and other current assets 4,670 10,322 14,890 — 29,882 Total current assets 137,115 61,745 251,077 (15,970 ) 433,967 Property and equipment, net 17,433 1,187,230 2,265,256 — 3,469,919 Long-term derivative instruments 145,086 — 316,758 — 461,844 Investments in subsidiaries 1,025,875 — — (1,025,875 ) — Other long-term assets 13,211 — 101,362 — 114,573 Total assets $ 1,338,720 $ 1,248,975 $ 2,934,453 $ (1,041,845 ) $ 4,480,303 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 19,413 $ 143,658 $ 112,259 $ (697 ) $ 274,633 Accounts payable - affiliates 20 19,257 618 (14,711 ) 5,184 Revenues payable 142 35,080 31,718 — 66,940 Short-term derivative instruments 6 — 2,980 — 2,986 Total current liabilities 19,581 197,995 147,575 (15,408 ) 349,743 Long-term debt 765,000 — 1,823,650 — 2,588,650 Asset retirement obligations — 7,743 118,965 — 126,708 Long-term derivative instruments 5 — 669 — 674 Deferred tax liabilities 60,660 17,656 2,359 — 80,675 Other long-term liabilities 7,394 — — — 7,394 Total liabilities 852,640 223,394 2,093,218 (15,408 ) 3,153,844 Equity: — Equity 486,080 1,025,581 835,451 (1,861,032 ) 486,080 Noncontrolling interest — — 5,784 834,595 840,379 Total equity 486,080 1,025,581 841,235 (1,026,437 ) 1,326,459 Total liabilities & equity $ 1,338,720 $ 1,248,975 $ 2,934,453 $ (1,041,845 ) $ 4,480,303 As of December 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,241 $ 3,762 $ 970 $ (1,015 ) $ 5,958 Accounts receivable- trade 5,995 44,952 83,346 (2,717 ) 131,576 Accounts receivable - affiliates 10,047 — 28 (10,075 ) — Short-term derivative instruments 131,471 — 208,585 — 340,056 Prepaid expenses and other current assets 5,833 7,993 14,201 — 28,027 Total current assets 155,587 56,707 307,130 (13,807 ) 505,617 Property and equipment, net 16,601 1,050,722 2,470,333 — 3,537,656 Long-term derivative instruments 123,567 — 311,802 — 435,369 Investments in subsidiaries 1,139,792 — — (1,139,792 ) — Other long-term assets 14,124 5,660 100,521 (5,400 ) 114,905 Total assets $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued expenses $ 6,245 $ 107,068 $ 114,584 $ (3,125 ) $ 224,772 Accounts payable - affiliates — 3,638 6,409 (9,423 ) 624 Revenues payable — 27,242 30,110 — 57,352 Short-term derivative instruments — — 3,289 — 3,289 Total current liabilities 6,245 137,948 154,392 (12,548 ) 286,037 Long-term debt 783,000 1,595,413 — 2,378,413 Asset retirement obligations — 9,830 112,701 — 122,531 Deferred tax liabilities 69,431 — 30,986 (5,400 ) 95,017 Other long-term liabilities 8,585 — — — 8,585 Total liabilities 867,261 147,778 1,893,492 (17,948 ) 2,890,583 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interest — — 5,560 1,114,994 1,120,554 Total equity 582,410 965,311 1,296,294 (1,141,051 ) 1,702,964 Total liabilities & equity $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547
Condensed Consolidating Statements of Operations	Three Months Ended June 30, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 78,605 $ 97,221 $ — $ 175,826 Other income — — 917 — 917 Total revenues — 78,605 98,138 — 176,743 Costs and expenses: Lease operating — 3,854 44,888 — 48,742 Gathering, processing and transportation — 14,289 9,048 — 23,337 Gathering, processing and transportation - affiliate — 3,813 — — 3,813 Pipeline operating — — 500 — 500 Exploration — 2,230 32 — 2,262 Production and ad valorem taxes — 3,140 6,058 — 9,198 Depreciation, depletion and amortization 1,084 34,743 46,286 — 82,113 Incentive unit compensation expense 16,116 — — — 16,116 General and administrative 10,404 (81 ) 14,377 — 24,700 Accretion of asset retirement obligations — 93 1,686 — 1,779 (Gain) loss on commodity derivatives 30,463 — 61,403 — 91,866 (Gain) loss on sale of properties — 50 — — 50 Other, net — — (943 ) — (943 ) Total costs and expenses 58,067 62,131 183,335 — 303,533 Operating income (loss) (58,067 ) 16,474 (85,197 ) — (126,790 ) Other income (expense): Interest expense, net (9,526 ) (87 ) (27,910 ) — (37,523 ) Equity earnings from subsidiaries 7,469 — — (7,469 ) — Other, net — (52 ) 124 — 72 Total other income (expense) (2,057 ) (139 ) (27,786 ) (7,469 ) (37,451 ) Income before income taxes (60,124 ) 16,335 (112,983 ) (7,469 ) (164,241 ) Income tax benefit (expense) 33,422 (8,778 ) (876 ) — 23,768 Net income (loss) (26,702 ) 7,557 (113,859 ) (7,469 ) (140,473 ) Net income (loss) attributable to noncontrolling interest — — 65 (113,836 ) (113,771 ) Net income (loss) attributable to Memorial Resource Development Corp. $ (26,702 ) $ 7,557 $ (113,924 ) $ 106,367 $ (26,702 ) Three Months Ended June 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 110,566 $ 142,870 $ — $ 253,436 Other income — 3 1,338 — 1,341 Total revenues — 110,569 144,208 — 254,777 Costs and expenses: Lease operating — 4,793 27,528 — 32,321 Gathering, processing and transportation — 10,295 7,591 — 17,886 Pipeline operating — — 676 — 676 Exploration — 940 204 — 1,144 Production and ad valorem taxes — 3,581 7,418 — 10,999 Depreciation, depletion and amortization — 30,814 42,966 — 73,780 Incentive unit compensation expense 111,757 831,060 — — 942,817 General and administrative 175 10,579 11,372 — 22,126 Accretion of asset retirement obligations — 127 1,400 — 1,527 (Gain) loss on commodity derivatives (3,435 ) 6,679 138,346 — 141,590 (Gain) loss on sale of properties — 3,167 — — 3,167 Total costs and expenses 108,497 902,035 237,501 — 1,248,033 Operating income (loss) (108,497 ) (791,466 ) (93,293 ) — (993,256 ) Other income (expense): Interest expense, net (976 ) (15,518 ) (18,037 ) — (34,531 ) Debt extinguishment costs (23,562 ) (13,686 ) — — (37,248 ) Equity earnings from subsidiaries (836,746 ) 3,260 — 833,486 — Other, net — 56 — — 56 Total other income (expense) (861,284 ) (25,888 ) (18,037 ) 833,486 (71,723 ) Income before income taxes (969,781 ) (817,354 ) (111,330 ) 833,486 (1,064,979 ) Income tax benefit (expense) 8,074 3,772 (310 ) — 11,536 Net income (loss) (961,707 ) (813,582 ) (111,640 ) 833,486 (1,053,443 ) Net income (loss) attributable to noncontrolling interest — — (12 ) (105,082 ) (105,094 ) Net income (loss) attributable to Memorial Resource Development Corp. $ (961,707 ) $ (813,582 ) $ (111,628 ) $ 938,568 $ (948,349 ) Six Months Ended June 30, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 165,628 $ 189,170 $ — $ 354,798 Other income — — 1,786 — 1,786 Total revenues — 165,628 190,956 — 356,584 Costs and expenses: Lease operating — 9,076 85,366 — 94,442 Gathering, processing and transportation — 29,052 17,268 — 46,320 Gathering, processing and transportation -affiliate — 3,813 — — 3,813 Pipeline operating — — 946 — 946 Exploration — 2,956 122 — 3,078 Production and ad valorem taxes — 5,915 12,713 — 18,628 Depreciation, depletion and amortization 2,052 74,307 97,552 — 173,911 Impairment of proved oil and natural gas properties — — 251,347 — 251,347 Incentive unit compensation expense 26,340 — — — 26,340 General and administrative 21,329 1,970 28,888 — 52,187 Accretion of asset retirement obligations — 216 3,320 — 3,536 (Gain) loss on commodity derivatives (77,727 ) — (84,056 ) — (161,783 ) (Gain) loss on sale of properties — 50 — — 50 Other, net — — (943 ) — (943 ) Total costs and expenses (28,006 ) 127,355 412,523 — 511,872 Operating income (loss) 28,006 38,273 (221,567 ) — (155,288 ) Other income (expense): Interest expense, net (19,282 ) (87 ) (56,728 ) — (76,097 ) Equity earnings from subsidiaries 17,343 — — (17,343 ) — Other, net — (101 ) 284 — 183 Total other income (expense) (1,939 ) (188 ) (56,444 ) (17,343 ) (75,914 ) Income before income taxes 26,067 38,085 (278,011 ) (17,343 ) (231,202 ) Income tax benefit (expense) (4,023 ) (18,891 ) 1,494 — (21,420 ) Net income (loss) 22,044 19,194 (276,517 ) (17,343 ) (252,622 ) Net income (loss) attributable to noncontrolling interest — — 224 (274,890 ) (274,666 ) Net income (loss) attributable to Memorial Resource Development Corp. $ 22,044 $ 19,194 $ (276,741 ) $ 257,547 $ 22,044 Six Months Ended June 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 198,299 $ 258,847 $ — $ 457,146 Other income — 6 2,246 — 2,252 Total revenues — 198,305 261,093 — 459,398 Costs and expenses: Lease operating — 8,028 57,648 — 65,676 Gathering, processing and transportation — 18,852 13,154 — 32,006 Pipeline operating — — 1,165 — 1,165 Exploration — 1,080 210 — 1,290 Production and ad valorem taxes — 6,154 13,429 — 19,583 Depreciation, depletion and amortization — 55,943 75,516 — 131,459 Incentive unit compensation expense 111,757 831,060 1,023 — 943,840 General and administrative 175 17,561 22,129 — 39,865 Accretion of asset retirement obligations — 257 2,791 — 3,048 (Gain) loss on commodity derivatives (3,435 ) 19,395 185,112 — 201,072 (Gain) loss on sale of properties — 3,167 (110 ) — 3,057 Other, net — — (12 ) — (12 ) Total costs and expenses 108,497 961,497 372,055 — 1,442,049 Operating income (loss) (108,497 ) (763,192 ) (110,962 ) — (982,651 ) Other income (expense): Interest expense, net (976 ) (33,492 ) (34,115 ) — (68,583 ) Debt extinguishment costs (23,562 ) (13,686 ) — — (37,248 ) Equity earnings from subsidiaries (836,746 ) — — 836,746 — Other, net — 87 — — 87 Total other income (expense) (861,284 ) (47,091 ) (34,115 ) 836,746 (105,744 ) Income before income taxes (969,781 ) (810,283 ) (145,077 ) 836,746 (1,088,395 ) Income tax benefit (expense) 8,074 3,747 (385 ) — 11,436 Net income (loss) (961,707 ) (806,536 ) (145,462 ) 836,746 (1,076,959 ) Net income (loss) attributable to noncontrolling interest — — 43 (137,025 ) (136,982 ) Net income (loss) attributable to Memorial Resource Development Corp. (961,707 ) (806,536 ) (145,505 ) 973,771 (939,977 )
Condensed Consolidating Statements of Cash Flows	Six Months Ended June 30, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by (used in) operating activities $ 37,045 $ 152,009 $ 111,718 $ 1,015 $ 301,787 Cash flows from investing activities: Acquisitions of oil and natural gas properties — — (6,095 ) — (6,095 ) Acquisition post-closing adjustment receipts — — 9,570 — 9,570 Additions to oil and gas properties — (207,103 ) (128,323 ) — (335,426 ) Additions to other property and equipment (2,871 ) (416 ) (83 ) — (3,370 ) Additions to restricted investments — — (2,735 ) — (2,735 ) Investments in subsidiaries (44,280 ) — — 44,280 — Distributions from subsidiaries 78,547 — — (78,547 ) — Proceeds from the sale of oil and gas properties — 13,612 — — 13,612 Net cash used in investing activities 31,396 (193,907 ) (127,666 ) (34,267 ) (324,444 ) Cash flows from financing activities: Advances on revolving credit facility 181,000 — 252,000 — 433,000 Payments on revolving credit facility (199,000 ) — (22,000 ) — (221,000 ) Repayment of senior notes — — (2,914 ) — (2,914 ) Deferred finance costs — — (235 ) — (235 ) Capital contributions — 41,189 3,091 (44,280 ) — Distributions to MRD — — (78,396 ) 78,396 — Distribution to partners — — (92,628 ) 92,628 — Distribution to noncontrolling interests — — — (92,477 ) (92,477 ) Repurchases of equity (51,197 ) — (43,777 ) — (94,974 ) Net cash provided by financing activities (69,197 ) 41,189 15,141 34,267 21,400 Net change in cash and cash equivalents (756 ) (709 ) (807 ) 1,015 (1,257 ) Cash and cash equivalents, beginning of period 2,241 3,762 970 (1,015 ) 5,958 Cash and cash equivalents, end of period $ 1,485 $ 3,053 $ 163 $ — $ 4,701 Six Months Ended June 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) operating activities $ (5,169 ) $ 73,471 $ 109,445 $ — $ 177,747 Cash flows from investing activities: Acquisitions of oil and natural gas properties — — (173,000 ) — (173,000 ) Additions to oil and gas properties — (155,362 ) (138,205 ) — (293,567 ) Additions to other property and equipment (263 ) (1,005 ) — — (1,268 ) Additions to restricted investments — — (2,121 ) — (2,121 ) Investments in subsidiaries (616,353 ) (3,304 ) — 619,657 — Distributions from subsidiaries — 48,596 — (48,596 ) — Change in restricted cash — 49,946 — — 49,946 Deposits for property acquisitions — — (70,125 ) — (70,125 ) Proceeds from the sale of oil and gas properties — — 6,700 — 6,700 Other — — (301 ) — (301 ) Net cash used in investing activities (616,616 ) (61,129 ) (377,052 ) 571,061 (483,736 ) Cash flows from financing activities: Advances on revolving credit facility 1,004,000 126,800 418,000 — 1,548,800 Payments on revolving credit facility (385,000 ) (329,900 ) (62,000 ) — (776,900 ) Termination of second lien credit facility — (328,282 ) — — (328,282 ) Redemption of senior notes (351,808 ) — — — (351,808 ) Deferred finance costs (4,679 ) (965 ) (590 ) — (6,234 ) Proceeds from MRD initial public offering 408,500 — — — 408,500 Costs incurred in conjunction with initial public offering (26,875 ) — — — (26,875 ) Capital contributions — 614,350 5,307 (619,657 ) — Contributions from NGP affiliates related to sale of properties — — 1,165 — 1,165 Purchase of additional interests in subsidiaries (3,292 ) — — — (3,292 ) Distribution to equity owners — — (110,440 ) 110,440 — Distribution to NGP affiliates related to purchase of assets — (63,389 ) (3,304 ) — (66,693 ) Distribution to noncontrolling interests — — — (61,844 ) (61,844 ) Distributions to MRD Holdco (17,207 ) (39,520 ) (3,076 ) — (59,803 ) Distribution to NGP affiliates related to sale of assets, net of cash received — (32,770 ) — — (32,770 ) Other — 270 — — 270 Net cash provided by financing activities 623,639 (53,406 ) 245,062 (571,061 ) 244,234 Net change in cash and cash equivalents 1,854 (41,064 ) (22,545 ) — (61,755 ) Cash and cash equivalents, beginning of period — 48,619 29,102 — 77,721 Cash and cash equivalents, end of period $ 1,854 $ 7,555 $ 6,557 $ — $ 15,966

Background, Organization and 39

Background, Organization and Basis of Presentation - Additional Information (Detail) $ in Millions	1 Months Ended	6 Months Ended
	Feb. 28, 2015USD ($)	Jun. 30, 2015Segment
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment		2
MEMP [Member]
Consolidation And Basis Of Presentation [Line Items]
Net payment made to affiliate for acquisition of oil and natural gas properties	$ 78.4
Net equity deemed contribution (distribution) related to net assets transferred	$ 127.1
Limited Partner [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage		99.90%
General Partner [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage		0.10%
MRD Operating [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage		100.00%

Summary of Significant Accoun40

Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Accrued capital expenditures	$ 107,344	$ 80,350
Accrued lease operating expense	23,524	16,403
Accrued general and administrative expenses	13,324	8,516
Accrued ad valorem taxes	11,442	8,870
Accrued interest payable	27,118	24,797
Accrued environmental	1,147	2,092
Accrued current and deferred income taxes	58,597	51,929
Other miscellaneous, including operator advances	6,770	6,043
Accrued liabilities	$ 249,266	$ 199,000

Summary of Significant Accoun41

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 85,019	$ 65,641
Cash paid for taxes	2,055	550
Noncash investing and financing activities:
(Increase) decrease in capital expenditures in payables and accrued liabilities	(26,994)	(3,526)
(Increase) decrease in accounts receivable related to acquisitions and divestitures	9,570	$ (4,732)
MEMP [Member]
Noncash investing and financing activities:
Repurchases under MEMP repurchase program	$ 2,710

Summary of Significant Accoun42

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	1 Months Ended	3 Months Ended		6 Months Ended
	Feb. 28, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Unrecognized tax benefits		$ 0		$ 0
Effective tax rate		14.50%	1.10%	(9.30%)	1.10%
Deferred tax liabilities		$ 80,675,000		$ 80,675,000		$ 95,017,000
Deferred income tax liabilities, net		$ 28,000,000		$ 28,000,000
MEMP [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred tax liabilities						$ 29,200,000
Deferred income tax benefit	$ 1,200,000

Acquisitions and Divestitures -

Acquisitions and Divestitures - Transaction Related Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Business Acquisition [Line Items]
Transaction related costs	$ 423	$ 1,593	$ 3,003	$ 4,055
General and administrative expense [Member]
Business Acquisition [Line Items]
Transaction related costs	$ 423	$ 1,593	$ 3,003	$ 4,055

Acquisitions and Divestitures44

Acquisitions and Divestitures - Additional Information (Detail) - USD ($) $ in Millions	Apr. 17, 2015	Jul. 01, 2014	May. 09, 2014	Mar. 25, 2014
Northern Oklahoma [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures			$ 7.6
Gain (loss) on sale of oil and gas properties			$ (3.2)
Eagle Ford Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Payments to acquire oil and gas properties and leases				$ 168.1
Wyoming Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Payments to acquire oil and gas properties and leases		$ 906.1
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures	$ 13.6
Gain (loss) on sale of oil and gas properties	$ (0.1)

Acquisitions and Divestitures45

Acquisitions and Divestitures - Unaudited Pro Forma Results of Operations (Detail) - Jun. 30, 2014 - USD ($) $ / shares in Units, $ in Thousands	Total	Total
Business Combinations [Abstract]
Revenues	$ 298,578	$ 550,597
Net income (loss)	$ (1,028,123)	$ (1,042,940)
Basic and diluted earnings per share	$ (5)	$ (5)

Fair Value Measurements of Fi46

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value, Measurements [Member] - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Assets:
Fair value of derivative asset	$ 821,489	$ 847,064
Liabilities:
Fair value of derivative liability	73,260	74,928
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	821,489	847,064
Liabilities:
Fair value of derivative liability	73,260	74,928
Commodity derivatives [Member]
Assets:
Fair value of derivative asset	821,489	845,759
Liabilities:
Fair value of derivative liability	70,349	71,639
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	821,489	845,759
Liabilities:
Fair value of derivative liability	70,349	71,639
Interest rate derivatives [Member]
Assets:
Fair value of derivative asset		1,305
Liabilities:
Fair value of derivative liability	2,911	3,289
Interest rate derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset		1,305
Liabilities:
Fair value of derivative liability	$ 2,911	$ 3,289

Fair Value Measurements of Fi47

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties		$ 251,347
Carrying value of properties after impairment charges		3,469,919		$ 3,537,656
MEMP [Member] | East Texas, Wyoming and Colorado [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	$ 0	251,300	$ 0
Carrying value of properties after impairment charges		$ 157,600

Risk Management and Derivativ48

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($)	1 Months Ended	6 Months Ended
	Feb. 28, 2015	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk		$ 91,000,000
Effect netting arrangements, counterparty exposure		171,500,000
Derivative asset		262,500,000
Deferred premiums		3,400,000
Cash collateral received or pledged		0
Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure		78,100,000
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		286,100,000
Effect netting arrangements, counterparty exposure		199,700,000
Derivative asset		485,800,000
Cash settlement receipt	$ 27,100,000
MRD [Member] | Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure		$ 56,600,000

Risk Management and Derivativ49

Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail) - Jun. 30, 2015		MMBTU$ / MMBTU$ / bblbbl
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,400,000
Weighted-average fixed price		4.15
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		130,000
Weighted-average floor price		4
Weighted-average ceiling price		4.64
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		4,100,000
Weighted-average strike price		3.75
Weighted-average deferred premium paid		(0.33)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Call Option [Member] | Written [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	[1]	3,225,000
Weighted-average sold strike price	[1]	3.75
Weighted-average deferred premium received	[1]	0.08
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,380,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread		(0.10)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,370,903
Weighted-average fixed price		4.08
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		350,000
Weighted-average floor price		4.62
Weighted-average ceiling price		5.80
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	[2]	80,000
Weighted-average sold strike price	[2]	5.25
Weighted-average bought strike price	[2]	6.75
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,690,000
Spread		(0.12)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,030,000
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) | 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) | 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) | 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 Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		91.67
Average Monthly Volume (Bbls) | bbl		42,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl		85
Weighted-average ceiling price | $ / bbl		101.35
Average Monthly Volume (Bbls) | bbl		2,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Weighted-average strike price | $ / bbl		85
Weighted-average deferred premium paid | $ / bbl		(3.80)
Average Monthly Volume (Bbls) | bbl		39,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Call Option [Member] | Written [Member]
Derivative [Line Items]
Weighted-average sold strike price | $ / bbl		85
Weighted-average deferred premium received | $ / bbl		0.48
Average Monthly Volume (Bbls) | bbl		29,250
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		91.34
Average Monthly Volume (Bbls) | bbl		272,531
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl		80
Weighted-average ceiling price | $ / bbl		94
Average Monthly Volume (Bbls) | bbl		5,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread | $ / bbl		(7.06)
Average Monthly Volume (Bbls) | bbl		97,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Spread | $ / bbl		(9.73)
Average Monthly Volume (Bbls) | bbl		57,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread | $ / bbl		(3.25)
Average Monthly Volume (Bbls) | bbl		40,000
2015 [Member] | NGL Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		41.52
Average Monthly Volume (Bbls) | bbl		163,000
2015 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		42.35
Average Monthly Volume (Bbls) | bbl		210,200
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		2,570,000
Weighted-average fixed price		4.09
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		1,100,000
Weighted-average floor price		4
Weighted-average ceiling price		4.71
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		6,000,000
Weighted-average strike price		3.51
Weighted-average deferred premium paid		(0.34)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		1,120,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread		(0.10)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,592,442
Weighted-average fixed price		4.14
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,578,333
Spread		(0.07)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,003,333
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread		(0.07)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | 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] | CIG basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		170,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread		(0.30)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | 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 Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		84.80
Average Monthly Volume (Bbls) | bbl		8,500
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl		80
Weighted-average ceiling price | $ / bbl		99.70
Average Monthly Volume (Bbls) | bbl		27,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		86.87
Average Monthly Volume (Bbls) | bbl		279,813
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread | $ / bbl		(9.56)
Average Monthly Volume (Bbls) | bbl		95,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Spread | $ / bbl		(13.35)
Average Monthly Volume (Bbls) | bbl		55,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread | $ / bbl		(4.34)
Average Monthly Volume (Bbls) | bbl		40,000
2016 [Member] | NGL Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		34.06
Average Monthly Volume (Bbls) | bbl		185,658
2016 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		35.64
Average Monthly Volume (Bbls) | bbl		213,100
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		1,770,000
Weighted-average fixed price		4.24
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		1,050,000
Weighted-average floor price		4
Weighted-average ceiling price		5.06
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		5,350,000
Weighted-average strike price		3.48
Weighted-average deferred premium paid		(0.32)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		200,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [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) | MMBTU		3,350,067
Weighted-average fixed price		4.06
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		2,210,000
Spread		(0.04)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		1,800,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread		(0.07)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | 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] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		295,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread		0.03
2017 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		84.70
Average Monthly Volume (Bbls) | bbl		28,000
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		84.70
Average Monthly Volume (Bbls) | bbl		301,600
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread | $ / bbl		(2.35)
Average Monthly Volume (Bbls) | bbl		30,000
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread | $ / bbl		(2.35)
Average Monthly Volume (Bbls) | bbl		30,000
2017 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		37.55
Average Monthly Volume (Bbls) | bbl		43,300
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		4,600,000
Weighted-average fixed price		4.06
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,450,000
Weighted-average strike price		3.62
Weighted-average deferred premium paid		(0.34)
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		3,060,000
Weighted-average fixed price		4.18
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		1,315,000
Spread		(0.02)
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		1,200,000
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread		(0.03)
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | 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 Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		84.50
Average Monthly Volume (Bbls) | bbl		31,625
2018 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		83.74
Average Monthly Volume (Bbls) | bbl		312,000
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		2,814,583
Weighted-average fixed price		4.31
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		900,000
Spread		0.01
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU		900,000
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread		0.01
2019 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl		85.52
Average Monthly Volume (Bbls) | bbl		160,000
[1]	These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps
[2]	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 Derivativ50

Risk Management and Derivative Instruments - Schedule of Entity's Interest Rate Swap Open Positions (Detail) - Jun. 30, 2015 - MEMP [Member] - Interest rate swaps [Member] - USD ($) $ in Thousands	Total
2015 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 391,667
Weighted-average fixed rate	1.123%
Floating rate	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	0.943%
Floating rate	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	1.612%
Floating rate	1 Month LIBOR
2018 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 100,000
Weighted-average fixed rate	1.946%
Floating rate	1 Month LIBOR

Risk Management and Derivativ51

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 ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 290,045	$ 340,056
Asset Derivatives, Net recorded fair value	461,844	435,369
Liability Derivatives, Net recorded fair value	2,986	3,289
Liability Derivatives, Net recorded fair value	674
Short-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	323,437	378,908
Asset Derivatives, Netting arrangements	(33,392)	(38,852)
Asset Derivatives, Net recorded fair value	290,045	340,056
Liability Derivatives, Gross fair value	36,378	42,141
Liability Derivatives, Netting arrangements	(33,392)	(38,852)
Liability Derivatives, Net recorded fair value	2,986	3,289
Short-term derivative instruments [Member] | Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	323,437	378,908
Liability Derivatives, Gross fair value	34,066	38,852
Short-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Liability Derivatives, Gross fair value	2,312	3,289
Long-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	498,052	468,156
Asset Derivatives, Netting arrangements	(36,208)	(32,787)
Asset Derivatives, Net recorded fair value	461,844	435,369
Liability Derivatives, Gross fair value	36,882	32,787
Liability Derivatives, Netting arrangements	(36,208)	(32,787)
Liability Derivatives, Net recorded fair value	674
Long-term derivative instruments [Member] | Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	498,052	466,851
Liability Derivatives, Gross fair value	36,283	32,787
Long-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value		$ 1,305
Liability Derivatives, Gross fair value	$ 599

Risk Management and Derivativ52

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	$ 91,866	$ 141,590	$ (161,783)	$ 201,072
Interest expense, net	37,523	34,531	76,097	68,583
Commodity derivative contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	91,866	141,590	(161,783)	201,072
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	$ 644	$ 821	$ 3,085	$ 1,323

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period			$ 122,531
Liabilities added from acquisitions or drilling			1,025
Liabilities settled			(780)
Revision of estimates			572
Liabilities removed upon sale of wells			(176)
Accretion expense	$ 1,779	$ 1,527	3,536	$ 3,048
Asset retirement obligations at end of period	$ 126,708		$ 126,708

Restricted Investments - Restri

Restricted Investments - Restricted Investment Balance (Detail) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Schedule Of Investments [Line Items]
Restricted investments	$ 80,096	$ 77,361
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	72,452	69,954
BOEM lease bonds [Member]
Schedule Of Investments [Line Items]
Restricted investments	794	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	2,938	2,701
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	3,005	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Schedule Of Investments [Line Items]
Restricted investments	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 100	$ 100

Long Term Debt - Consolidated D

Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt		$ 2,588,650	$ 2,378,413
MRD Segment [Member]
Debt Instrument [Line Items]
Long-term debt		765,000	783,000
MRD Segment [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility		165,000	183,000
MRD Segment [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	[1]	600,000	600,000
MEMP [Member]
Debt Instrument [Line Items]
Unamortized discounts		(15,340)	(16,587)
Long-term debt		1,823,650	1,595,413
MEMP [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility		642,000	412,000
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member]
Debt Instrument [Line Items]
Senior Notes	[2]	700,000	700,000
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Senior Notes	[3]	$ 496,990	$ 500,000
[1]	The estimated fair value of this fixed-rate debt was $574.5 million and $534.0 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[2]	The estimated fair value of this fixed-rate debt was $669.4 million and $563.5 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[3]	The estimated fair value of this fixed-rate debt was $454.8 million and $380.0 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Long Term Debt - Consolidated56

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
MRD Segment [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities		$ 2,000,000,000
Maturity date	Jun. 18, 2019
MRD Segment [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Jul. 1, 2022
Debt interest rate		5.875%
Estimated fair value of fixed rate debt		$ 574,500,000	$ 534,000,000
MEMP [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities		$ 2,000,000,000
Maturity date	Mar. 19, 2018
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member]
Debt Instrument [Line Items]
Maturity date	May 1, 2021
Debt interest rate		7.625%
Estimated fair value of fixed rate debt		$ 669,400,000	563,500,000
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 1, 2022
Debt interest rate		6.875%
Estimated fair value of fixed rate debt		$ 454,800,000	$ 380,000,000

Long Term Debt - Borrowing Base

Long Term Debt - Borrowing Base Credit Facility (Detail) $ in Thousands	Jun. 30, 2015USD ($)
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 725,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 1,300,000

Long Term Debt - Borrowing Ba58

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Jun. 30, 2015USD ($)
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
MRD Segment [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.70%	2.24%	1.80%	2.24%
MRD Segment [Member] | WildHorse Resources, LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		4.13%		4.04%
MRD Segment [Member] | WildHorse Resources second lien [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		6.44%		6.44%
MEMP [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	2.08%	2.09%	2.01%	1.98%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 40,746	$ 44,474
MRD Segment [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	4,175	4,285
MRD Segment [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	11,766	12,455
MEMP [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	4,972	6,468
MEMP [Member] | 2021 Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	12,251	13,308
MEMP [Member] | 2022 Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 7,582	$ 7,958

Stockholders' Equity and Nonc61

Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) - USD ($)	Mar. 16, 2015	Jun. 30, 2015	Apr. 30, 2015	Dec. 31, 2014
Stockholders Equity Note Disclosure [Line Items]
Common stock, shares authorized		600,000,000		600,000,000
Common stock, par value		$ 0.01		$ 0.01
Payments for repurchase of common stock		$ 47,785,000
Stock repurchased and retired during period, shares		0
Stock repurchase program, authorized amount			$ 50,000,000
MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock		$ 45,117,000
MEMP [Member] | Noncontrolling Interest [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock		$ 45,117,000
Stock repurchased and retired during period, shares		2,951,612
Payments for repurchase of common units		$ 43,900,000
MRD Segment [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock	$ 47,800,000
Stock repurchased and retired during period, shares	2,764,887

Stockholders' Equity and Nonc62

Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail)	6 Months Ended
	Jun. 30, 2015shares
Class of Stock [Line Items]
Beginning Balance	193,435,414
Shares of common stock repurchased	0
Ending Balance	191,527,728
Common Stock [Member]
Class of Stock [Line Items]
Shares of common stock repurchased	(2,764,887)
Restricted common shares issued (Note 11)	931,724
Restricted common shares repurchased	(60,773)
Restricted common shares forfeited	(13,750)

Stockholders' Equity and Nonc63

Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Parenthetical) (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2015USD ($)
Statement Of Stockholders Equity [Abstract]
Payments remitted for employees tax obligations	$ 1.2

Earnings per Share - Summary of

Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Numerator:
Net income (loss) available to common stockholders	$ (26,702)	$ (961,707)	$ 21,894	$ (961,707)
Denominator:
Weighted average common shares outstanding	189,628	192,500	190,163	192,500
Basic EPS	$ (0.14)	$ (5)	$ 0.12	$ (5)
Diluted EPS	$ (0.14)	$ (5)	$ 0.12	$ (5)

Earnings per Share - Summary 65

Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Parenthetical) (Detail) - Jun. 30, 2015 - shares shares in Thousands	Total	Total
Earnings Per Share [Abstract]
Incremental shares included in diluted EPS computation	364,321	329,312

Long-Term Incentive Plans - Sum

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) - 6 months ended Jun. 30, 2015 - Restricted Stock [Member] - $ / shares	Total
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common shares outstanding, Number of Shares, Beginning Balance	1,059,211
Granted, Number of Shares	931,724
Forfeited, Number of Shares	(13,750)
Vested, Number of Shares	(274,355)
Restricted common shares outstanding, Number of Shares, Ending Balance	1,702,830
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance	$ 19
Granted, Weighted-Average Grant Date Fair Value Per Shares	18.80
Forfeited, Weighted-Average Grant Date Fair Value Per Shares	18.73
Vested, Weighted-Average Grant Date Fair Value Per Shares	19
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance	$ 18.89
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Shares	795,077
Forfeited, Number of Shares	(19,739)
Vested, Number of Shares	(476,057)
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance	$ 20.93
Granted, Weighted-Average Grant Date Fair Value Per Shares	15.04
Forfeited, Weighted-Average Grant Date Fair Value Per Shares	19.48
Vested, Weighted-Average Grant Date Fair Value Per Shares	20.36
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance	$ 17.78
Restricted common shares outstanding, Number of Units, Beginning Balance	1,093,520
Restricted common shares outstanding, Number of Units, Ending Balance	1,392,801

Long-Term Incentive Plans - S67

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - 6 months ended Jun. 30, 2015 - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Millions	Total
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 18.80
MRD Segment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$ 17.5
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$ 12
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 15.04
Minimum [Member] | MRD Segment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	18.05
Minimum [Member] | MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	14.94
Maximum [Member] | MRD Segment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	18.91
Maximum [Member] | MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 15.45

Long-Term Incentive Plans - S68

Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$ 20,638	$ 944,657	$ 34,689	$ 946,975
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	2,565	1,665	4,906	2,960
Restricted Stock [Member] | MRD Segment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$ 1,957	$ 175	$ 3,443	$ 175

Long-Term Incentive Plans - Add

Long-Term Incentive Plans - Additional Information (Detail) - Jun. 30, 2015 - Restricted Stock [Member] - USD ($) $ in Millions	Total
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 30.9
Unrecognized compensation cost weighted-average period	2 years 10 months 28 days
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 23.2
Unrecognized compensation cost weighted-average period	2 years 2 months 23 days

Incentive Units - Additional In

Incentive Units - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Equity Incentive Plan [Line Items]
Compensation expense	$ 20,638	$ 944,657	$ 34,689	$ 946,975
MRD Holdco LLC [Member]
Equity Incentive Plan [Line Items]
The number of incentive units authorized by governing documents	1,000		1,000
MRD Holdco LLC [Member] | Exchanged Incentive Units [Member]
Equity Incentive Plan [Line Items]
Incentive units granted in an exchange for cancelled predecessor awards			930
Compensation expense	$ 16,100		$ 26,300
Unrecognized compensation expense	$ 87,700		$ 87,700
Remaining expected life			1 year 11 months 1 day
MRD Holdco LLC [Member] | Subsequent Incentive Units [Member]
Equity Incentive Plan [Line Items]
Subsequent incentive units	70		70

Incentive Units - Fair Value of

Incentive Units - Fair Value of Incentive Units Estimated (Detail) - 6 months ended Jun. 30, 2015	Total
Exchanged Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	Jun. 30, 2015
Dividend yield	0.00%
Expected volatility	46.42%
Risk-free rate	0.61%
Expected life (years)	1 year 11 months 1 day
Subsequent Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	Jun. 30, 2015
Dividend yield	0.00%
Expected volatility	46.42%
Risk-free rate	0.61%
Expected life (years)	1 year 11 months 1 day

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) $ in Millions	Apr. 14, 2015USD ($)	Mar. 28, 2014USD ($)	Mar. 10, 2014USD ($)	May. 31, 2014$ / MMBTU$ / bbl	Nov. 30, 2011MMBTU / d	Jun. 30, 2015USD ($)$ / MMBTU	Jun. 30, 2015USD ($)MMBTU / d$ / MMBTU$ / gal	Feb. 28, 2014USD ($)
Gas Gathering Agreement [Member] | Classic Operating And Classic Pipeline [Member]
Related Party Transaction [Line Items]
Pipeline transportation agreement expiration year					2,020
Pipeline transportation agreement extension					1 year
Natural gas produced per day | MMBTU / d					50,000
Fee per MMBTU | $ / MMBTU				0.30
Annual inflationary escalation				3.50%
Price per unit | $ / MMBTU				0.07
Agreement expired, date				Dec. 31, 2023
Gas Transportation Agreement [Member]
Related Party Transaction [Line Items]
Commodity usage charge | $ / MMBTU							0.04
Transportation Services Agreement [member]
Related Party Transaction [Line Items]
Commodity usage charge | $ / gal							0.04
Water Disposal Agreement [Member] | Classic Operating And Classic Pipeline [Member]
Related Party Transaction [Line Items]
Water disposal agreement period				3 years
Pipeline water disposal agreement extension				1 year
Water disposal fee per barrel | $ / bbl				1.10
NGPCIF [Member]
Related Party Transaction [Line Items]
Business acquisition common control purchase price								$ 63.4
Date of acquisition common control							Feb. 28, 2014
Cretic Energy Services, LLC [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses						$ 0.6	$ 1.1
BlueStone Natural Resources Holdings, LLC [Member]
Related Party Transaction [Line Items]
Total cash consideration			$ 1.2
Amount of gain over the book value			0.5
Gain recognized as contribution			$ 0.5
Natural Gas Partners [Member]
Related Party Transaction [Line Items]
Cash received		$ 3.3
WHR Management Company [Member]
Related Party Transaction [Line Items]
Management fee per month							$ 1
PennTex Operating [Member] | Gas Processing Agreement [Member]
Related Party Transaction [Line Items]
Primary term of gas processing agreement	15 years
Extension term of gas processing agreement	1 year
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Through November 30, 2019
Related Party Transaction [Line Items]
Payback demand quality per day | MMBTU / d							460,000
Payback demand fee | $ / MMBTU						0.03	0.03
PennTex Operating [Member] | Gas Gathering Agreement [Member] | July 1, 2016 | Minimum [Member]
Related Party Transaction [Line Items]
Minimum gas volume commitment | MMBTU / d							460,000
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Through June 30, 2026 [Member]
Related Party Transaction [Line Items]
Commodity usage charge | $ / MMBTU							0.05
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Through June 30, 2026 [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Minimum gas volume commitment | MMBTU / d							460,000
PennTex Operating [Member] | Gas Gathering Agreement [Member] | June 30, 2026, and thereafter
Related Party Transaction [Line Items]
Commodity usage charge | $ / MMBTU							0.05
PennTex Operating [Member] | Gas Gathering Agreement [Member] | June 30, 2026, and thereafter | Minimum [Member]
Related Party Transaction [Line Items]
Minimum gas volume commitment | MMBTU / d							345,000
PennTex Operating [Member] | First Plant [Member] | Gas Processing Agreement [Member]
Related Party Transaction [Line Items]
Minimum annual processing fee	$ 18.3
PennTex Operating [Member] | First Plant [Member] | Gas Gathering Agreement [Member] | Until Second Processing Plant Operational
Related Party Transaction [Line Items]
Commodity usage charge | $ / MMBTU							0.02
PennTex Operating [Member] | First Plant [Member] | Gas Gathering Agreement [Member] | Until Second Processing Plant Operational | Minimum [Member]
Related Party Transaction [Line Items]
Minimum gas volume commitment | MMBTU / d							115,000
PennTex Operating [Member] | Second Plant [Member] | Gas Processing Agreement [Member]
Related Party Transaction [Line Items]
Minimum annual processing fee	$ 55
PennTex Operating [Member] | Second Plant [Member] | Gas Gathering Agreement [Member] | Through November 30, 2019
Related Party Transaction [Line Items]
Commodity usage charge | $ / MMBTU							0.02
PennTex Operating [Member] | Second Plant [Member] | Gas Gathering Agreement [Member] | Through November 30, 2019 | Minimum [Member]
Related Party Transaction [Line Items]
Minimum gas volume commitment | MMBTU / d							345,000
PennTex NLA Holdings, LLC | Midstream Agreements
Related Party Transaction [Line Items]
Primary term of gas processing agreement	15 years
Extension term of gas processing agreement	1 year

Related Party Transactions - Sc

Related Party Transactions - Schedule of Net Assets Recorded (Detail) - WildHorse Resources, LLC [Member] - NGPCIF [Member] - Acquisitions [Member] $ in Thousands	Feb. 28, 2014USD ($)
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

Related Party Transactions - Bo

Related Party Transactions - Book Value of Assets Sold (Detail) - WHR Management Company [Member] - WildHorse Resources, LLC [Member] - Disposition [Member] $ in Thousands	Jun. 18, 2014USD ($)
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 - Additio

Business Segment Data - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2015Segment
Segment Reporting [Abstract]
Number of reportable business segments	2

Business Segment Data - Summary

Business Segment Data - Summary of Selected Business Segment Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total revenues	$ 176,743	$ 254,777	$ 356,584	$ 459,398
Adjusted EBITDA	165,631	162,944	338,817	286,740
Segment assets	4,480,303		4,480,303		$ 4,593,547
Total cash expenditures for additions to long-lived assets			344,891	467,835
Operating Segments [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	165,706	165,946	338,968	292,744
Operating Segments [Member] | MRD Segment [Member]
Segment Reporting Information [Line Items]
Total revenues	78,605	110,569	165,628	198,305
Adjusted EBITDA	82,831	81,471	169,661	146,223
Segment assets	1,553,851		1,553,851		1,413,768
Total cash expenditures for additions to long-lived assets			210,390	156,630
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Total revenues	98,138	144,208	190,956	261,093
Adjusted EBITDA	82,875	84,475	169,307	146,521
Segment assets	2,934,433		2,934,433		3,189,760
Total cash expenditures for additions to long-lived assets			134,501	311,205
Other, Adjustments & Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(75)	$ (3,002)	(151)	$ (6,004)
Segment assets	$ (7,981)		$ (7,981)		$ (9,981)

Business Segment Data - Schedul

Business Segment Data - Schedule of Calculation of Reportable Segment's Adjusted EBITDA (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Net income (loss)	$ (26,702)	$ (948,349)	$ 22,044	$ (939,977)
Interest expense, net	37,523	34,531	76,097	68,583
Loss on debt extinguishment		37,248		37,248
Income tax expense (benefit)	(23,768)	(11,536)	21,420	(11,436)
DD&A	82,113	73,780	173,911	131,459
Impairment of proved oil and natural gas properties			251,347
Accretion of asset retirement obligations	1,779	1,527	3,536	3,048
(Gain) loss on commodity derivative instruments	91,866	141,590	(161,783)	201,072
Cash settlements received (paid) on expired commodity derivative instruments	(91,890)	11,314	(184,763)	24,504
(Gain) loss on sale of properties	50	3,167	50	3,057
Transaction related costs	423	1,593	3,003	4,055
Compensation expense	20,638	944,657	34,689	946,975
Exploration costs	2,262	1,144	3,078	1,290
Provision for environmental remediation				2,852
Loss on settlement of AROs	1,328		1,328
Cash distributions from MEMP	75	3,002	151	6,004
Adjusted EBITDA	165,631	162,944	338,817	286,740
Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income (loss)	(140,562)	(1,063,387)	(252,849)	(1,089,889)
Interest expense, net	37,523	34,531	76,097	68,583
Loss on debt extinguishment		37,248		37,248
Income tax expense (benefit)	(23,768)	(11,536)	21,420	(11,436)
DD&A	82,113	73,780	173,911	131,459
Impairment of proved oil and natural gas properties			251,347
Accretion of asset retirement obligations	1,779	1,527	3,536	3,048
(Gain) loss on commodity derivative instruments	91,866	141,590	(161,783)	201,072
Cash settlements received (paid) on expired commodity derivative instruments	91,890	(11,314)	184,763	(24,504)
(Gain) loss on sale of properties	50	3,167	50	3,057
Transaction related costs	423	1,593	3,003	4,055
Compensation expense	20,638	944,657	34,689	946,975
Exploration costs	2,262	1,144	3,078	1,290
Provision for environmental remediation				2,852
Loss on settlement of AROs	1,328		1,328
Non-cash equity (income) loss from MEMP	89	9,944	227	12,930
Cash distributions from MEMP	75	3,002	151	6,004
Adjusted EBITDA	165,706	165,946	338,968	292,744
Operating Segments [Member] | MRD Segment [Member]
Segment Reporting Information [Line Items]
Net income (loss)	(26,703)	(951,747)	23,668	(945,357)
Interest expense, net	9,613	16,494	19,369	34,468
Loss on debt extinguishment		37,248		37,248
Income tax expense (benefit)	(24,644)	(11,846)	22,914	(11,821)
DD&A	35,827	30,814	76,359	55,943
Accretion of asset retirement obligations	93	127	216	257
(Gain) loss on commodity derivative instruments	30,463	3,244	(77,727)	15,960
Cash settlements received (paid) on expired commodity derivative instruments	37,539	(3,408)	70,288	(8,629)
(Gain) loss on sale of properties	50	3,167	50	3,057
Transaction related costs	126	500	1,407	1,068
Compensation expense	18,073	942,992	29,783	944,015
Exploration costs	2,230	940	2,956	1,080
Non-cash equity (income) loss from MEMP	89	9,944	227	12,930
Cash distributions from MEMP	75	3,002	151	6,004
Adjusted EBITDA	82,831	81,471	169,661	146,223
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Net income (loss)	(113,859)	(111,640)	(276,517)	(144,532)
Interest expense, net	27,910	18,037	56,728	34,115
Income tax expense (benefit)	876	310	(1,494)	385
DD&A	46,286	42,966	97,552	75,516
Impairment of proved oil and natural gas properties			251,347
Accretion of asset retirement obligations	1,686	1,400	3,320	2,791
(Gain) loss on commodity derivative instruments	61,403	138,346	(84,056)	185,112
Cash settlements received (paid) on expired commodity derivative instruments	54,351	(7,906)	114,475	(15,875)
Transaction related costs	297	1,093	1,596	2,987
Compensation expense	2,565	1,665	4,906	2,960
Exploration costs	32	204	122	210
Provision for environmental remediation				2,852
Loss on settlement of AROs	1,328		1,328
Adjusted EBITDA	$ 82,875	$ 84,475	$ 169,307	$ 146,521

Business Segment Data - Reconci

Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA	$ 165,631	$ 162,944	$ 338,817	$ 286,740
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net	(37,523)	(34,531)	(76,097)	(68,583)
Loss on extinguishment of debt		(37,248)		(37,248)
Income tax benefit (expense)	23,768	11,536	(21,420)	11,436
DD&A	(82,113)	(73,780)	(173,911)	(131,459)
Impairment of proved oil and natural gas properties			(251,347)
Accretion of asset retirement obligations	(1,779)	(1,527)	(3,536)	(3,048)
Gains (losses) on commodity derivative instruments	(91,866)	(141,590)	161,783	(201,072)
Cash settlements received (paid) on expired commodity derivative instruments	(91,890)	11,314	(184,763)	24,504
Gain (loss) on sale of properties	(50)	(3,167)	(50)	(3,057)
Transaction related costs	(423)	(1,593)	(3,003)	(4,055)
Incentive-based compensation expense	(20,638)	(944,657)	(34,689)	(946,975)
Exploration costs	(2,262)	(1,144)	(3,078)	(1,290)
Provision for environmental remediation				(2,852)
Loss on settlement of AROs	(1,328)		(1,328)
Cash distributions from MEMP	(75)	(3,002)	(151)	(6,004)
Net income (loss)	(140,473)	(1,053,443)	(252,622)	(1,076,959)
Reportable Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA	$ 165,706	$ 165,946	$ 338,968	$ 292,744

Business Segment Data - Sched79

Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Oil & natural gas sales	$ 175,826	$ 253,436	$ 354,798	$ 457,146
Other revenues	917	1,341	1,786	2,252
Total revenues	176,743	254,777	356,584	459,398
Costs and expenses:
Lease operating	48,742	32,321	94,442	65,676
Gathering, processing, and transportation	23,337	17,886	46,320	32,006
Gathering, processing, and transportation - affiliate (Note 13)	3,813		3,813
Pipeline operating	500	676	946	1,165
Exploration	2,262	1,144	3,078	1,290
Production and ad valorem taxes	9,198	10,999	18,628	19,583
Depreciation, depletion, and amortization	82,113	73,780	173,911	131,459
Impairment of proved oil and natural gas properties			251,347
Incentive unit compensation expense	16,116	942,817	26,340	943,840
General and administrative	24,700	22,126	52,187	39,865
Accretion of asset retirement obligations	1,779	1,527	3,536	3,048
(Gain) loss on commodity derivative instruments	91,866	141,590	(161,783)	201,072
(Gain) loss on sale of properties	50	3,167	50	3,057
Other, net	(943)		(943)	(12)
Total costs and expenses	303,533	1,248,033	511,872	1,442,049
Operating income (loss)	(126,790)	(993,256)	(155,288)	(982,651)
Other income (expense):
Interest expense, net	(37,523)	(34,531)	(76,097)	(68,583)
Other, net	72	56	183	87
Total other income (expense)	(37,451)	(71,723)	(75,914)	(105,744)
Loss on extinguishment of debt		(37,248)		(37,248)
Income (loss) before income taxes	(164,241)	(1,064,979)	(231,202)	(1,088,395)
Income tax benefit (expense)	23,768	11,536	(21,420)	11,436
Net income (loss)	(140,473)	(1,053,443)	(252,622)	(1,076,959)
Operating Segments [Member]
Costs and expenses:
Exploration	2,262	1,144	3,078	1,290
Depreciation, depletion, and amortization	82,113	73,780	173,911	131,459
Impairment of proved oil and natural gas properties			251,347
Accretion of asset retirement obligations	1,779	1,527	3,536	3,048
(Gain) loss on commodity derivative instruments	91,866	141,590	(161,783)	201,072
(Gain) loss on sale of properties	50	3,167	50	3,057
Other income (expense):
Interest expense, net	(37,523)	(34,531)	(76,097)	(68,583)
Loss on extinguishment of debt		(37,248)		(37,248)
Income tax benefit (expense)	23,768	11,536	(21,420)	11,436
Other, Adjustments & Eliminations [Member]
Other income (expense):
Earnings from equity investments	89	9,944	227	12,930
Total other income (expense)	89	9,944	227	12,930
Income (loss) before income taxes	89	9,944	227	12,930
Net income (loss)	89	9,944	227	12,930
MRD Segment [Member] | Operating Segments [Member]
Revenues:
Oil & natural gas sales	78,605	110,566	165,628	198,299
Other revenues		3		6
Total revenues	78,605	110,569	165,628	198,305
Costs and expenses:
Lease operating	3,854	4,793	9,076	8,028
Gathering, processing, and transportation	14,289	10,295	29,052	18,852
Gathering, processing, and transportation - affiliate (Note 13)	3,813		3,813
Exploration	2,230	940	2,956	1,080
Production and ad valorem taxes	3,140	3,581	5,915	6,154
Depreciation, depletion, and amortization	35,827	30,814	76,359	55,943
Incentive unit compensation expense	16,116	942,817	26,340	943,840
General and administrative	10,323	10,754	23,299	17,753
Accretion of asset retirement obligations	93	127	216	257
(Gain) loss on commodity derivative instruments	30,463	3,244	(77,727)	15,960
(Gain) loss on sale of properties	50	3,167	50	3,057
Total costs and expenses	120,198	1,010,532	99,349	1,070,924
Operating income (loss)	(41,593)	(899,963)	66,279	(872,619)
Other income (expense):
Interest expense, net	(9,613)	(16,494)	(19,369)	(34,468)
Earnings from equity investments	(89)	(9,944)	(227)	(12,930)
Other, net	(52)	56	(101)	87
Total other income (expense)	(9,754)	(63,630)	(19,697)	(84,559)
Loss on extinguishment of debt		(37,248)		(37,248)
Income (loss) before income taxes	(51,347)	(963,593)	46,582	(957,178)
Income tax benefit (expense)	24,644	11,846	(22,914)	11,821
Net income (loss)	(26,703)	(951,747)	23,668	(945,357)
MEMP [Member] | Operating Segments [Member]
Revenues:
Oil & natural gas sales	97,221	142,870	189,170	258,847
Other revenues	917	1,338	1,786	2,246
Total revenues	98,138	144,208	190,956	261,093
Costs and expenses:
Lease operating	44,888	27,528	85,366	57,648
Gathering, processing, and transportation	9,048	7,591	17,268	13,154
Pipeline operating	500	676	946	1,165
Exploration	32	204	122	210
Production and ad valorem taxes	6,058	7,418	12,713	13,429
Depreciation, depletion, and amortization	46,286	42,966	97,552	75,516
Impairment of proved oil and natural gas properties			251,347
General and administrative	14,377	11,372	28,888	22,112
Accretion of asset retirement obligations	1,686	1,400	3,320	2,791
(Gain) loss on commodity derivative instruments	61,403	138,346	(84,056)	185,112
Other, net	(943)		(943)	(12)
Total costs and expenses	183,335	237,501	412,523	371,125
Operating income (loss)	(85,197)	(93,293)	(221,567)	(110,032)
Other income (expense):
Interest expense, net	(27,910)	(18,037)	(56,728)	(34,115)
Other, net	124		284
Total other income (expense)	(27,786)	(18,037)	(56,444)	(34,115)
Income (loss) before income taxes	(112,983)	(111,330)	(278,011)	(144,147)
Income tax benefit (expense)	(876)	(310)	1,494	(385)
Net income (loss)	$ (113,859)	$ (111,640)	$ (276,517)	$ (144,532)

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Commitments And Contingencies (Additional Textual) [Abstract]
Environmental reserves liability	$ 1.1	$ 2.1
Maximum remaining obligation	$ 6.2

Commitments and Contingencies81

Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Held-to-maturity Securities [Abstract]
Less: Outside working interest owners share, Amortized Cost	$ (67,551)
Restricted investments	80,096	$ 77,361
BOEM platform abandonment [Member]
Held-to-maturity Securities [Abstract]
Restricted investments	72,452	$ 69,954
Money Market Funds [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$ 140,003

Commitments and Contingencies82

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) $ in Thousands	Jun. 30, 2015USD ($)
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

Condensed Consolidating Finan83

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 4,701	$ 5,958	$ 15,966	$ 77,721
Accounts receivable - trade	109,339	131,576
Short-term derivative instruments	290,045	340,056
Prepaid expenses and other current assets	29,882	28,027
Total current assets	433,967	505,617
Property and equipment, net	3,469,919	3,537,656
Long-term derivative instruments	461,844	435,369
Other long-term assets	114,573	114,905
Total assets	4,480,303	4,593,547
Current liabilities:
Accounts payable and accrued liabilities	274,633	224,772
Accounts payable - affiliates	5,184	624
Revenues payable	66,940	57,352
Short-term derivative instruments	2,986	3,289
Total current liabilities	349,743	286,037
Long-term debt	2,588,650	2,378,413
Asset retirement obligations	126,708	122,531
Long-term derivative instruments	674
Deferred tax liabilities	80,675	95,017
Other long-term liabilities	7,394	8,585
Total liabilities	3,153,844	2,890,583
Equity:
Equity	486,080	582,410
Noncontrolling interests	840,379	1,120,554
Total equity	1,326,459	1,702,964	816,652	858,132
Total liabilities and equity	4,480,303	4,593,547
Parent [Member]
Current assets:
Cash and cash equivalents	1,485	2,241	1,854
Accounts receivable - trade	4,776	5,995
Accounts receivable - affiliates	8,783	10,047
Short-term derivative instruments	117,401	131,471
Prepaid expenses and other current assets	4,670	5,833
Total current assets	137,115	155,587
Property and equipment, net	17,433	16,601
Long-term derivative instruments	145,086	123,567
Investments in subsidiaries	1,025,875	1,139,792
Other long-term assets	13,211	14,124
Total assets	1,338,720	1,449,671
Current liabilities:
Accounts payable and accrued liabilities	19,413	6,245
Accounts payable - affiliates	20
Revenues payable	142
Short-term derivative instruments	6
Total current liabilities	19,581	6,245
Long-term debt	765,000	783,000
Long-term derivative instruments	5
Deferred tax liabilities	60,660	69,431
Other long-term liabilities	7,394	8,585
Total liabilities	852,640	867,261
Equity:
Equity	486,080	582,410
Total equity	486,080	582,410
Total liabilities and equity	1,338,720	1,449,671
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	3,053	3,762	7,555	48,619
Accounts receivable - trade	48,370	44,952
Prepaid expenses and other current assets	10,322	7,993
Total current assets	61,745	56,707
Property and equipment, net	1,187,230	1,050,722
Other long-term assets		5,660
Total assets	1,248,975	1,113,089
Current liabilities:
Accounts payable and accrued liabilities	143,658	107,068
Accounts payable - affiliates	19,257	3,638
Revenues payable	35,080	27,242
Total current liabilities	197,995	137,948
Asset retirement obligations	7,743	9,830
Deferred tax liabilities	17,656
Total liabilities	223,394	147,778
Equity:
Equity	1,025,581	965,311
Total equity	1,025,581	965,311
Total liabilities and equity	1,248,975	1,113,089
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	163	970	$ 6,557	$ 29,102
Accounts receivable - trade	62,311	83,346
Accounts receivable - affiliates	1,069	28
Short-term derivative instruments	172,644	208,585
Prepaid expenses and other current assets	14,890	14,201
Total current assets	251,077	307,130
Property and equipment, net	2,265,256	2,470,333
Long-term derivative instruments	316,758	311,802
Other long-term assets	101,362	100,521
Total assets	2,934,453	3,189,786
Current liabilities:
Accounts payable and accrued liabilities	112,259	114,584
Accounts payable - affiliates	618	6,409
Revenues payable	31,718	30,110
Short-term derivative instruments	2,980	3,289
Total current liabilities	147,575	154,392
Long-term debt	1,823,650	1,595,413
Asset retirement obligations	118,965	112,701
Long-term derivative instruments	669
Deferred tax liabilities	2,359	30,986
Total liabilities	2,093,218	1,893,492
Equity:
Equity	835,451	1,290,734
Noncontrolling interests	5,784	5,560
Total equity	841,235	1,296,294
Total liabilities and equity	2,934,453	3,189,786
Eliminations [Member]
Current assets:
Cash and cash equivalents		(1,015)
Accounts receivable - trade	(6,118)	(2,717)
Accounts receivable - affiliates	(9,852)	(10,075)
Total current assets	(15,970)	(13,807)
Investments in subsidiaries	(1,025,875)	(1,139,792)
Other long-term assets		(5,400)
Total assets	(1,041,845)	(1,158,999)
Current liabilities:
Accounts payable and accrued liabilities	(697)	(3,125)
Accounts payable - affiliates	(14,711)	(9,423)
Total current liabilities	(15,408)	(12,548)
Deferred tax liabilities		(5,400)
Total liabilities	(15,408)	(17,948)
Equity:
Equity	(1,861,032)	(2,256,045)
Noncontrolling interests	834,595	1,114,994
Total equity	(1,026,437)	(1,141,051)
Total liabilities and equity	$ (1,041,845)	$ (1,158,999)

Condensed Consolidating Finan84

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Oil & natural gas sales	$ 175,826	$ 253,436	$ 354,798	$ 457,146
Other income	917	1,341	1,786	2,252
Total revenues	176,743	254,777	356,584	459,398
Costs and expenses:
Lease operating	48,742	32,321	94,442	65,676
Gathering, processing, and transportation	23,337	17,886	46,320	32,006
Gathering, processing and transportation - affiliate	3,813		3,813
Pipeline operating	500	676	946	1,165
Exploration	2,262	1,144	3,078	1,290
Production and ad valorem taxes	9,198	10,999	18,628	19,583
Depreciation, depletion, and amortization	82,113	73,780	173,911	131,459
Impairment of proved oil and natural gas properties			251,347
Incentive unit compensation expense	16,116	942,817	26,340	943,840
General and administrative	24,700	22,126	52,187	39,865
Accretion of asset retirement obligations	1,779	1,527	3,536	3,048
(Gain) loss on commodity derivatives	91,866	141,590	(161,783)	201,072
(Gain) loss on sale of properties	50	3,167	50	3,057
Other, net	(943)		(943)	(12)
Total costs and expenses	303,533	1,248,033	511,872	1,442,049
Operating income (loss)	(126,790)	(993,256)	(155,288)	(982,651)
Other income (expense):
Interest expense, net	(37,523)	(34,531)	(76,097)	(68,583)
Debt extinguishment costs		(37,248)		(37,248)
Other, net	72	56	183	87
Total other income (expense)	(37,451)	(71,723)	(75,914)	(105,744)
Income (loss) before income taxes	(164,241)	(1,064,979)	(231,202)	(1,088,395)
Income tax benefit (expense)	23,768	11,536	(21,420)	11,436
Net income (loss)	(140,473)	(1,053,443)	(252,622)	(1,076,959)
Net income (loss) attributable to noncontrolling interest	(113,771)	(105,094)	(274,666)	(136,982)
Net income (loss) attributable to Memorial Resource Development Corp.	(26,702)	(948,349)	22,044	(939,977)
Parent [Member]
Costs and expenses:
Depreciation, depletion, and amortization	1,084		2,052
Incentive unit compensation expense	16,116	111,757	26,340	111,757
General and administrative	10,404	175	21,329	175
(Gain) loss on commodity derivatives	30,463	(3,435)	(77,727)	(3,435)
Total costs and expenses	58,067	108,497	(28,006)	108,497
Operating income (loss)	(58,067)	(108,497)	28,006	(108,497)
Other income (expense):
Interest expense, net	(9,526)	(976)	(19,282)	(976)
Debt extinguishment costs		(23,562)		(23,562)
Equity earnings from subsidiaries	7,469	(836,746)	17,343	(836,746)
Total other income (expense)	(2,057)	(861,284)	(1,939)	(861,284)
Income (loss) before income taxes	(60,124)	(969,781)	26,067	(969,781)
Income tax benefit (expense)	33,422	8,074	(4,023)	8,074
Net income (loss)	(26,702)	(961,707)	22,044	(961,707)
Net income (loss) attributable to Memorial Resource Development Corp.	(26,702)	(961,707)	22,044	(961,707)
Guarantor Subsidiaries [Member]
Revenues:
Oil & natural gas sales	78,605	110,566	165,628	198,299
Other income		3		6
Total revenues	78,605	110,569	165,628	198,305
Costs and expenses:
Lease operating	3,854	4,793	9,076	8,028
Gathering, processing, and transportation	14,289	10,295	29,052	18,852
Gathering, processing and transportation - affiliate	3,813		3,813
Exploration	2,230	940	2,956	1,080
Production and ad valorem taxes	3,140	3,581	5,915	6,154
Depreciation, depletion, and amortization	34,743	30,814	74,307	55,943
Incentive unit compensation expense		831,060		831,060
General and administrative	(81)	10,579	1,970	17,561
Accretion of asset retirement obligations	93	127	216	257
(Gain) loss on commodity derivatives		6,679		19,395
(Gain) loss on sale of properties	50	3,167	50	3,167
Total costs and expenses	62,131	902,035	127,355	961,497
Operating income (loss)	16,474	(791,466)	38,273	(763,192)
Other income (expense):
Interest expense, net	(87)	(15,518)	(87)	(33,492)
Debt extinguishment costs		(13,686)		(13,686)
Equity earnings from subsidiaries		3,260
Other, net	(52)	56	(101)	87
Total other income (expense)	(139)	(25,888)	(188)	(47,091)
Income (loss) before income taxes	16,335	(817,354)	38,085	(810,283)
Income tax benefit (expense)	(8,778)	3,772	(18,891)	3,747
Net income (loss)	7,557	(813,582)	19,194	(806,536)
Net income (loss) attributable to Memorial Resource Development Corp.	7,557	(813,582)	19,194	(806,536)
Non-Guarantor Subsidiaries [Member]
Revenues:
Oil & natural gas sales	97,221	142,870	189,170	258,847
Other income	917	1,338	1,786	2,246
Total revenues	98,138	144,208	190,956	261,093
Costs and expenses:
Lease operating	44,888	27,528	85,366	57,648
Gathering, processing, and transportation	9,048	7,591	17,268	13,154
Pipeline operating	500	676	946	1,165
Exploration	32	204	122	210
Production and ad valorem taxes	6,058	7,418	12,713	13,429
Depreciation, depletion, and amortization	46,286	42,966	97,552	75,516
Impairment of proved oil and natural gas properties			251,347
Incentive unit compensation expense				1,023
General and administrative	14,377	11,372	28,888	22,129
Accretion of asset retirement obligations	1,686	1,400	3,320	2,791
(Gain) loss on commodity derivatives	61,403	138,346	(84,056)	185,112
(Gain) loss on sale of properties				(110)
Other, net	(943)		(943)	(12)
Total costs and expenses	183,335	237,501	412,523	372,055
Operating income (loss)	(85,197)	(93,293)	(221,567)	(110,962)
Other income (expense):
Interest expense, net	(27,910)	(18,037)	(56,728)	(34,115)
Other, net	124		284
Total other income (expense)	(27,786)	(18,037)	(56,444)	(34,115)
Income (loss) before income taxes	(112,983)	(111,330)	(278,011)	(145,077)
Income tax benefit (expense)	(876)	(310)	1,494	(385)
Net income (loss)	(113,859)	(111,640)	(276,517)	(145,462)
Net income (loss) attributable to noncontrolling interest	65	(12)	224	43
Net income (loss) attributable to Memorial Resource Development Corp.	(113,924)	(111,628)	(276,741)	(145,505)
Eliminations [Member]
Other income (expense):
Equity earnings from subsidiaries	(7,469)	833,486	(17,343)	836,746
Total other income (expense)	(7,469)	833,486	(17,343)	836,746
Income (loss) before income taxes	(7,469)	833,486	(17,343)	836,746
Net income (loss)	(7,469)	833,486	(17,343)	836,746
Net income (loss) attributable to noncontrolling interest	(113,836)	(105,082)	(274,890)	(137,025)
Net income (loss) attributable to Memorial Resource Development Corp.	$ 106,367	$ 938,568	$ 257,547	$ 973,771

Condensed Consolidating Finan85

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$ 301,787	$ 177,747
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(6,095)	(173,000)
Acquisition post-closing adjustment receipts	9,570
Additions to oil and gas properties	(335,426)	(293,567)
Additions to other property and equipment	(3,370)	(1,268)
Additions to restricted investments	(2,735)	(2,121)
Change in restricted cash		49,946
Deposits for property acquisitions		(70,125)
Proceeds from the sale of oil and gas properties	13,612	6,700
Other		(301)
Net cash used in investing activities	(324,444)	(483,736)
Cash flows from financing activities:
Advances on revolving credit facilities	433,000	1,548,800
Payments on revolving credit facilities	(221,000)	(776,900)
Termination of second lien credit facility		(328,282)
Repayment of senior notes	(2,914)	(351,808)
Deferred financing costs	(235)	(6,234)
Proceeds from MRD initial public offering		408,500
Costs incurred in conjunction with initial public offering		(26,875)
Purchase of additional interests in consolidated subsidiaries		(3,292)
Distributions to noncontrolling interests	(92,477)	(61,844)
Other		270
Repurchases of equity	(94,974)
Net cash provided by financing activities	21,400	244,234
Net change in cash and cash equivalents	(1,257)	(61,755)
Cash and cash equivalents, beginning of period	5,958	77,721
Cash and cash equivalents, end of period	4,701	15,966
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to affiliates		(59,803)
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties		1,165
Distribution to NGP affiliates related to purchase of assets		(66,693)
Distribution to NGP affiliates related to sale of assets, net of cash received		(32,770)
Parent [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities	37,045	(5,169)
Cash flows from investing activities:
Additions to other property and equipment	(2,871)	(263)
Investments in subsidiaries	(44,280)	(616,353)
Distributions from subsidiaries	78,547
Net cash used in investing activities	31,396	(616,616)
Cash flows from financing activities:
Advances on revolving credit facilities	181,000	1,004,000
Payments on revolving credit facilities	(199,000)	(385,000)
Repayment of senior notes		(351,808)
Deferred financing costs		(4,679)
Costs incurred in conjunction with initial public offering		(26,875)
Purchase of additional interests in consolidated subsidiaries		(3,292)
Repurchases of equity	(51,197)
Net cash provided by financing activities	(69,197)	623,639
Net change in cash and cash equivalents	(756)	1,854
Cash and cash equivalents, beginning of period	2,241
Cash and cash equivalents, end of period	1,485	1,854
Parent [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to affiliates		(17,207)
Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities	152,009	73,471
Cash flows from investing activities:
Additions to oil and gas properties	(207,103)	(155,362)
Additions to other property and equipment	(416)	(1,005)
Investments in subsidiaries		(3,304)
Distributions from subsidiaries		48,596
Change in restricted cash		49,946
Proceeds from the sale of oil and gas properties	13,612
Net cash used in investing activities	(193,907)	(61,129)
Cash flows from financing activities:
Advances on revolving credit facilities		126,800
Payments on revolving credit facilities		(329,900)
Termination of second lien credit facility		(328,282)
Deferred financing costs		(965)
Capital contributions	41,189	614,350
Other		270
Net cash provided by financing activities	41,189	(53,406)
Net change in cash and cash equivalents	(709)	(41,064)
Cash and cash equivalents, beginning of period	3,762	48,619
Cash and cash equivalents, end of period	3,053	7,555
Guarantor Subsidiaries [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to affiliates		(39,520)
Guarantor Subsidiaries [Member] | Natural Gas Partners [Member]
Cash flows from financing activities:
Distribution to NGP affiliates related to purchase of assets		(63,389)
Distribution to NGP affiliates related to sale of assets, net of cash received		(32,770)
Non-Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities	111,718	109,445
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(6,095)	(173,000)
Acquisition post-closing adjustment receipts	9,570
Additions to oil and gas properties	(128,323)	(138,205)
Additions to other property and equipment	(83)
Additions to restricted investments	(2,735)	(2,121)
Deposits for property acquisitions		(70,125)
Proceeds from the sale of oil and gas properties		6,700
Other		(301)
Net cash used in investing activities	(127,666)	(377,052)
Cash flows from financing activities:
Advances on revolving credit facilities	252,000	418,000
Payments on revolving credit facilities	(22,000)	(62,000)
Repayment of senior notes	(2,914)
Deferred financing costs	(235)	(590)
Capital contributions	3,091	5,307
Distribution to partners	(92,628)
Repurchases of equity	(43,777)
Distribution to equity owners		(110,440)
Net cash provided by financing activities	15,141	245,062
Net change in cash and cash equivalents	(807)	(22,545)
Cash and cash equivalents, beginning of period	970	29,102
Cash and cash equivalents, end of period	163	6,557
Non-Guarantor Subsidiaries [Member] | MRD Corp. [Member]
Cash flows from financing activities:
Distributions to affiliates	(78,396)
Non-Guarantor Subsidiaries [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to affiliates		(3,076)
Non-Guarantor Subsidiaries [Member] | Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties		1,165
Distribution to NGP affiliates related to purchase of assets		(3,304)
Eliminations [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities	1,015
Cash flows from investing activities:
Investments in subsidiaries	44,280	619,657
Distributions from subsidiaries	(78,547)	(48,596)
Net cash used in investing activities	(34,267)	571,061
Cash flows from financing activities:
Capital contributions	(44,280)	(619,657)
Distribution to partners	92,628
Distributions to noncontrolling interests	(92,477)	(61,844)
Distribution to equity owners		110,440
Net cash provided by financing activities	34,267	(571,061)
Net change in cash and cash equivalents	1,015
Cash and cash equivalents, beginning of period	(1,015)
Eliminations [Member] | MRD Corp. [Member]
Cash flows from financing activities:
Distributions to affiliates	78,396
MRD Segment [Member]
Cash flows from financing activities:
Proceeds from MRD initial public offering		408,500
Repurchases of equity	$ (51,197)
MRD Segment [Member] | Parent [Member]
Cash flows from financing activities:
Proceeds from MRD initial public offering		$ 408,500