10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–Q

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

For the quarterly period ended June 30, 2015

OR

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

For the transition period from to .

Commission File Number: 001-36490

MEMORIAL RESOURCE DEVELOPMENT CORP.

(Exact name of registrant as specified in its charter)

Delaware	46-4710769
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
500 Dallas Street, Suite 1800, Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 588-8300

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ  No ¨

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

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

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

As of July 31, 2015, the registrant had 191,532,159 shares of common stock, $.01 par value, outstanding

MemORIAL RESOURCE DEVELOPMENT CORP.

Table of Contents

		Page
	Glossary of Oil and Natural Gas Terms	ii
	Names of Entities	5
	Cautionary Note Regarding Forward-Looking Statements	6
	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	8
	Unaudited Condensed Statements of Consolidated and Combined Operations for the Three and Six Months Ended June 30, 2015 and 2014	9
	Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Six Months Ended June 30, 2015 and 2014	10
	Unaudited Condensed Statements of Consolidated and Combined Equity for the Six Months Ended June 30, 2015 and 2014	11
	Notes to Unaudited Condensed Consolidated and Combined Financial Statements
	Note 1 – Background, Organization and Basis of Presentation	12
	Note 2 – Summary of Significant Accounting Policies	13
	Note 3 – Acquisitions and Divestitures	14
	Note 4 – Fair Value Measurements of Financial Instruments	15
	Note 5 – Risk Management and Derivative Instruments	17
	Note 6 – Asset Retirement Obligations	21
	Note 7 – Restricted Investments	22
	Note 8 – Long Term Debt	22
	Note 9 – Stockholders’ Equity and Noncontrolling Interests	23
	Note 10 – Earnings per Share	24
	Note 11 – Long-Term Incentive Plans	24
	Note 12 – Incentive Units	25
	Note 13 – Related Party Transactions	26
	Note 14 – Business Segment Data	28
	Note 15 – Commitments and Contingencies	35
	Note 16 – Condensed Consolidating Financial Information	36
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	57
Item 4.	Controls and Procedures	58
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	59
Item 1A.	Risk Factors	59
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60
Item 3.	Defaults Upon Senior Securities	60
Item 4.	Mine Safety Disclosures	60
Item 5.	Other Information	60
Item 6.	Exhibits	60
Signatures		61

i

GLOSSARY OF OIL AND NATURAL GAS TERMS

Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcfe: One billion cubic feet of natural gas equivalent.

BOEM: Bureau of Ocean Energy Management.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

COPAS: Council of Petroleum Accountants Societies.

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Field: An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

MBbl: One thousand Bbls.

Mcf: One thousand cubic feet of natural gas.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

Net Production: Production that is owned by us less royalties and production due others.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Play: A geographic area with hydrocarbon potential.

Possible Reserves: Reserves that are less certain to be recovered than probable reserves.

Probable Reserves: Reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.

ii

Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PUDs: Proved Undeveloped Reserves.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to reflect property acquisitions and dispositions.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

iii

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the United States Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a corporation, we are subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

WTI: West Texas Intermediate.

iv

NAMES OF ENTITIES

As used in this Form 10-Q, unless we indicate otherwise:

· Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” or like terms are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries;

· “MRD LLC” refers to Memorial Resource Development LLC, which has historically owned our predecessor’s business and which was merged into MRD Operating LLC (“MRD Operating”), our subsidiary, subsequent to our initial public offering;

· “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires;

· “MEMP GP” refers to Memorial Production Partners GP LLC, the general partner of the Partnership;

· “our predecessor” refers collectively to: (i) MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P. (“Classic”), Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”), Black Diamond Minerals, LLC (“Black Diamond”), Beta Operating Company, LLC (“Beta Operating”), MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, LLC (“WildHorse Resources”), Tanos Energy, LLC (“Tanos”), and each of their respective subsidiaries, including MEMP and its subsidiaries and (ii) the previous owners as defined below;

· “the Funds” refers 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;

· “MRD Holdco” refers to MRD Holdco LLC, a holding company controlled by the Funds that, together with a group, owns a majority of our common stock;

· “the previous owners” for accounting and financial reporting purposes refers to the carved-out net profits interest created from working interests in certain oil and natural gas properties that WildHorse Resources originally acquired in 2010 from third parties and immediately sold to NGP Income Co-Investment Fund II, L.P. (“NGPCIF”), a NGP controlled entity, and subsequently reacquired from NGPCIF on February 28, 2014; and

· “NGP” refers to Natural Gas Partners, a family of private equity funds organized to make direct equity investments in the energy industry, including the Funds.

· “Classic Pipeline” refers to Classic Pipeline & Gathering, LLC, a subsidiary of MRD Holdco that owns certain immaterial midstream assets in Texas.

5

CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This quarterly report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, may include statements about our:

· business strategy;

· estimated reserves and the present value thereof;

· technology;

· cash flows and liquidity;

· financial strategy, budget, projections and future operating results;

· realized commodity prices;

· timing and amount of future production of reserves;

· ability to procure drilling and production equipment;

· ability to procure oilfield labor;

· the amount, nature and timing of capital expenditures, including future development costs;

· ability to access, and the terms of, capital;

· drilling of wells, including statements made about future horizontal drilling activities;

· competition;

· expectations regarding government regulations;

· marketing of production and the availability of pipeline capacity;

· exploitation or property acquisitions;

· costs of exploiting and developing our properties and conducting other operations;

· expectations regarding general economic and business conditions;

· competition in the oil and natural gas industry;

· effectiveness of our risk management activities;

· environmental and other liabilities;

· counterparty credit risk;

· expectations regarding taxation of the oil and natural gas industry;

· expectations regarding developments in other countries that produce oil and natural gas;

· future operating results;

· plans and objectives of management; and

· plans, objectives, expectations and intentions contained in this report that are not historical.

6

These types of statements, other than statements of historical fact included in this quarterly report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “forecast,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or include other “forward-looking” information. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

· variations in the market demand for, and prices of, oil, natural gas and NGLs;

· uncertainties about our estimated reserves;

· the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility;

· general economic and business conditions;

· risks associated with negative developments in the capital markets;

· failure to realize expected value creation from property acquisitions;

· uncertainties about our ability to replace reserves and economically develop our current reserves;

· drilling results;

· potential financial losses or earnings reductions from our commodity price risk management programs;

· adoption or potential adoption of new governmental regulations;

· the availability of capital on economic terms to fund our capital expenditures and acquisitions;

· risks associated with our substantial indebtedness; and

· our ability to satisfy future cash obligations and environmental costs.

The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this quarterly report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2014 (our “2014 Form 10-K) and “Part II—Item 1A. Risk Factors” appearing within this quarterly report and elsewhere in this quarterly report. All forward-looking statements speak only as of the date of this quarterly report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

7

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

	June 30,			December 31,
	2015			2014
ASSETS
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
LIABILITIES AND EQUITY
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
Long-term debt—MRD Segment		765,000			783,000
Long-term debt—MEMP Segment		1,823,650			1,595,413
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)
Equity:
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

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

8

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per share amounts)

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2015			2014			2015			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	)	$	(5.00	)	$	0.12		$	(5.00	)
Diluted	$	(0.14	)	$	(5.00	)	$	0.12		$	(5.00	)
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

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

9

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

 (In thousands)

	Six Months Ended
	June 30,
	2015			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	)
Contributions from NGP affiliates related to sale of assets		—			1,165
Distribution to MRD Holdco		—			(59,803	)
Distributions to noncontrolling interests		(92,477	)		(61,844	)
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 Equity repurchases		(51,197	)		—
MEMP Equity repurchases		(43,777	)		—
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

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

10

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(In thousands)

	Stockholders' Equity									Members' Equity
	Common stock			Additional paid in capital			Accumulated earnings (deficit)			Members			Previous Owners			Noncontrolling Interest			Total
Balance, January 1, 2014	$	—		$	—		$	—		$	237,186		$	40,331		$	580,615		$	858,132
Net income (loss)		—			—			(961,707	)		20,305			1,425			(136,982	)		(1,076,959	)
Issuance of shares in connection with restructuring transactions		1,710			913,152			—			—			—			—			914,862
Issuance of shares in connection with initial public offering		215			380,453			—			—			—			—			380,668
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		—			—			—			45,059			(41,756	)		—			3,303
Purchase of noncontrolling interest		—			(2,881	)		—			—			—			(411	)		(3,292	)
Distribution of net assets to  MRD Holdco		—			—			—			(123,078	)		—			29,994			(93,084	)
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 equity awards		—			174			—			—			—			2,960			3,134
Other		—			384			—			(154	)		—			(345	)		(115	)
Balance, June 30 2014	$	1,936		$	1,359,777		$	(961,707	)	$	—		$	—		$	416,646		$	816,652
Balance, January 1, 2015	$	1,935		$	1,367,346		$	(786,871	)	$	—		$	—		$	1,120,554		$	1,702,964
Net income (loss)		—			—			22,044			—			—			(274,666	)		(252,622	)
Share repurchase		(28	)		—			(47,757	)		—			—			—			(47,785	)
Restricted stock awards		9			(9	)		—			—			—			—			—
Amortization of restricted stock awards		—			3,443			—			—			—			—			3,443
Contribution related to MRD Holdco incentive unit compensation expense (Note 12)		—			26,340			—			—			—			—			26,340
Net equity deemed contribution (distribution) related to MEMP property exchange (Note 1)		—			(127,149	)		—			—			—			127,149			—
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
MEMP common units repurchased		—			—			—			—			—			(45,117	)		(45,117	)
MRD restricted shares repurchased		(1	)		—			(1,195	)		—			—			—			(1,196	)
Other		—			(47	)		—			—			—			30			(17	)
Balance, June 30, 2015	$	1,915		$	1,297,944		$	(813,779	)	$	—		$	—		$	840,379		$	1,326,459

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

11

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

12

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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 to include a new note containing condensed consolidating financial information.

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. 

13

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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”).

14

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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.

15

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

16

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

17

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

18

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

19

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

20

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

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

21

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

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

22

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

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.

23

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 programthrough 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.

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.

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.

24

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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.

25

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

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 – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

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

26

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

27

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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.

28

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

29

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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

30

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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	)

31

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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	)

32

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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	)

33

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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	)

34

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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	)

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

35

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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

36

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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

37

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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	)

38

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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	)

39

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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

40

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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	)

41

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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

42

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	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

43

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Management’s Discussion and Analysis of Financial Condition and Results ofOperations should be read in conjunction with the unaudited condensed financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our 2014 Form 10-K filed with the SEC on March 18, 2015, our Recast Form 8-K filed with the SEC on July 8, 2015 and any supplements thereto. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.

Overview

We are an independent natural gas and oil company focused on the acquisition, exploration and development of natural gas and oil properties with a majority of our activity in the Terryville Complex of North Louisiana, where we are targeting overpressured, liquids-rich natural gas opportunities in multiple zones in the Cotton Valley formation. We are focused on creating shareholder value primarily through the development of our sizeable horizontal inventory.

We have two reportable segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties:

· 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.

Because we control MEMP through our ownership of its general partner, its business and operations are consolidated with ours for financial reporting purposes, even though we do not own any of its common units. As a result, our financial statements and notes thereto included under “Item 1. Financial Statements” consolidate MEMP’s business and assets with ours; however, the MEMP Segment’s debt is nonrecourse to the Company. Except where expressly noted to the contrary, the following discussion of our business, operations and assets and the use of the terms “we”, “our” and “us” excludes MEMP’s business, operations and assets.

As discussed under Note 2 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements,” the FASB issued an accounting standards update in February 2015 to improve consolidation guidance for certain types of legal entities. The guidance, among other things, modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities and eliminates the presumption that a general partner should consolidate a limited partnership. 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.

Recent Developments

Property Swap

In February 2015, we and MEMP completed a transaction (the “Property Swap”) in which we exchanged certain of our oil and gas properties in East Texas and West Louisiana for MEMP’s North Louisiana oil and gas properties and approximately $78.4 million in cash. Terms of the transaction were approved by our board of directors and by its conflicts committee, which is comprised entirely of independent directors. The transaction had an effective date of January 1, 2015.

Amendment to MRD Revolving Credit Facility and Borrowing Base Reaffirmation

In April 2015, we entered into a fourth amendment to our revolving credit facility to, among other things, add new lenders and permit the repurchase of up to $50.0 million of our common stock. In connection therewith, the lenders under our revolving credit facility reaffirmed the borrowing base under our revolving credit facility at $725.0 million, to remain at such level until the next scheduled redetermination, the next interim redetermination or other adjustment to the borrowing base, whichever occurs first.

MEMP Borrowing Base Redetermination

In March 2015, in connection with the semi-annual borrowing base redetermination by lenders under MEMP’s revolving credit facility, the borrowing base under its revolving credit facility decreased from $1.44 billion to $1.3 billion. This reduction in the borrowing base was primarily the result of the deterioration of commodity prices in the oil and natural gas industry. The new borrowing base became effective on March 24, 2015.

44

MEMP Conversion of Subordinated Units

In February 2015, the subordination period for the 5,360,912 MEMP subordinated units ended. All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period and were then sold by MRD Holdco during the second quarter of 2015.

MEMP Repurchase Program

In December 2014, the board of directors of MEMP’s general partner authorized the repurchase of up to $150.0 million of MEMP’s common units (“MEMP Repurchase Program”).  In 2015, MEMP repurchased $52.8 million of common units through July 31, 2015, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program.

Business Segments

Our reportable business segments are organized in a manner that reflects how management manages those business activities. We evaluate segment performance based on Adjusted EBITDA. For additional information regarding our reportable business segments and Adjusted EBITDA, see Note 14 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

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 for comparability purposes.

The MRD Segment is focused on the acquisition, exploration, and development of natural gas and oil properties primarily in the Cotton Valley formation in North Louisiana. These properties consist primarily of assets with extensive production histories, high drilling success rates, and significant horizontal redevelopment potential. The MRD Segment is focused on maintaining and growing its production and cash flow primarily through the development of its sizeable inventory. The MRD Segment, prior to our initial public offering, included BlueStone, MRD Royalty, MRD Midstream, Golden Energy Partners LLC (“Golden Energy”), Classic Pipeline, the MEMP subordinated units and cash held in a debt service reserve account that had been established when the 10.00%/10.75% Senior PIK toggle notes due 2018 (the “PIK notes”) were issued by MRD LLC in December 2013.

The MEMP Segment is engaged in the acquisition, exploitation, development and production of oil and natural gas properties, with assets consisting primarily of producing oil and natural gas properties that are located in Texas, Louisiana, Colorado, Wyoming, and New Mexico and offshore Southern California. Most of the MEMP Segment’s properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. The MEMP Segment is focused on generating stable cash flows to allow MEMP to make quarterly cash distributions to its unitholders and, over time, to increase those quarterly cash distributions.

Sources of Revenues

Both our and MEMP’s revenues are derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from natural gas during processing. Production revenues are derived entirely from the continental United States. Natural gas, NGL and oil prices are inherently volatile and are influenced by many factors outside our control. In order to reduce the impact of fluctuations in natural gas and oil prices on revenues, or to protect the economics of property acquisitions, both we and MEMP intend to periodically enter into derivative contracts with respect to a significant portion of estimated natural gas and oil production through various transactions that fix the future prices received. At the end of each period the fair value of these commodity derivative instruments are estimated and, because hedge accounting is not elected, the changes in the fair value of unsettled commodity derivative instruments are recognized in earnings at the end of each accounting period.

Principal Components of Cost Structure

· Lease operating expenses. These are the day to day costs incurred to maintain production of our natural gas, NGLs and oil. Such costs include utilities, direct labor, water injection and disposal, materials and supplies, compression, repairs and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services.

· Gathering, processing and transportation. These are costs incurred to deliver production of our natural gas, NGLs and oil to the market. Cost levels of these expenses can vary based on the volume of natural gas, NGLs and oil production.

· Production and ad valorem taxes. These consist of severance and ad valorem taxes. Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. Both MRD and MEMP take full advantage of all credits and exemptions in the various taxing jurisdictions where they operate. Ad valorem taxes are generally tied to the valuation of the oil and natural properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

· Exploration expense. These are geological and geophysical costs and include seismic costs, costs of unsuccessful exploratory dry holes and unsuccessful leasing efforts.

45

· Impairment of proved properties. Proved properties are impaired whenever the carrying value of the properties exceed their estimated undiscounted future cash flows.

· Depreciation, depletion and amortization. Depreciation, depletion and amortization, or DD&A, includes the systematic expensing of the capitalized costs incurred to acquire, exploit and develop natural gas and oil properties. As a “successful efforts” company, all costs associated with acquisition and development efforts and all successful exploration efforts are capitalized, and these costs are depleted using the units of production method.

· Incentive unit compensation expense. For more information regarding compensation expense recognized associated with incentive units, see Note 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

· General and administrative expense. These costs include overhead, including payroll and benefits for employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expense associated with certain long-term incentive-based plans, franchise taxes, audit and other professional fees, and legal compliance expenses.

· Interest expense. Both MRD and MEMP finance a portion of their working capital requirements and acquisitions with borrowings under revolving credit facilities and senior note issuances. As a result, both MRD and MEMP incur substantial interest expense that is affected by both fluctuations in interest rates and financing decisions. We expect to continue to incur significant interest expense as we continue to grow.

· Income tax expense. We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes.

Critical Accounting Policies and 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 value of incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis.

When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Results of Operations

MRD Segment

The MRD Segment’s consolidated results of operations for the three and six months ended June 30, 2015 and 2014 presented below have been derived from our consolidated financial statements. The comparability of the results of operations among the periods presented is impacted by the distribution by MRD LLC of the following to MRD Holdco prior to our initial public offering: (i) BlueStone, which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owned certain immaterial leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owned an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline and (ii) 5,360,912 subordinated units of MEMP (which converted to common units on February 13, 2015 and were then sold by MRD Holdco during the second quarter of 2015).

Segment financial information has been retrospectively revised for material common control transactions between the MEMP Segment and the MRD Segment for comparability purposes, which includes 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.

46

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)
Oil & natural gas sales	$	78,605		$	110,566		$	165,628		$	198,299
Lease operating		3,854			4,793			9,076			8,028
Gathering, processing, and transportation (including affiliate)		18,102			10,295			32,865			18,852
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
(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
Interest expense, net		(9,613	)		(16,494	)		(19,369	)		(34,468	)
Loss on extinguishment of debt		—			(37,248	)		—			(37,248	)
Income tax benefit (expense)		24,644			11,846			(22,914	)		11,821
Net income (loss)		(26,703	)		(951,747	)		23,668			(945,357	)
Natural gas and oil revenue:
Oil sales	$	16,752		$	23,304		$	30,145		$	44,399
NGL sales		14,042			22,353			25,496			41,713
Natural gas sales		47,811			64,909			109,987			112,187
Total natural gas and oil revenue	$	78,605		$	110,566		$	165,628		$	198,299
Production Volumes:
Oil (MBbls)		315			233			598			455
NGLs (MBbls)		669			418			1,172			861
Natural gas (MMcf)		18,469			13,670			38,664			22,972
Total (MMcfe)		24,373			17,576			49,283			30,866
Average net production (MMcfe/d)		267.8			193.1		$	272.3		$	170.5
Average sales price:
Oil (per Bbl)	$	53.18		$	100.02		$	50.41		$	97.58
NGL (per Bbl)		20.99			53.48			21.75			48.45
Natural gas (per Mcf)		2.59			4.75			2.84			4.88
Total (Mcfe)	$	3.23		$	6.29		$	3.36		$	6.43
Average unit costs per Mcfe:
Lease operating expense	$	0.16		$	0.27		$	0.18		$	0.26
Gathering, processing, and transportation  (including affiliate)		0.74			0.59			0.67			0.61
Production and ad valorem taxes		0.13			0.20			0.12			0.20
General and administrative expenses		0.42			0.61			0.47			0.58
Depletion, depreciation, and amortization		1.47			1.75			1.55			1.81

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

The MRD Segment recorded a net loss of $26.7 million during the three months ended June 30, 2015 compared to a net loss of $951.7 million during the three months ended June 30, 2014.

· Oil, natural gas and NGL revenues for 2015 totaled $78.6 million, a decrease of $32.0 million compared with 2014. Production increased 6.8 Bcfe (approximately 39%) primarily due to drilling activities in North Louisiana. The average realized sales price decreased $3.06 per Mcfe (approximately 49%) due to lower commodity prices. The volume and pricing variance contributed to an approximate $42.8 million increase and offset by a $74.8 million decrease in revenues, respectively.

· Lease operating expenses were $3.9 million and $4.8 million for 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.16 for 2015 from $0.27 for 2014 due to increased production volumes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges.

· Gathering, processing and transportation expenses, including affiliates, were $18.1 million and $10.3 million for 2015 and 2014, respectively. The increase of $7.8 million is primarily due to an increase in natural gas and NGL volumes and an increase in the rate due to cryogenic processing associated with the new gas processing agreements. For more information regarding the new midstream service agreements, see Note 13 of the Notes to the Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

47

· DD&A expense for 2015 was $35.8 million compared to $30.8 million for 2014, an increase of $5.0 million.The increase is due to an increase in production volumes and was partially offset by a decrease in the rate as reserves grew faster than costs subject to depletion. Increased production volumes caused DD&A expense to increase by approximately $11.9 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $6.9million.

· Incentive unit compensation expense for 2015 was $16.1 million related to MRD Holdco incentive units as discussed in Note 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report. Incentive unit compensation expense of approximately $942.8 million was recorded in 2014, of which $831.1 million related to WildHorse Resource incentive units and $111.8 million related to MRD Holdco incentive units.

· General and administrative expenses for 2015 were $10.3 million compared to $10.8 million for 2014. General and administrative expenses for 2015 included $0.1 million of transaction-related costs compared to $0.5 million of transaction-related costs in 2014.

· Net losses on commodity derivative instruments of $30.5 million were recognized during 2015, consisting of $37.5 million of cash settlement receipts offset by a $68.0 million decrease in the fair value of open hedge positions. Net losses on commodity derivative instruments of $3.2 million were recognized during 2014, consisting of $3.4 million of cash settlement payments offset by $0.2 million related to the increase in the fair value of open hedge positions.

Given the volatility of commodity prices, it is not possible to predict future reported mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

· Net interest expense during 2015 was $9.6 million, including amortization of deferred financing fees of approximately $0.7 million. Net interest expense during 2014 was $16.5 million, including amortization of deferred financing fees of approximately $0.8 million. The decrease in net interest expense is primarily the result of a lower level of indebtedness during 2015 compared to 2014.

Average outstanding borrowings under our revolving credit facility were $140.5 million during 2015. Average outstanding borrowings under the revolving credit facilities were $269.7 million during 2014. For 2015, we had an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding. For 2014, we had an average of $296.2 million aggregate principal amount of the PIK notes issued and outstanding and an average of $282.1 million aggregate principal outstanding for the WildHorse Resources’ second lien term facility.

· Income tax benefit for 2015 was $24.6 million compared to $11.8 million for 2014. The increase in income tax benefit is primarily the result of an increase in the net loss subject to income taxes for 2015. The effective tax rate was 48.0% for 2015 compared to 1.2% for 2014. The effective tax rate for 2015 differs from the federal statutory income tax rate primarily due to the non-deductibility of incentive unit compensation and state income tax. The effective tax rate for 2014 differs from the federal statutory income tax rate primarily due to the non-deductibility of incentive unit compensation and MRD’s predecessor being a pass-through entity prior to the initial public offering.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

The MRD Segment recorded net income of $23.7 million during the six months ended June 30, 2015 compared to a net loss of $945.4 million during the six months ended June 30, 2014.

· Oil, natural gas and NGL revenues for 2015 totaled $165.6 million, a decrease of $32.7 million compared with 2014. Production increased 18.4 Bcfe (approximately 60%) primarily due to drilling activities in North Louisiana. The average realized sales price decreased $3.07 per Mcfe (approximately 48%) primarily due to lower commodity prices. The volume and pricing variance contributed to an approximate $118.4 million increase and $151.3 million decrease in revenues, respectively.

· Lease operating expenses were $9.1 million and $8.0 million for 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.18 for 2015 from $0.26 for 2014 due to increased production volumes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges.

· Gathering, processing and transportation expenses, including affiliates, were $32.9 million and $18.9 million for 2015 and 2014, respectively. The increase of $14.0 million is primarily due to an increase in natural gas and NGL volumes and an increase in the rate due to cryogenic processing associated with new gas processing agreements.

48

· DD&A expense for 2015 was $76.4 million compared to $55.9 million for 2014, an increase of $20.4 million. The increase is due to an increase in production volumes and was partially offset by a decrease in the rate as reserves grew faster than costs subject to depletion. Increased production volumes caused DD&A expense to increase by approximately $33.4 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $13.0 million.

· Incentive unit compensation expense for 2015 was $26.3 million related to MRD Holdco incentive units as discussed in Note 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report. Incentive unit compensation expense of approximately $943.8 million was recorded in 2014, of which $831.1 million related to WildHorse Resource incentive units, $111.8 million related to MRD Holdco incentive units, and $1.0 million related to BlueStone incentive units.

· General and administrative expenses for 2015 were $23.3 million compared to $17.8 million for 2014. General and administrative expenses for 2015 included $1.4 million of transaction-related costs compared to $1.1 million of transaction-related costs in 2014. Long term incentive plan (“LTIP”) awards for 2015 were $3.4 million compared to $0.2 million in 2014. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

· Net gains on commodity derivative instruments of $77.7 million were recognized during 2015, consisting of $70.3 million of cash settlement receipts in addition to a $7.4 million increase in the fair value of open hedge positions. Net losses on commodity derivative instruments of $16.0 million were recognized during 2014, consisting of $8.6 million of cash settlement payments and $7.4 million related to the decrease in the fair value of open hedge positions.

· Net interest expense during 2015 was $19.4 million, including amortization of deferred financing fees of approximately $1.3 million. Net interest expense during 2014 was $34.5million, including amortization of deferred financing fees of approximately $1.9 million. The decrease in net interest expense is primarily the result of lower level of indebtedness during 2015 compared to 2014.

Average outstanding borrowings under our revolving credit facility were $161.4 million during 2015. Average outstanding borrowings under the revolving credit facilities were $260.4 million during 2014. For 2015, we had an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding. For 2014, we had an average of $322.9 million aggregate principal amount of the PIK notes issued and outstanding and an average of $303.5 million aggregate principal outstanding for the WildHorse Resources’ second lien term facility.

· Income tax expense for 2015 was $22.9 million compared to an income tax benefit of $11.8 million for 2014. The income tax expense is primarily the result of net income before income taxes for 2015, compared to net loss before income taxes for 2014. The effective tax rate was 49.2% for 2015 compared to 1.2% for 2014. The effective tax rate for 2015 differs from the federal statutory income tax rate primarily due to the non-deductibility of incentive unit compensation and state income tax. The effective tax rate for 2014 differs from the federal statutory income tax rate primary due to the non-deductibility of incentive unit compensation and MRD’s predecessor being a pass-through entity prior to the initial public offering.

MEMP Segment

The MEMP Segment’s consolidated and combined results of operations for the three and six months ended June 30, 2015 and 2014 presented below have been derived from our consolidated and combined financial statements. The comparability of the results of operations among the periods presented is impacted by the following transactions:

· the Eagle Ford acquisition in March 2014 for a net purchase price of $168.1 million; and

· the Wyoming acquisition in July 2014 for a purchase price of approximately $906.1 million.

49

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)
Oil & natural gas sales	$	97,221		$	142,870		$	189,170		$	258,847
Lease operating		44,888			27,528			85,366			57,648
Gathering, processing, and transportation		9,048			7,591			17,268			13,154
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
(Gain) loss on commodity derivative instruments		61,403			138,346			(84,056	)		185,112
Interest expense, net		(27,910	)		(18,037	)		(56,728	)		(34,115	)
Net income (loss)		(113,859	)		(111,640	)		(276,517	)		(144,532	)
Natural gas and oil revenue:
Oil sales	$	52,815		$	62,373		$	97,068		$	105,119
NGL sales		11,213			19,515			23,336			36,794
Natural gas sales		33,193			60,982			68,766			116,934
Total natural gas and oil revenue	$	97,221		$	142,870		$	189,170		$	258,847
Production Volumes:
Oil (MBbls)		1,014			632			2,035			1,095
NGLs (MBbls)		692			617			1,391			1,109
Natural gas (MMcf)		12,322			12,968			24,703			24,052
Total (MMcfe)		22,548			20,457			45,246			37,272
Average net production (MMcfe/d)		247.8			224.8			250.0			205.9
Average sales price:
Oil (per Bbl)	$	52.09		$	98.76		$	47.70		$	96.02
NGL(per Bbl)		16.20			31.65			16.78			33.19
Natural gas (per Mcf)		2.69			4.70			2.78			4.86
Total (Mcfe)	$	4.31		$	6.98		$	4.18		$	6.94
Average unit costs per Mcfe:
Lease operating expense	$	1.99		$	1.35		$	1.89		$	1.55
Gathering, processing, and transportation		0.40			0.37			0.38			0.35
Production and ad valorem taxes		0.27			0.36			0.28			0.36
General and administrative expenses		0.64			0.56			0.64			0.59
Depletion, depreciation, and amortization		2.05			2.10			2.16			2.03

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

A net loss of $113.9 million was recorded for the three months ended June 30, 2015, primarily due to significant losses on commodity derivative instruments, compared to a net loss of $111.6 million generated for the three months ended June 30, 2014.

· Oil, natural gas and NGL revenues for 2015 totaled $97.2 million, a decrease of $45.7 million compared with 2014. Production increased 2.1 Bcfe (approximately 10%), primarily from increased drilling activities and increased volumes from third party acquisitions. The average realized sales price decreased $2.67 per Mcfe primarily due to lower period-to-period commodity prices. Crude oil volumes comprised approximately 27% of total volumes for 2015 compared to approximately 19% of total volumes for 2014. The unfavorable price variance contributed to an approximate $60.3 million decrease in revenues that was partially offset by a favorable volume variance, which contributed to an approximate $14.6 million increase in revenues.

· Lease operating expenses were $44.9 million and $27.5 million for 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses were $1.99 for 2015 compared to $1.35 for 2014. The increase was primarily due to the acquisition of oil properties with higher lifting costs and true-up of accruals.

· Gathering, processing and transportation expenses were $9.0 million and $7.6 million for 2015 and 2014, respectively. The increase of $1.5 million is primarily due to an increase in natural gas and NGL volumes. On a per Mcfe basis, gathering, processing, and transportation increased from $0.37 for 2014 to $0.40 for 2015.

· Production and ad valorem taxes for 2015 totaled $6.1 million, a decrease of $1.4 million compared with 2014 primarily due to lower realized commodity prices. On a per Mcfe basis, production and ad valorem taxes decreased to $0.27 for 2015 compared to $0.36 for 2014 due to reduced production and ad valorem taxes as a result of lower realized commodity prices in East Texas, South Texas and the Permian, offset by higher production tax rates on a per Mcfe basis for production from MEMP’s July 2014 Wyoming acquisition.

50

· DD&A expense for 2015 was $46.3 million compared to $43.0million for 2014, a $3.3 million increase primarily due to an increase in production volumes related to third party acquisitions and MEMP’s drilling program. Increased production volumes caused DD&A expense to increase by approximately $4.4 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $1.1 million.

· General and administrative expenses for 2015 were $14.4 million and included $2.6 million of non-cash unit-based compensation expense and $0.3 million of transaction-related costs. General and administrative expenses for 2014 totaled $11.4 million and included approximately $1.7 million of non-cash unit-based compensation expense and approximately $1.1 million of transaction-related costs. The $3.0 million period-to-period increase was primarily due to the acquisition of properties in the third quarter of 2014.

· Net losses on commodity derivative instruments of $61.4 million were recognized during 2015, consisting of $54.4 million of cash settlement receipts offset by a $115.8 million decrease in the fair value of open positions. Net losses on commodity derivative instruments of $138.3 million were recognized during 2014, consisting of $7.9 million of cash settlement payments and a $130.4 million decrease in the fair value of open positions.

· Net interest expense totaled $27.9 million during 2015, including losses on interest rate swaps of approximately $0.6 million, amortization of deferred financing fees of approximately $1.3 million, and accretion of net discount associated with the senior notes of $0.6 million. Net interest expense totaled $18.0 million during 2014, including losses on interest rate swaps of $0.8 million, amortization of deferred financing fees of approximately $0.9 million, and accretion of net discounts associated with the senior notes of $0.4 million. The increase in net interest expense is primarily due to the increase in outstanding borrowings under MEMP’s revolving credit facility and a higher aggregate principal amount of MEMP’s senior notes issued and outstanding for 2015 compared to 2014.

Average outstanding borrowings under MEMP’s revolving credit facility were $627.0 million during 2015 compared to $431.7 million during 2014. For 2015, MEMP had an average of $1.2 billion aggregate principal amount of its senior notes issued and outstanding. For 2014, MEMP had an average of $700.0 million aggregate principal amount of its senior notes issued and outstanding.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

A net loss of $276.5 million was generated for the six months ended June 30, 2015, primarily due to impairment charges which were partially offset by significant gains on commodity derivative instruments, compared to a net loss of $144.5 million generated for the six months ended June 30, 2014.

· Oil, natural gas and NGL revenues for 2015 totaled $189.2 million, a decrease of $69.6 million compared with 2014. Production increased 8.0 Bcfe (approximately 21%), primarily from increased drilling activities and increased volumes from third party acquisitions. The average realized sales price decreased $2.76 per Mcfe primarily due to lower period-to-period commodity prices. Crude oil volumes comprised approximately 27% of total volumes for 2015 compared to approximately 18% of total volumes for 2014. The unfavorable price variance contributed to an approximate $124.9 million decrease in revenues that was partially offset by a favorable volume variance, which contributed to an approximate $55.3 million increase in revenues.

· Lease operating expenses were $85.4 million and $57.6 million for 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses increased to $1.89 for 2015 from $1.55 for 2014. The increase was primary due to the acquisition of oil properties with higher lifting costs.

· Gathering, processing and transportation expenses were $17.3 million and $13.2 million for 2015 and 2014, respectively. The increase of $4.1 million is primarily due to an increase in natural gas and NGL volumes. On a per Mcfe basis, gathering, processing, and transportation increased from $0.35 for 2014 to $0.38 for 2015.

· Production and ad valorem taxes for 2015 totaled $12.7 million, a decrease of $0.7 million compared with 2014 primarily due to a decrease in commodity prices. On a per Mcfe basis, production and ad valorem taxes decreased to $0.28 for 2015 from $0.36 for 2014 due to lower realized commodity prices in East Texas, South Texas and the Permian, partially offset by higher production tax rates on a per Mcfe basis for production from MEMP’s July 2014 Wyoming acquisition.

· DD&A expense for 2015 was $97.6 million compared to $75.5 million for 2014, a $22.1 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and MEMP’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $16.2 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximately $5.9 million.

· Impairment expense for 2015 was $251.3 million which primarily related to certain properties 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.  MEMP did not record any impairment during the same period for 2014.

51

· General and administrative expenses for 2015 were $28.9 million and included $4.9 million of non-cash unit-based compensation expense and $1.6 million of transaction-related costs. General and administrative expenses for 2014 totaled $22.1million and included approximately $3.0 million of non-cash unit-based compensation expense and approximately $3.0 million of transaction-related costs. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods. The $6.8 million period-to period increase was primarily due to the acquisition of properties in the third quarter of 2014.

· Net gains on commodity derivative instruments of $84.1 million were recognized during 2015, consisting of $114.4 million of cash settlement receipts on expired positions and $27.1 million in cash settlements received on terminated derivatives. These gains were offset by a $57.4 million decrease in the fair value of open positions. Net losses on commodity derivative instruments of $185.1 million were recognized during 2014, consisting of $15.9 million of cash settlement payments and $169.2 million decrease in the fair value of open positions.

· Net interest expense totaled $56.7 million during 2015, including losses on interest rate swaps of approximately $3.1 million, amortization of deferred financing fees of approximately $3.1 million, and accretion of net discount associated with the senior notes of $1.2 million. Net interest expense totaled $34.1 million during 2014, including losses on interest rate swaps of $1.1 million and amortization of deferred financing fees of approximately $1.7 million and accretion of net discounts associated with senior notes of $0.7 million. The increase in net interest expense is primarily due to the increase in outstanding borrowings under MEMP’s revolving credit facility and a higher aggregate principal amount of MEMP’s senior notes issued and outstanding for 2015 compared to 2014.

Average outstanding borrowings under MEMP’s revolving credit facility were $567.9 million during 2015 compared to $291.0 million during 2014. For 2015, MEMP had an average of $1.2 billion aggregate principal amount of its senior notes issued and outstanding. For 2014, MEMP had an average of $700.0 million aggregate principal amount of its senior notes issued and outstanding.

Consolidated

For consolidated results of operations, see MRD Segment and MEMP Segment above.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, the MRD and MEMP Segments operate with independent capital structures. The MEMP Segment’s debt is nonrecourse to the Company. With the exception of cash distributions paid to the MRD Segment by the MEMP Segment related to MEMP partnership interests held by the Company, the cash needs of each segment have been met independently with a combination of operating cash flows, asset sales, credit facility borrowings and the issuance of debt and equity. We expect that the cash needs of each of the MRD Segment and the MEMP Segment will continue to be met independently of each other with a combination of these funding sources.

MRD Segment

Historically, the primary sources of liquidity have been through borrowings under credit facilities, capital contributions from NGP and certain members of management, borrowings under a second lien term loan facility, issuance of senior notes, asset sales, including dropdowns to MEMP, and net cash provided by operating activities. The primary use of cash has been for the exploration, development and acquisition of natural gas and oil properties. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet future financial obligations, planned capital expenditure activities and liquidity requirements. Any future success in growing proved reserves and production will be highly dependent on the capital resources available. Our identified potential horizontal well locations in the Terryville Complex will take many years to develop.

Currently, the primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We also have the ability to issue additional equity and debt as needed through both private and public offerings. We may from time-to-time refinance our existing indebtedness including by issuing longer-term fixed rate debt to refinance shorter-term floating rate debt.

We believe our cash flows provided by operating activities and availability under our revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned 2015 development drilling activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We can provide no assurance that operations and other needed capital will be available on acceptable terms, or at all.

52

As of June 30, 2015, we had $560.0 million ofavailable borrowings under our revolving credit facility and $4.5 million of cash and cash equivalents. As of June 30, 2015, we had a working capital deficit balance of $19.3 million.We believe the available borrowings under our revolving credit facility provides sufficient liquidity to finance anticipated working capital and capital expenditure requirements.

Capital Budget

For the six months ended June 30, 2015, MRD Segment’s total capital expenditures, including unproved leasehold, were $234.3 million related primarily to the development of the Terryville Complex.

Debt Agreements—MRD Segment

Revolving Credit Facility

In June 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with a borrowing base of $725.0 million as of June 30, 2015. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. In April 2015, the borrowing base under our revolving credit facility was re-affirmed at $725.0 million. In the future, we may be unable to access sufficient capital under the revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

We believe we were in compliance with all the financial (interest coverage ratio and current ratio) and other covenants associated with our revolving credit facility as of June 30, 2015.

See Note 8 under “Item 1. Financial Statements” for additional information regarding our revolving credit facility.

MRD Senior Notes

As of June 30, 2015, MRD had $600.0 million aggregate principal amount of 5.875% senior unsecured notes due 2022 (the “MRD Senior Notes”) outstanding. The MRD Senior Notes will mature on July 1, 2022 with interest accruing at a rate of 5.875% per annum and payable semi-annually in arrears on January 1 and July 1 of each year. The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are fully and unconditionally guaranteed, subject to customary release provisions, on a senior unsecured basis by certain of our existing subsidiaries. See Note 8 under “Item 1. Financial Statements” for additional information regarding the MRD Senior Notes.

Debt Agreements—MEMP Segment

Revolving Credit Facility

Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is party to a $2.0 billion revolving credit facility, with a current borrowing base of $1.3 billion that matures in March 2018 and is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries). See Note 8 under “Item 1. Financial Statements” for additional information regarding MEMP’s revolving credit facility.

Senior Notes

As of June 30, 2015, MEMP had $700.0 million aggregate principal of amount of 7.625% senior notes due 2021 (“2021 Senior Notes”) outstanding. The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes were issued under and are governed by an indenture dated as of April 17, 2013.

As of June 30, 2015, MEMP had approximately $497.0 million aggregate principal amount of 6.875% senior notes due 2022 (“2022 Senior Notes”) outstanding. The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year. The 2022 Senior Notes were issued under and are governed by an indenture dated as of July 17, 2014.

See Note 8 under “Item 1. Financial Statements” for additional information regarding the 2021 Senior Notes and 2022 Senior Notes.

53

Commodity Derivative Contracts

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of June 30, 2015, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Interest Rate Derivative Contracts

Periodically, we may enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time-to-time we may enter into offsetting positions to avoid being economically over-hedged.

See “Item 3. Quantitative and Qualitative Disclosure About Market Risk” for a summary of our derivative contracts as of June 30, 2015.

Counterparty Exposure

Our hedging policy permits us to enter into derivative contracts with major financial institutions or major energy entities. Our derivative contracts are currently with major financial institutions, certain of which are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following tables summarize segment cash flows from operating, investing and financing activities for the periods indicated. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated and Combined Cash Flows included under Item 1 of this quarterly report.

MRD Segment

	Six Months Ended June 30,
	2015			2014
Net cash provided by operating activities:	$	187,875		$	65,435
Net cash used in investing activities:
Additions to oil and gas properties	$	(207,103	)	$	(155,362	)
Additions to other property and equipment		(3,287	)		(1,268	)
Distributions received from MEMP Segment related to partnership interests		151			6,004
Decrease (increase) in restricted cash		—			49,946
Proceeds from the sale of oil and gas properties to third parties		13,612			6,700
Other		—			(315	)
Net cash provided by (used in) investing activities	$	(196,627	)	$	(94,295	)
Net cash provided by financing activities:
Advances on revolving credit facilities	$	181,000		$	1,130,800
Payments on revolving credit facilities		(199,000	)		(714,900	)
Termination of second lien credit facility		—			(328,282	)
Redemption of senior notes		—			(351,808	)
Deferred financing costs		—			(5,644	)
Purchase of additional interest in consolidated subsidiaries		—			(3,292	)
Proceeds from initial public offering		—			408,500
Costs incurred in conjunctions with initial public offering		—			(26,875	)
Contributions from MEMP Segment		78,396			33,880
Contribution related to sale of assets to NGP affiliates		—			1,165
Distribution to noncontrolling interest		—			(325	)
Distribution to MEMP Segment		(1,912	)		(1,975	)
Distribution to MRD Holdco		—			(59,803	)
Distribution to other NGP affiliates		—			(99,463	)
Repurchases of shares		(51,197	)		—
Other		—			268
Net cash provided by (used in) financing activities	$	7,287		$	(17,754	)

54

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Operating Activities. Net cash flows provided by operating activities were $187.9 million during 2015 compared to $65.4 million during 2014. Production increased 18.4 Bcfe (approximately 60%) and average realized sales price decreased $3.07 per Mcfe as previously discussed under “Results of Operations—MRD Segment.” Cash paid for interest during 2015 was $35.7 million compared to $34.3 million during 2014 and cash settlements on commodity derivatives were $78.9 million higher in 2015. In 2014, $26.7 million was paid related to the WildHorse Resources incentive units and $8.2 million was paid for debt extinguishment costs.

Investing Activities. Total cash used in investing activities was $196.6 million during 2015 compared to $94.3 million for the same period in 2014. Cash used for additions to oil and gas properties was $207.1 million during 2015 compared to $155.4 million for the same period in 2014, which consisted primarily of drilling and completion activities in North Louisiana. Additions to other property and equipment were $3.2 million which consisted primarily of computer hardware, software, and other leased office space build out during 2015. Distributions of $0.1 million and $6.0 million were received from MEMP related to partnership interests owned by the MRD Segment during 2015 and 2014, respectively.  MRD LLC owned MEMP subordinated units during 2014.  These MEMP partnership interests were distributed to MRD Holdco in connection with Company’s initial public offering in June 2014.  On April 17, 2015, we sold certain oil and natural gas properties to a third party in Colorado and Wyoming for approximately $13.6 million. On May 9, 2014, Black Diamond sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for cash consideration of approximately $6.7 million. There was a decrease in restricted cash of $49.9 million in 2014, which was primarily due to $50.0 million being released from the debt service reserve account associated with the PIK notes.

Financing Activities.  Net repayments under our revolving credit facility were $18.0 million during 2015 compared to net advances of $415.9 million during 2014.

On June 18, 2014, we completed our initial public offering pursuant to which we sold 21,500,000 shares of our common stock to the public at an offering price of $19.00 per share. After deducting underwriting discounts and commissions of $23.0 million and additional estimated offering expenses of $4.8 million (including $0.9 million of accrued offering expenses), the net proceeds from our initial public offering were approximately $380.7 million. We used approximately $360.0 million of our initial public offering proceeds to redeem the PIK notes on June 27, 2014, of which $351.8 million was classified as a financing activity and the remaining $8.2 million was classified as an operating activity representing interest expense.

Distributions to NGP affiliates related to the purchase of assets were primarily related to WildHorse Resources’ February 2014 acquisition of net profits interests in the Terryville Complex from an affiliate of NGP for $63.4 million. MRD Royalty also acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from an affiliate of NGP for $3.3 million in March 2014. Distributions to NGP affiliates related to such sale of assets were $32.8 million.

Distributions to MRD Holdco during 2014 were $59.8 million. Approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014 was distributed to MRD Holdco in connection with our initial public offering. We also reimbursed MRD LLC for the approximately $17.2 million interest payment that it made on the PIK notes on June 15, 2014, which was distributed to MRD Holdco. Remaining cash of $32.8 million released from the debt service reserve account in connection with the redemption and discharge of the PIK notes was also distributed to MRD Holdco. Bluestone distributed $3.1 million to MRD Holdco in connection with our initial public offering and restructuring transactions.

The MRD Segment received $78.4 million from the MEMP Segment in connection with the Property Swap. MRD made deemed distributions of $1.9 million and $2.0 million to MEMP related to the properties MEMP acquired in the Property Swap transaction during 2015 and 2014, respectively. The MRD Segment received $33.9 million from the MEMP segment in connection with MEMP’s acquisition of certain oil and gas properties in East Texas during 2014.

Total payments remitted for employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million during 2015 upon vesting of the restricted common stock.The Company repurchased 2,888,684 shares of its common stock under its December 2014 repurchase program for an aggregate price of $50.0 million during 2015, which exhausted the December 2014 repurchase program. At December 31, 2014, there was $2.2 million accrued for 123,797 shares that were repurchased and retired in 2014. The Company has retired all of the shares of common stock repurchased and those shares of common stock are no longer issued or outstanding.  

Deferred financing costs of approximately $5.6 million were incurred during 2014.

55

MEMP Segment

	Six Months Ended June 30,
	2015			2014
Net cash provided by operating activities	$	111,718		$	112,315
Net cash used in investing activities:
Acquisition 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	)
Net cash provided by (used in) investing activities	$	(127,666	)	$	(383,451	)
Net cash provided by financing activities
Advances on revolving credit facilities	$	252,000		$	418,000
Payments on revolving credit facilities		(22,000	)		(62,000	)
Repurchase of senior notes		(2,914	)		—
Deferred financing costs		(235	)		(590	)
Contribution from MRD Segment		1,912			1,975
Distributions to partners		(92,628	)		(67,524	)
Distributions to MRD Segment		(78,396	)		(33,880	)
Restricted units returned to plan		(7	)		—
Repurchased units under unit repurchase program		(42,591	)		—
Other		—			14
Net cash provided by (used in) financing activities	$	15,141		$	255,995

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities decreased by $0.6 million and net income decreased by $132.0 million. Production increased 8.0 Bcfe (approximately 21%) while average realized sales price decreased $2.76 per Mcfe. Net cash provided by operating activities included a $128.8 million period-to-period increase in cash settlements received on expired commodity derivative instruments partially offset by a $5.3 million period-to-period decrease in cash flow attributable to the timing of cash receipts and disbursements related to operating activities. These period-to-period increases partially offset decreased revenues and increased operating costs as previously discussed under “—Results of Operations—MEMP Segment.”

Investing Activities. Net cash used in investing activities during 2015 was $127.7 million, of which $6.1 million was used to acquire oil and natural gas properties from a third party and $128.3 million was used for additions to oil and natural gas properties. Cash used in investing activities during 2014 was $383.5 million, of which $173.0 million was used to acquire oil and natural gas properties from a third party and $138.2 million was used for additions to oil and natural gas properties. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. Additions to restricted investments were $2.7 million during 2015 compared to $2.1 million during 2014. MEMP made an earnest money deposit of $70.1 million during 2014 related to its Wyoming Acquisition. MEMP received a post-closing settlement receipt of $9.6 million related to its Wyoming Acquisition during 2015.

Financing Activities. Distributions to partners during 2015 were $92.6 million compared to $67.5 million during 2014, of which the MRD Segment received $0.1 million during 2015 compared to $6.0 million during 2014. The MRD Segment received $78.4 million from MEMP in connection with the Property Swap acquisition. MEMP received a contribution of $1.9 million and $2.0 million from the MRD Segment related to the properties MEMP acquired in the Property Swap transaction during 2015 and 2014, respectively. The MRD Segment received $33.9 million from the MEMP segment in connection with MEMP’s acquisition of certain oil and gas properties in East Texas during 2014.

MEMP had net borrowings of $230.0 million under its revolving credit facility during 2015 that were primarily used to fund the Property Swap acquisition and to fund MEMP’s drilling program. MEMP had net borrowings of $356.0 million under its revolving credit facility during 2014 that were used primarily to fund its March 2014 Eagle Ford acquisition, the earnest money deposit for its Wyoming Acquisition and to fund MEMP’s drilling program.

MEMP repurchased $42.6 million in common units during 2015, which represents a repurchase and retirement of 2,862,782 common units under the MEMP Repurchase Program (including common unit repurchases of $1.4 million, representing 93,800 common units, accrued at December 31, 2014). In addition, MEMP accrued repurchases of $2.7 million, representing 182,630 common units at June 30, 2015. MEMP repurchased a principal amount of approximately $3.0 million of the 2022 Senior Notes at a price of 83.000% of the face value of the 2022 Senior Notes in January 2015, of which $2.9 million was classified as a financing outflow representing repayment of the original proceeds and $0.3 million classified as an operating inflow.

56

Contractual Obligations

During the six months ended June 30, 2015, there were no significant changes in our consolidated contractual obligations from those reported in our Recast Form 8-K filed with the SEC on July 8, 2015, except for the addition of the midstream service agreements with PennTex. For more information, see Note 13 of the Notes to the Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Off–Balance Sheet Arrangements

As of June 30, 2015, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. We believe that our exposures to market risk have not changed materially since those reported under “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2014 Form 10-K filed with the SEC on March 18, 2015.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our natural gas, oil and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices received.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of June 30, 2015, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for interest rate swap arrangements that were outstanding at June 30, 2015.

At June 30, 2015, we had $165.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 1.50%, or 1.66%. Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the in the variable component of the stated interest rates would be less than $0.1 million per year.

The fair value of MRD Senior Notes, MEMP’s 2022 Senior Notes and MEMP’s 2021 Senior Notes is sensitive to changes in interest rates. We estimate the fair value of MRD Senior Notes, MEMP’s 2022 Senior Notes and MEMP’s 2021 Senior Notes using quoted market prices. The carrying value (net of any discount or premium) is compared to the estimated fair value in the table below (in thousands):

	June 30, 2015
	Carrying		Estimated
Description	Amount		Fair Value
MRD Segment:
5.875% senior notes, fixed-rate, due May 1, 2022	$	600,000	$	574,500
MEMP Segment:
7.625% senior notes, fixed rate, due May 1, 2021	$	691,296	$	669,375
6.875% senior notes, fixed-rate, due August 1, 2022	$	490,354	$	454,746

57

Counterparty and Customer Credit Risk

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding credit risk associated with our derivative instruments.

ITEM 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2015. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2015 at the reasonable assurance level.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2, respectively, to this quarterly report.

58

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, “Item 1. Financial Statements”, Note 15, “Commitments and Contingencies – Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included in this quarterly report, which is incorporated herein by reference.

ITEM 1A. RISK FACTORS.

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. There have been no material changes with respect to the risk factors disclosed in our 2014 Form 10-K filed with the SEC on March 18, 2015 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2015 filed with the SEC on May 11, 2015.

59

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

(a) Recent sales of unregistered securities.

None.

(b) Use of proceeds.

None.

(c) Purchases of equity securities by the issuer and affiliated purchasers.

The following table summarizes our repurchase activity during the quarterly period ended June 30, 2015.

							Approximate
			Average		Total Number of Shares Purchased		Dollar Value of Shares That May
	Total Number of		Price Paid		as Part of Publicly		Yet Be Purchased
Period	Shares Purchased		per Shares		Announced Plan		Under the Plan
							(in thousands)
Restricted share repurchases (1)
April 1, 2015 - April 30, 2015		—	$	—		—	$	—
May 1, 2015 - May 31, 2015		—	$	—		—	$	—
June 1, 2015 - June 30, 2015		60,773	$	19.70		—	$	—
Total		60,773	$	19.70		—	$	—

(1) Represents common shares surrendered to satisfy tax liabilities incident to the vesting of restricted shares issued under the LTIP.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

The information required by this Item 6. Exhibits is set forth in the Exhibit Index accompanying this quarterly report on Form 10-Q, which is incorporated herein by reference.

60

SIGNATURES

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

	Memorial Resource Development Corp.
	(Registrant)
Date: August 5, 2015	By:	/s/Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Senior Vice President and Chief Financial Officer

61

EXHIBIT INDEX

Exhibit Number		Description
2.1##	—	Purchase and Sale Agreement, dated as of May 2, 2014, among Merit Management Partners I, L.P., Merit Energy Partners III, L.P., Merit Pipeline Company, LLC and Merit Energy Company, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Memorial Production Partners LP’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2014).
2.2##	—		Purchase and Sale Agreement, dated as of March 25, 2014, between Alta Mesa Eagle, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Memorial Production Partners LP’s Current Report on Form 8-K (File No. 001-35364) filed on March 25, 2014).
3.1	—		Amended and Restated Certificate of Incorporation dated June 10, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 16, 2014).
3.2	—		Amended and Restated Bylaws dated June 10, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 16, 2014).
4.1#	—		Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to Memorial Production Partners LP’s Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011).
10.1	—		Fourth Amendment to Credit Agreement by and among Memorial Resource Development Corp., as borrower, Bank of America, N.A., as administrative agent, and the other lenders and parties party thereto, dated as of April 13, 2015 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on April 14, 2015).
10.2	—		Amended and Restated Area of Mutual Interest and Midstream Exclusivity Agreement by and among PennTex NLA Holdings, LLC, MRD WHR LA Midstream LLC, MRD Operating LLC, and PennTex North Louisiana, LLC, dated as of April 14, 2015 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on April 17, 2015).
10.3*	—		Amendment No. 1 to Amended and Restated Area of Mutual Interest and Midstream Exclusivity Agreement by and among PennTex NLA Holdings, LLC, MRD WHR LA Midstream LLC, MRD Operating LLC, and PennTex North Louisiana, LLC, dated as of May 20, 2015.
10.4	—		Amended and Restated Gas Processing Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of April 14, 2015 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on April 17, 2015).
10.5*	—		Amendment No. 1 to Amended and Restated Gas Processing Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of May 20, 2015.
10.6	—		Gas Gathering Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of April 14, 2015 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on April 17, 2015).
10.7*	—		Amendment No. 1 to Gas Gathering Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of May 20, 2015.
10.8	—		Gas Transportation Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of April 14, 2015 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on April 17, 2015).
10.9	—		Transportation Services Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of April 14, 2015 (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on April 17, 2015).

62

31.1*	—	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*	—	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
32.1*	—	Certifications of Principal Executive Officer and Principal Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.CAL*	—	XBRL Calculation Linkbase Document
101.DEF*	—	XBRL Definition Linkbase Document
101.INS*	—	XBRL Instance Document
101.LAB*	—	XBRL Labels Linkbase Document
101.PRE*	—	XBRL Presentation Linkbase Document
101.SCH*	—	XBRL Schema Document

* Filed or furnished as an exhibit to this Quarterly Report on Form 10-Q.

# Management contract or compensatory plan or arrangement.

## Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

63

EX-10.3

Exhibit 10.3

Execution version

AMENDMENT NO. 1 TO

AMENDED AND RESTATED AREA OF MUTUAL INTEREST

AND MIDSTREAM EXCLUSIVITY AGREEMENT

This Amendment No. 1 to Amended and Restated Area of Mutual Interest and Midstream Exclusivity Agreement, dated as of May 20, 2015 (this “Amendment”), is entered into by and among PennTex NLA Holdings, LLC, a Delaware limited liability company (“PTX”), MRD WHR LA Midstream LLC, a Delaware limited liability company (“MRD”), MRD Operating LLC, a Delaware limited liability company (“MRD Operating”), and PennTex North Louisiana, LLC, a Delaware limited liability company (“JV”). PTX, MRD, MRD Operating and JV are each referred to herein as a “Party,” and collectively as, the “Parties.” Defined terms used but not defined herein have the meaning given to them in the Agreement (as defined below).

WHEREAS, the Parties entered into that certain Amended and Restated Area of Mutual Interest and Midstream Exclusivity Agreement, dated as of April 14, 2015 (the “Agreement”), in order to (i) establish an area of mutual interest covering the lands lying within the AMI and (ii) grant certain exclusivity rights to provide Midstream Services for Hydrocarbons produced by MRD Operating from AMI Interests; and

WHEREAS, the Parties desire to amend the Agreement in accordance with Section II.F(xiv) thereof as set forth herein.

NOW THEREFORE, in consideration of the premises of this Amendment and the agreements set forth herein and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the Parties hereby agree as follows:

1. Amendment and Restatement of Section II.B(iv). Section II.B(iv) of the Agreement is hereby amended and restated in its entirety as follows:

“(iv) If MRD Operating dedicates Hydrocarbons produced from AMI Interests to JV for the provision of Midstream Services, the provision of such Midstream Services requires Other Operations and JV proposes to proceed with such Other Operations, then JV shall prepare, in good faith, a budget setting forth the projected capital expenditures associated with such Other Operations, and MRD Operating and JV shall, in good faith, attempt to agree on the commercial terms for such Other Operations based on such projected capital expenditures budget. For the avoidance of doubt, such use of good faith efforts shall include good faith efforts to agree on terms that are “market,” meaning commonly accepted between parties for similar projects. If MRD Operating and JV agree on the commercial terms and enter into a definitive agreement with respect to such commercial terms, JV shall proceed with the Other Operations. Notwithstanding anything in this Agreement to the contrary, if JV proceeds with the construction of facilities pursuant to this Section II.B(iv) and if such facilities are not available at the time MRD Operating is ready to deliver Hydrocarbons to such facilities, then JV’s exclusive rights to provide the Midstream Services applicable to such Other Operations, and in the Hydrocarbons attributable thereto, shall be automatically released, on a temporary basis, from the dedication herein without any further action on any Person’s part, until such time as such facilities are available.”

2. Amendment and Restatement of Section II.B(v). Section II.B(v) of the Agreement is hereby amended and restated in its entirety as follows:

“(v) If (x) MRD Operating dedicates Hydrocarbons produced from AMI Interests to JV for the provision of Midstream Services, (y) the provision of such Midstream Services requires Other Operations, and (z) JV does not elect to proceed with such Other Operations, then JV’s exclusive rights to provide such Midstream Services, and in the Hydrocarbons attributable thereto, shall be automatically released from the dedication herein without any further action on any Person’s part. If JV does not provide MRD Operating a budget for Other Operations in accordance with Section II.B(iv) within sixty (60) days of MRD Operating’s request for such Other Operations, JV shall be deemed to have elected to not proceed with such Other Operations.”

3. Amendment and Restatement of Section II.B(vi). Section II.B(vi) of the Agreement is hereby amended and restated in its entirety as follows:

“(vi) [reserved].”

4. Amendment and Restatement of Section II.C. Section II.C of the Agreement is hereby amended and restated in its entirety as follows with respect to the period from and after the date of this Amendment:

“(C) Exclusivitv Regarding the Provision of Midstream Services. MRD Operating and PTX, and each of their respective Subsidiaries, shall not invest in, provide services to, receive any consideration in respect of, or otherwise engage in, contract for, or conduct any Midstream Services in the AMI, except (i) Other Operations by and through JV or any of its Subsidiaries in accordance with Section II.B(iv) and Section II.B(v) hereof, (ii) as provided in the Pipeline Agreements or this Agreement and (iii) any agreement executed by MRD Operating after the Effective Date for the provision of Midstream Services on an interruptible and/or uncommitted basis for Hydrocarbons released from the dedication of this Agreement in accordance with Section II.B or pursuant to one or more Pipeline Agreements.”

5. Governing Law. This Amendment shall be govered, interpreted and construed in accordance with the laws of the State of Texas without regard to the conflicts of laws provisions thereof.

6. Counterpart Execution. This Amendment may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument. Any signature delivered by a Party by facsimile transmission or electronically shall be deemed an original signature.

7. Integration with Agreement. This Amendment shall be and hereby is incorporated into and forms a part of the Agreement. Except as expressly provided herein, all terms and conditions of the Agreement shall remain in full force and effect.

[signature page follows]

2

IN WITNESS WHEREOF, each of the Parties has duly executed this Amendment as of the date first written above.

PennTex NLA Holdings, LLC
By:	/s/ Robert O. Bond
Name:	Robert O. Bond
Title:	Chief Operating Officer

MRD WHR LA Midstream LLC
By:	/s/ Kyle N. Roane
Name:	Kyle N. Roane
Title:	Manager

MRD Operating LLC
By:	Memorial Resource Development Corp., its sole member
By:	/s/ Kyle N. Roane
Name:	Kyle N. Roane
Title:	Senior Vice President

PennTex North Louisiana, LLC
By:	/s/ Robert O. Bond
Name:	Robert O. Bond
Title:	Chief Operating Officer

[Signature Page to Amendment No. 1 to Amended and Restated AMI and Exclusivity Agreement]

EX-10.5

Exhibit 10.5

Execution version

AMENDMENT NO. 1 TO

AMENDED AND RESTATED GAS PROCESSING AGREEMENT

This Amendment No. 1 to Amended and Restated Gas Processing Agreement, dated as of May 20, 2015 (this “Amendment”), is entered into by and among PennTex North Louisiana, LL C, a Delaware company and successor in interest to PennTex North Louisiana Operating, LLC (“Processor”), and MRD Operating LLC, a Delaware limited liability company (“Customer”). Processor and Customer are each referred to herein as a “Party,”and collectively as, the “Parties.” Defined terms used but not defined herein have the meaning given to them in the Agreement (as defined below).

WHEREAS, the Parties entered into that certain Amended and Restated Gas Processing Agreement, dated as of April 14, 2015 (the “Agreement”), pursuant to which Processor agreed to provide certain processing services for Customer; and

WHEREAS, the Parties desire to amend the Agreement in accordance with Section 19.20 thereof as set forth herein.

NOW THEREFORE, in consideration of the premises of this Amendment and the agreements set forth herein and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the Parties hereby agree as follows:

1. Amendment to Article I. Article Iof the Agreement is hereby amended by adding thereto in alphabetical order each of the following definitions, which shall read in full as follows:

“GPM” means the quantity of Gallons of theoretically recoverable NGL Components contained in an Mcf of Gas, as calculated from chromatographic analysis or other method acceptable in the industry”

“NGL Components” means the individual hydrocarbon components of NGL’s including ethane, propane, iso butane, normal butane and natural gasoline (pentanes and heavier hydrocarbons).”

2. Amendment to Section 3.1(e). Section 3.l(e) of the Agreement is hereby amended by adding the following sentence to the end of such Section:

Notwithstanding the foregoing, the Parties acknowledge and agree that each Plant will be designed to accept a maximum volume of Gas equal to 230,000 MMBtu per Day, assuming a Gross Heating Value of 1,150 Btu per cubic foot or minimum NGL Components of 2.6 GPM.”

3. Governing Law. This Amendment shall be government, interpreted and construed in accordance with the laws of the State of Texas without regard to the conflicts of laws provisions thereof.

4. Counterpart Execution. This Amendment may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument. Any signature delivered by a Party by facsimile transmission or electronically shall be deemed an original signature.

5. Integration with Agreement. This Amendment shall be and hereby is incorporated into and forms a part of the Agreement. Except as expressly provided herein, all terms and conditions of the Agreement shall remain in full force and effect.

[signature page follows]

IN WITNESS WHEREOF, each of the Parties has duly executed this Amendment as of the date first written above.

MRD Operating LLC
By:	Memorial Resource Development Corp., its sole member
By:	/s/ Kyle N. Roane
Name:	Kyle N. Roane
Title:	Senior Vice President
PcnnTex North Louisiana, LLC
By:	/s/ Robert O. Bond
Name:	Robert O. Bond
Title:	Chief Operating Officer

[Signature Page to Amendment No. 1 to Amended and Rcstated Gas Processing Agreement]

EX-10.7

Exhibit 10.7

Execution version

AMENDMENT NO. 1 TO

GAS GATHERING AGREEMENT

This Amendment No. 1 to Gas Gathering Agreement, dated as of May 20, 2015 (this “Amendment”), is entered into by and among PennTex North Louisiana, LLC, a Delaware company and successor in interest to PennTex North Louisiana Operating, LLC (“Gatherer”), and MRD Operating LLC, a Delaware limited liability company (“Customer”). Gatherer and Customer are each referred to herein as a “Party,” and collectively as, the “Parties”Defined terms used but not defined herein have the meaning given to them in the Agreement (as defined below).

WHEREAS, the Parties entered into that certain Gas Gathering Agreement, dated as of April 14, 2015 (the “Agreement”), to provide for the gathering, compression, dehydration and/or treating of Customer’s Gas on Gatherer’s natural gas gathering system and related facilities; and

WHEREAS, the Parties desire to amend the Agreement in accordance with Article XV thereof as set forth herein.

NOW THEREFORE, in consideration of the premises of this Amendment and the agreements set forth herein and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the Parties hereby agree as follows:

1. Amendment to Article I. Article I of the Agreement is hereby amended by adding thereto in alphabetical order each of the following definitions, which shall read in full as follows:

“Modification Final AFE” shall mean, with respect to a Modification undertaken by Gatherer at Customer’s expense pursuant to Article II, an amount equal to the lesser of (i) 110% of Gatherer’s actual, out of pocket costs to install any facilities required as part of the Modification, including but not limited to Measurement Facilities, hot taps, valving, etc., and (ii) the total amount of the AFE for such Modification.

“Modification Surcharge” shall mean, with respect to a Modification undertaken by Gatherer at Customer’s expense pursuant to Article II, an amount, expressed in cents per MMBtu, equal to quotient of (i) the Modification Final AFE for such Modification, divided by (ii) the product of (x) twelve (12) multiplied by (y) the total volume of Customer Gas (expressed in MMBtu) forecasted to be received at the Point of Receipt to which such Modification relates in the Month immediately following the Month in which such Modification is completed and made available to Customer (such forecasted volume shall be the volume agreed to by the Parties in preparing the AFE applicable to such Modification).

“Receipt Point Gathering Fee” shall have the meaning given such term in Article II.

2. Amendment and Restatement of Article II. Article II is hereby amended by deleting the second sentence of subsection (c) of the section titled “Post-Commencement Date Point of Receipt Facilities” in its entirety and replace it with the following:

“If Customer elects the foregoing option (y) with respect to a Modification, commencing on the first day of the Month immediately following the Month in which such Modification is completed and available for service to Customer, Customer shall pay Gatherer a fee each Month (the “Receipt Point Gathering Fee”) equal to the product of (i) the Modification Surcharge per MMBtu applicable to such Modification, and (ii) the volume of Customer Gas (in MMBtu) received by Gatherer during such Month at the Point of Receipt to which such Modification relates. Customer shall pay the Receipt Point Gathering Fee with respect to a Modification until the aggregate amount of all such fees paid by Customer for such Modification equals the Modification Final AFE for such Modification”

3. Amendments to Article VIII.

(i) The Section titled “Fees” in Article VIII of the Agreement is hereby amended by adding thereto a new clause (e), which shall read in full as follows:

“(e) Receipt Point Gathering Fee. To the extent applicable, Customer shall pay Gatherer the Receipt Point Gathering Fee with respect to Modifications as required pursuant to Article II(c) of the section titled “Post-Commencement Date Point of Receipt Facilities.”

(ii) The Section titled “Invoices and Statements” in Article VIII of the Agreement is hereby amended by adding a sentence to end thereof to read as follows:

“If any Receipt Point Gathering Fees are incurred during a Month, Gatherer’s statement for such Month shall include a breakdown of each Receipt Point to which such fees applied during such Month and the aggregate amount of the Receipt Point Gathering Fees applicable to such Receipt Point for such Month.”

4. Governing Law. This Amendment shall be governed, interpreted and construed in accordance with the laws of the State of Texas without regard to the conflicts of laws provisions thereof.

5.Counterpart Execution. This Amendment may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument. Any signature delivered by a Party by facsimile transmission or electronically shall be deemed an original signature.

6. Integration with Agreement. This Amendment shall be and hereby is incorporated into and forms a part of the Agreement. Except as expressly provided herein, all terms and conditions of the Agreement shall remain in full force and effect.

[signature page follows]

2

IN WITNESS WHEREOF, each of the Parties has duly executed this Amendment as of the date first written above.

MRD Operating LLC
By:	Memorial Resource Development Corp., its sole member
By:	/s/ Kyle N. Roane
Name:	Kyle N. Roane
Title:	Senior Vice President
PennTex North Louisiana, LLC
By:	/s/ Robert O. Bond
Name:	Robert O. Bond
Title:	Chief Operating Officer

[Signature Page to Amendment No. 1 to Gas Gathering Agreement]

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, John A. Weinzierl, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Memorial Resource Development Corp. (the “registrant”);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 5, 2015	/s/ John A. Weinzierl
	John A. Weinzierl
	Chief Executive Officer
	Memorial Resource Development Corp.

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Andrew J. Cozby, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Memorial Resource Development Corp. (the “registrant”);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 5, 2015	/s/ Andrew J. Cozby
	Andrew J. Cozby
	Senior Vice President & Chief Financial Officer
	Memorial Resource Development Corp.

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Memorial Resource Development Corp. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, John A. Weinzierl, Chief Executive Officer of Memorial Resource Development Corp. and Andrew J. Cozby, Senior Vice President & Chief Financial Officer of Memorial Resource Development Corp., certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to their knowledge:

	(1)	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
	(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date:  August 5, 2015			/s/ John A. Weinzierl
			John A. Weinzierl
			Chief Executive Officer
			Memorial Resource Development Corp.
Date:  August 5, 2015			/s/ Andrew J. Cozby
			Andrew J. Cozby
			Senior Vice President & Chief Financial Officer
			Memorial Resource Development Corp.

The foregoing certifications are being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, are not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and are not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

XML

Background, Organization and Basis of Presentation - Additional Information (Detail) $ in Millions	1 Months Ended	6 Months Ended
	Feb. 28, 2015 USD ($)	Jun. 30, 2015 Segment
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%

XML

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

XML

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

XML

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

XML

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.

XML

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

XML

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

XML

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

XML

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)

XML

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

XML

Long Term Debt - Borrowing Base Credit Facility (Detail) $ in Thousands	Jun. 30, 2015 USD ($)
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

XML

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)

XML

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

XML

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

XML

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

XML

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	)

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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	$ 12.0
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

XML

Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) - USD ($)		6 Months Ended
	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

XML

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

XML

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.

XML

Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail)	6 Months Ended
	Jun. 30, 2015 shares
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)

XML

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

XML

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

XML

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

XML

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. 01, 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 01, 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. 01, 2022
Debt interest rate		6.875%
Estimated fair value of fixed rate debt		$ 454,800,000	$ 380,000,000

XML

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)

XML

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

XML

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.

XML

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 to include a new note containing condensed consolidating financial information.

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.

XML

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.

XML

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)

XML

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

XML

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

XML

Related Party Transactions - Additional Information (Detail) $ in Millions				1 Months Ended		3 Months Ended	6 Months Ended
	Apr. 14, 2015 USD ($)	Mar. 28, 2014 USD ($)	Mar. 10, 2014 USD ($)	May. 31, 2014 $ / MMBTU $ / bbl	Nov. 30, 2011 MMBTU / d	Jun. 30, 2015 USD ($) $ / MMBTU	Jun. 30, 2015 USD ($) MMBTU / d $ / MMBTU $ / gal	Feb. 28, 2014 USD ($)
Gas Gathering Agreement [Member] | Classic Operating And Classic Pipeline [Member]
Related Party Transaction [Line Items]
Pipeline transportation agreement expiration year					2020
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							$ 1.0
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	$ 55.0
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

XML

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

XML

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	$ (5.00)	$ (5.00)

XML

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

XML

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%

XML

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

XML

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

XML

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

XML

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	)

XML

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			—

XML

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

XML

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.

XML

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

XML

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.

XML

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	2015
Document Fiscal Period Focus	Q2
Trading Symbol	MRD
Entity Registrant Name	MEMORIAL RESOURCE DEVELOPMENT CORP.
Entity Central Index Key	0001599222
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		191,532,159

XML

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

XML

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

XML

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)	$ (5.00)	$ 0.12	$ (5.00)
Diluted	$ (0.14)	$ (5.00)	$ 0.12	$ (5.00)
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

XML

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

XML

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

XML

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.

XML

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 – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

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.

XML

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

XML

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.

XML

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

XML

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

XML

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

XML

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.

XML

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)	$ (5.00)	$ 0.12	$ (5.00)
Diluted EPS	$ (0.14)	$ (5.00)	$ 0.12	$ (5.00)

XML

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

XML

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	$ 19.00
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	19.00
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

XML

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

XML

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

XML

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

XML

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.

XML

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

XML

Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail) - Jun. 30, 2015		MMBTU $ / MMBTU $ / bbl bbl
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		4.00
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		85.00
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		85.00
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		85.00
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		80.00
Weighted-average ceiling price | $ / bbl		94.00
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		4.00
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		80.00
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		4.00
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.

XML

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

XML

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)

XML

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.

XML

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Jun. 30, 2015 USD ($)
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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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	)