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, 2016

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	þ	Accelerated filer	¨
Non-accelerated filer	¨ (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 13, 2016, the registrant had 206,038,313 shares of common stock, $.01 par value, outstanding

MemORIAL RESOURCE DEVELOPMENT CORP.

Table of Contents

		Page
	Glossary of Oil and Natural Gas Terms	2
	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, 2016 and December 31, 2015	8
	Unaudited Condensed Statements of Consolidated Operations for the Three and Six Months Ended June 30, 2016 and 2015	9
	Unaudited Condensed Statements of Consolidated Cash Flows for the Six Months Ended June 30, 2016 and 2015	10
	Unaudited Condensed Statements of Consolidated Equity for the Six Months Ended June 30, 2016 and 2015	11
	Notes to Unaudited Condensed Consolidated Financial Statements
	Note 1 – Background, Organization and Basis of Presentation	12
	Note 2 – Summary of Significant Accounting Policies	13
	Note 3 – Discontinued Operations	15
	Note 4 – Acquisitions and Divestitures	16
	Note 5 – Fair Value Measurements of Financial Instruments	17
	Note 6 – Risk Management and Derivative and Other Financial Instruments	18
	Note 7 – Asset Retirement Obligations	20
	Note 8 – Long Term Debt	21
	Note 9 – Stockholders’ Equity and Noncontrolling Interests	22
	Note 10 – Earnings per Share	23
	Note 11 – Long-Term Incentive Plans	23
	Note 12 – Incentive Units	24
	Note 13 – Related Party Transactions	24
	Note 14 – Commitments and Contingencies	25
	Note 15 – Income Taxes	27
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	36
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosures	38
Item 5.	Other Information	38
Item 6.	Exhibits	38
Signatures		39

1

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.

2

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.

3

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 provisions 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.

4

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;

· “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;

· “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;

· “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; and

· “Classic Pipeline” refers to Classic Pipeline & Gathering, LLC, a subsidiary of MRD Holdco that owned 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:

· risks related to the proposed merger with Range Resources Corporation;

· 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;

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

· potential changes to certain favorable tax deductions available to oil and natural gas exploration and production operations due to future legislative actions.

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, 2015 (our “2015 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,
	2016			2015
ASSETS
Current assets:
Cash and cash equivalents	$	10		$	—
Accounts receivable		62,174			52,691
Short-term derivative instruments		98,594			227,991
Other financial instruments (Note 6)		27,253			46,106
Prepaid expenses and other current assets		3,381			3,375
Assets of discontinued operation (Note 3)		—			345,541
Total current assets		191,412			675,704
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method (Note 2)		2,409,611			2,160,008
Other		12,256			22,822
Accumulated depreciation, depletion and impairment		(559,930	)		(438,383	)
Property and equipment, net		1,861,937			1,744,447
Long-term derivative instruments		36,514			91,291
Other long-term assets		10,833			4,976
Assets of discontinued operation (Note 3)		—			2,566,431
Total assets	$	2,100,696		$	5,082,849
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	25,697		$	25,057
Accounts payable - affiliates		8,062			5,016
Revenues payable		34,117			34,026
Accrued liabilities  (Note 2)		72,064			68,876
Liabilities of discontinued operation (Note 3)		—			91,779
Total current liabilities		139,940			224,754
Long-term debt		1,103,902			1,012,064
Asset retirement obligations		10,779			10,079
Deferred tax liabilities		149,355			193,733
Other long-term liabilities		3,083			7,195
Liabilities of discontinued operation (Note 3)		—			2,167,103
Total liabilities		1,407,059			3,614,928
Commitments and contingencies (Note 14)
Equity:
Stockholders' equity:
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; 206,038,313 shares issued and outstanding at June 30, 2016; 205,293,743 shares issued and outstanding at December 31, 2015		2,060			2,053
Additional paid-in capital		1,627,780			1,560,949
Accumulated earnings (deficit)		(936,203	)		(740,175	)
Total stockholders' equity		693,637			822,827
Noncontrolling interests		—			645,094
Total equity		693,637			1,467,921
Total liabilities and equity	$	2,100,696		$	5,082,849

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

8

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(In thousands, except per share amounts)

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Revenues:
Oil & natural gas sales	$	98,986		$	78,605		$	180,064		$	165,628
Total revenues		98,986			78,605			180,064			165,628
Costs and expenses:
Lease operating		8,189			3,854			14,903			9,076
Gathering, processing, and transportation		23,353			14,289			45,294			29,052
Gathering, processing, and transportation - affiliate (Note 13)		13,456			3,813			27,643			3,813
Exploration		4,612			2,230			7,058			2,956
Taxes other than income		2,991			3,140			5,855			5,915
Depreciation, depletion, and amortization		65,558			35,827			125,357			76,359
Incentive unit compensation expense (benefit) (Note 12)		74,329			16,116			52,569			26,340
General and administrative		24,021			10,323			35,154			23,299
Accretion of asset retirement obligations		156			93			295			216
(Gain) loss on commodity derivative instruments		90,617			30,463			54,175			(77,727	)
(Gain) loss on sale of properties		—			50			50			50
Total costs and expenses		307,282			120,198			368,353			99,349
Operating income (loss)		(208,296	)		(41,593	)		(188,289	)		66,279
Other income (expense):
Interest expense, net		(12,767	)		(9,613	)		(24,124	)		(19,369	)
Other, net		(112	)		(52	)		(108	)		(101	)
Total other income (expense)		(12,879	)		(9,665	)		(24,232	)		(19,470	)
Income (loss) before income taxes		(221,175	)		(51,258	)		(212,521	)		46,809
Income tax benefit (expense)		25,342			24,644			22,405			(22,914	)
Net income (loss) from continuing operations		(195,833	)		(26,614	)		(190,116	)		23,895
Discontinued Operations: (Note 3)
Income (loss) before income taxes		(122,425	)		(112,983	)		(160,426	)		(278,011	)
Income tax benefit (expense)		—			(876	)		(96	)		1,494
Net income (loss) from discontinued operations		(122,425	)		(113,859	)		(160,522	)		(276,517	)
Net income (loss)		(318,258	)		(140,473	)		(350,638	)		(252,622	)
Net income (loss) attributable to noncontrolling interest		(122,297	)		(113,771	)		(160,354	)		(274,666	)
Net income (loss) attributable to Memorial Resource    Development Corp.		(195,961	)		(26,702	)		(190,284	)		22,044
Net (income) allocated to participating restricted stockholders		—			—			—			(150	)
Net (income) loss from discontinued operations		128			88			168			227
Net income (loss) from continuing operations available to common stockholders	$	(195,833	)	$	(26,614	)	$	(190,116	)	$	22,121
Earnings per common share-basic: (Note 10)
Income (loss) from continuing operations	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Income (loss) from discontinued operations	$	—		$	—		$	—		$	—
Net income (loss)	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Earnings per common share-diluted: (Note 10)
Income (loss) from continuing operations	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Income (loss) from discontinued operations	$	—		$	—		$	—		$	—
Net income (loss)	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Weighted average common and common    equivalent shares outstanding:
Basic		203,948			189,628			203,807			190,163
Diluted		203,948			189,628			203,807			190,163

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

9

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

 (In thousands)

	For the Six Months Ended
	June 30,
	2016			2015
Cash flows from operating activities:
Net income (loss)	$	(350,638	)	$	(252,622	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
(Income) loss from discontinued operations		160,522			276,517
Depreciation, depletion, and amortization		125,357			76,359
(Gain) loss on derivatives		54,175			(77,727	)
Cash settlements (paid) received on expired derivative instruments		130,000			70,288
Amortization of deferred financing costs		1,560			1,333
Accretion of asset retirement obligations		295			216
Amortization of equity awards		13,673			3,443
(Gain) loss on sale of properties		50			50
Non-cash compensation expense		52,569			26,340
Deferred income tax expense (benefit)		(44,301	)		15,197
Exploration costs		236			—
Changes in operating assets and liabilities:
Accounts receivable		(6,849	)		3,396
Prepaid expenses and other assets		(6,678	)		4,538
Payables and accrued liabilities		23,691			37,537
Other		(1,715	)		(1,166	)
Net cash provided by continuing operations		151,947			183,699
Net cash provided by discontinued operations		139,770			118,088
Net cash provided by operating activities		291,717			301,787
Cash flows from investing activities:
Additions to oil and gas properties		(265,532	)		(207,103	)
Additions to other property and equipment		(438	)		(3,309	)
Other financial instruments		16,220			—
Proceeds from the sale of other property and equipment		4,219			—
Proceeds from the sale of oil and natural gas properties		—			13,612
Other		24			—
Net cash used in continuing operations		(245,507	)		(196,800	)
Net cash used in discontinued operations		(33,014	)		(127,644	)
Net cash used in investing activities		(278,521	)		(324,444	)
Cash flows from financing activities:
Advances on revolving credit facilities		229,000			181,000
Payments on revolving credit facilities		(138,000	)		(199,000	)
Deferred financing costs		(38	)		—
Proceeds from sale of subsidiaries		750			—
MRD equity repurchases		(5,748	)		(51,197	)
Net cash used in continuing operations		85,964			(69,197	)
Net cash provided by (used in) discontinued operations		(86,365	)		90,597
Net cash provided by (used in) financing activities		(401	)		21,400
Net change in cash and cash equivalents		12,795			(1,257	)
Add: cash balance included in assets of discontinued operations at beginning of period		2,175			2,594
Less: cash balance included in assets of discontinued operations at May 31, 2016 and June 30, 2015		14,960			4,701
Cash and cash equivalents, beginning of period		—			3,364
Cash and cash equivalents, end of period	$	10		$	—

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

10

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(In thousands)

	Stockholders' Equity
	Common stock			Additional paid in capital			Accumulated earnings (deficit)			Noncontrolling Interest			Total
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 15)		—			28,020			—			—			28,020
Distributions		—			—			—			(92,477	)		(92,477	)
Amortization of MEMP equity awards		—			—			—			4,906			4,906
MRD restricted shares repurchased		(1	)		—			(1,195	)		—			(1,196	)
MEMP common units repurchased		—			—			—			(45,117	)		(45,117	)
Other		—			(47	)		—			30			(17	)
Balance, June 30, 2015	$	1,915		$	1,297,944		$	(813,779	)	$	840,379		$	1,326,459
Balance, January 1, 2016	$	2,053		$	1,560,949		$	(740,175	)	$	645,094		$	1,467,921
Net income (loss)		—			—			(190,284	)		(160,354	)		(350,638	)
Restricted stock awards		11			(11	)		—			—			—
Amortization of restricted stock awards		—			13,673			—			—			13,673
Contribution (distribution) related to MRD Holdco incentive units (Note 12)		—			52,569			—			—			52,569
Distributions		—			—			—			(8,295	)		(8,295	)
Restricted stock awards returned to plan		(4	)		—			(5,744	)		—			(5,748	)
Amortization of MEMP equity awards		—			—			—			4,218			4,218
MEMP restricted units repurchased		—			—			—			(90	)		(90	)
Adjustments from deconsolidation of subsidiaries (Note 9)		—			—			—			(480,165	)		(480,165	)
Other		—			600			—			(408	)		192
Balance, June 30, 2016	$	2,060		$	1,627,780		$	(936,203	)	$	—		$	693,637

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

11

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED 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; (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) “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 (v) “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.

Basis of Presentation

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Under the amended consolidation guidance that we adopted on January 1, 2016 (see Note 2), a limited partnership is considered a variable interest entity (“VIE”) unless a single limited partner or a simple majority of all partners have substantive kick-out or participating rights. The Company determined that MEMP was a VIE and we were deemed the primary beneficiary. On June 1, 2016, we completed the sale of MEMP GP, Beta Operating Company, LLC (“Beta Operating”) and MEMP Services LLC (“Services”) (collectively, the “Disposition Entities”), to MEMP for $0.75 million in cash. This sale was a reconsideration event under the amended consolidation guidance which resulted in the deconsolidation of the Partnership. Our equity statement reflects a loss of $0.1 million related to the deconsolidation of the Disposition Entities and their subsidiaries. Our financial statements have been retrospectively revised to reflect the Disposition Entities and their subsidiaries as discontinued operations for all periods presented (see Note 3). After the completion of the sale, we have one reportable business segment, which is engaged in the acquisition, exploration and development of oil and natural gas properties.  

All material intercompany transactions and balances have been eliminated in preparation of our consolidated financial statements. Our results of operations for the three and six months ended June 30, 2016 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”).

Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to the  acquisition by MEMP of certain assets from the Company in East Texas in February 2015 for certain properties in North Louisiana (the “Property Swap”).

Proposed Merger with Range Resources Corporation

On May 15, 2016, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Range Resources Corporation (“Range”), a Delaware corporation, and Medina Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of Range (“Merger Sub”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth, the Merger Sub will be merged with and into the Company, with the Company continuing as the surviving entity and a wholly owned subsidiary of Range (“the Merger”).

If the Merger is completed, each share of our common stock outstanding immediately before that time (including outstanding shares of our restricted common stock, all of which will become fully vested and unrestricted under the terms of the Merger Agreement) will automatically be converted into the right to receive 0.375 of a share of Range common stock, par value of $0.01 per share (“Range Common Stock”). The Merger is subject to customary closing conditions, including the approval by both Memorial and Range stockholders. We expect the closing of the Merger will occur late in the third quarter of 2016.

12

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In connection with the execution of the Merger Agreement, MRD Holdco, Jay Graham (our chief executive officer), Anthony Bahr and WHR Incentive LLC (a limited liability company controlled by Mr. Graham and Mr. Bahr) (collectively, the “Memorial Stockholders”) entered into a voting and support agreement with Range and have agreed to vote all of the shares held by them in favor of the approval and adoption of the Merger Agreement and the transactions contemplated by the Merger Agreement, including the merger. As of June 30, 2016, the Memorial Stockholders hold and are entitled to vote in the aggregate approximately 47.7% of the issued and outstanding shares of our common stock entitled to vote at our special meeting.  In addition, certain other stockholders of the Company who are not party to the voting and support agreement are party to an existing voting agreement, as discussed in our 2015 Form 10-K, pursuant to which those stockholders are required to vote all of the shares of our common stock that they own as directed by MRD Holdco. As of June 30, 2016, those additional stockholders hold and are entitled to vote in the aggregate approximately 2.7% of the outstanding shares of our common stock entitled to vote at our special meeting.

Upon completion of the Merger, our common stock currently listed on the NASDAQ will cease to be listed for trading on the NASDAQ and will subsequently be deregistered under the Securities Exchange Act of 1934, as amended.

Use of Estimates

The preparation of the accompanying unaudited condensed consolidated 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 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; realization of long-term prepaid processing fees; 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 2015 Form 10-K.

Oil and Natural Gas Properties

Oil and natural gas properties consisted of the following at the dates indicated (in thousands):

	June 30,		December 31,
	2016		2015
	(In thousands)
Proved oil and natural gas properties	$	1,984,500	$	1,740,530
Support equipment and facilities		7,191		4,719
Unproved oil and natural gas properties		417,920		414,759
Total oil and natural gas properties	$	2,409,611	$	2,160,008

At June 30, 2016 and December 31, 2015, we had $147.4 million and $174.0 million, respectively, capitalized in proved oil and natural gas properties related to wells in various stages of drilling and completion, which have been excluded from the depletion base.

13

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Accrued liabilities

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

	June 30,		December 31,
	2016		2015
Accrued capital expenditures	$	24,084	$	40,197
Accrued interest payable		17,665		17,657
Accrued lease operating expense		1,414		2,031
Accrued general and administrative expenses		5,871		4,030
Accrued ad valorem taxes		1,619		157
Accrued current income taxes		20,007		1,911
Other miscellaneous, including operator advances		1,404		2,893
Total accrued liabilities	$	72,064	$	68,876

Supplemental Cash Flow Information

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

	For the Six Months Ended
	June 30,
	2016			2015
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	22,418		$	35,650
Cash paid for taxes		3,800			2,000
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(16,113	)		25,560
(Increase) decrease in accounts receivable related to other financial instruments		2,633			—
Assumptions of asset retirement obligations related to properties acquired or drilled		530			—

New Accounting Pronouncements

Improvements to Employee Share-Based Payment Accounting. In March 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in additional paid-in capital (“APIC”). Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement and the APIC pools will be eliminated. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before companies can recognize them and requires companies to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires a company to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, companies will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required.  

The new guidance is effective for reporting periods beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. The Company is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively.

14

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Leases. In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company is currently evaluating the standard and the impact on the Company’s financial statements and related footnote 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. We adopted this guidance on January 1, 2016 and determined that MEMP was a VIE for which the Company is the primary beneficiary for accounting purposes. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements. On June 1, 2016, we completed the sale of the Disposition Entities to MEMP as discussed in Note 1, which triggered a reconsideration event under the guidance which resulted in the deconsolidation of the Partnership.  

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. Discontinued Operations

As previously discussed in Note 1, we sold the Disposition Entities and their subsidiaries on June 1, 2016 to MEMP. Below is a reconciliation of carrying amounts of major classes of assets and liabilities included as part of discontinued operations as reflected on the balance sheet associated with this disposal transaction (in thousands):

	December 31,
	2015
ASSETS
Current assets:
Cash and cash equivalents	$	2,175
Accounts receivable		61,404
Short-term derivative instruments		272,320
Prepaid expenses and other current assets		9,642
Total current assets		345,541
Property and equipment, net		1,946,937
Long-term derivative instruments		461,810
Restricted investments		152,631
Other long-term assets		5,053
Total assets	$	2,911,972
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,792
Accounts payable - affiliates		193
Revenues payable		27,021
Accrued liabilities		52,923
Short-term derivative instruments		2,850
Total current liabilities		91,779
Long-term debt		2,000,579
Asset retirement obligations		162,989
Long-term derivative instruments		1,441
Deferred tax liabilities		2,094
Total liabilities	$	2,258,882

15

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Below is a reconciliation of major line items constituting pretax profit (loss) of discontinued operations to the after tax profit (loss) of discontinued operations that are presented in the statement of operations (in thousands):

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Revenues:
Oil & natural gas sales	$	43,806		$	97,221		$	104,429		$	189,170
Other revenues		186			917			429			1,786
Total revenues		43,992			98,138			104,858			190,956
Costs and expenses:
Lease operating		19,347			44,888			55,043			85,366
Gathering, processing, and transportation		6,166			9,548			15,375			18,214
Exploration		3			32			125			122
Taxes other than income		2,534			6,058			6,542			12,713
Depreciation, depletion, and amortization		29,954			46,286			74,383			97,552
Impairment of proved oil and natural gas properties		—			—			8,342			251,347
General and administrative (1)		9,092			14,377			22,616			28,888
Accretion of asset retirement obligations		1,828			1,686			4,535			3,320
(Gain) loss on commodity derivative instruments		104,365			61,403			52,620			(84,056	)
(Gain) loss on sale of properties		—			—			(96	)		—
Other, net		—			(943	)		119			(943	)
Total costs and expenses		173,289			183,335			239,604			412,523
Operating income (loss)		(129,297	)		(85,197	)		(134,746	)		(221,567	)
Other income (expense):
Interest expense, net		(19,142	)		(27,910	)		(51,694	)		(56,728	)
Other, net		26,014			124			26,014			284
Total other income (expense)		6,872			(27,786	)		(25,680	)		(56,444	)
Pretax profit (loss) of discontinued operations		(122,425	)		(112,983	)		(160,426	)		(278,011	)
Income tax benefit (expense)		—			(876	)		(96	)		1,494
Net income (loss) from discontinued operations	$	(122,425	)	$	(113,859	)	$	(160,522	)	$	(276,517	)

(1) Included $4.4 million and $12.2 million, for the three and six months ended June 30, 2016; and $8.5 million and $17.0 million for the three and six months ended June 30, 2015 that was allocated to discontinued operations under an omnibus agreement.  This omnibus agreement was terminated on June 1, 2016, and we entered into a transition services agreement (“TSA”) with MEMP to manage post-closing separation costs and activities through February 2017. At June 30, 2016, we owed MEMP approximately $1.9 million under the TSA.

In connection with the sale of the Disposition Entities, we received $4.2 million from MEMP for the sale of furniture, fixtures, and other property and equipment. We also received an additional $5.4 million from MEMP related to both the settlement of a receivable that had been previously eliminated in consolidation and prepaid expenses. We paid MEMP approximately $1.9 million, which represented a settlement related to corporate office space.

Note 4. Acquisitions and Divestitures

Transaction-related costs, which include costs associated with our proposed Merger with Range, 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,
2016		2015		2016		2015
$	6,179	$	126	$	6,209	$	1,407

2016 Acquisitions and Divestitures

There were no material acquisitions during the three and six months ended June 30, 2016. In addition, there were no material divestitures during the three and six months ended June 30, 2016, except for the Disposition Entities and their subsidiaries as discussed in Note 1.

2015 Acquisition and Divestitures

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 (the “Rockies Divestiture”) and recorded a gain of less than $0.1 million related to the sale.

16

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On June 1, 2015, we entered into an oil and gas lease option agreement with a third party pursuant to which we have the right to obtain one or more oil and gas leases in North Louisiana. The option is exercisable through February 2017. The purchase price of this option was approximately $4.0 million. The purchase price has been capitalized as part of unproved properties and will be expensed if the option is not exercised.

Note 5. 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), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at June 30, 2016 and December 31, 2015. 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, 2016 and December 31, 2015 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, 2016 and December 31, 2015 for each of the fair value hierarchy levels:

	Fair Value Measurements at June 30, 2016 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	$	—	$	135,658	$	—	$	135,658
Liabilities:
Commodity derivatives	$	—	$	550	$	—	$	550

	Fair Value Measurements at December 31, 2015 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	319,762	$	—	$	319,762
Liabilities:
Commodity derivatives	$	—	$	480	$	—	$	480

See Note 6 for additional information regarding our derivative instruments.

17

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 7 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. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach.

· Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate 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.

Note 6. Risk Management and Derivative and Other Financial Instruments

Derivative and other financial 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 and other financial instruments, 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, and other financial instruments 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 and other financial instruments is minimized by limiting exposure to any single counterparty and entering into derivative and other financial 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 or other financial 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 or other financial instrument, 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, 2016, we had net derivative and other financial assets of $162.4 million. After taking into effect netting arrangements, we had counterparty exposure of $16.6 million related to derivative and other financial instruments of which all was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $145.8 million against amounts outstanding under our revolving credit facility at June 30, 2016. See Note 8 for additional information regarding our revolving credit facility.

Commodity Derivatives and Other Financial Instruments

We may use a combination of commodity derivatives and other financial instruments (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, 2016 is net of deferred premiums of $10.5 million.

18

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During the year ended December 31, 2015, we restructured our existing 2018 crude oil and natural gas hedges for crude oil and NGL swaps that will settle in 2016. Cash settlements of approximately $92.3 million from the terminated 2018 positions were received and applied as premiums for the new crude oil and NGL swaps. Certain contracts are classified as other financial instruments, which required bifurcation, based on the relationship between the fixed swap price and the market price at the restructure dates. Due to bifurcation, $27.3 million of the restructured contracts represents other financial assets at June 30, 2016.

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as TGT Z1 in proximity to our areas of production. We also enter into oil derivative contracts indexed primarily to NYMEX-WTI. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

At June 30, 2016, we had the following open commodity positions (excluding embedded derivatives):

	Remaining
	2016			2017
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,120,000			1,770,000
Weighted-average fixed price	$	4.06		$	4.24
Collar contracts:
Average Monthly Volume (MMBtu)		1,000,000			1,050,000
Weighted-average floor price	$	4.00		$	4.00
Weighted-average ceiling price	$	4.71		$	5.06
Purchased put option contracts:
Average Monthly Volume (MMBtu)		6,700,000			5,350,000
Weighted-average strike price	$	3.54		$	3.48
Weighted-average deferred premium	$	(0.34	)	$	(0.32	)
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		1,120,000			200,000
Spread - Henry Hub	$	(0.10	)	$	(0.08	)
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		32,833			28,000
Weighted-average fixed price	$	83.91		$	84.70
Collar contracts:
Average Monthly Volume (Bbls)		26,600			—
Weighted-average floor price	$	80.00		$	—
Weighted-average ceiling price	$	99.70		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		366,758			—
Weighted-average fixed price	$	39.93		$	—

19

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At June 30, 2016, we had the following open embedded derivative positions:

	Remaining
	2016
Oil Hybrid Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		27,211
Weighted-average fixed price	$	46.50
Initial net investment price		62.29
Total contract swap price	$	108.79
NGL Hybrid Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		111,175
Weighted-average fixed price	$	15.77
Initial net investment price		25.61
Total contract swap price	$	41.38

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, 2016 and December 31, 2015. 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	2016			2015			2016			2015
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	98,937		$	228,349		$	343		$	358
Netting arrangements	Short-term derivative instruments		(343	)		(358	)		(343	)		(358	)
Net recorded fair value	Short-term derivative instruments	$	98,594		$	227,991		$	—		$	—
Commodity contracts	Long-term derivative instruments	$	36,721		$	91,413		$	207		$	122
Netting arrangements	Long-term derivative instruments		(207	)		(122	)		(207	)		(122	)
Net recorded fair value	Long-term derivative instruments	$	36,514		$	91,291		$	—		$	—

(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 periods indicated (in thousands):

		For the Three Months Ended				For the Six Months Ended
	Statements of	June 30,				June 30,
	Operations Location	2016		2015		2016		2015
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	90,617	$	30,463	$	54,175	$	(77,727	)

Note 7. 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, 2016 (in thousands):

Asset retirement obligations at beginning of period	$	10,079
Liabilities added from acquisitions or drilling		530
Revision of estimates		(125	)
Accretion expense		295
Asset retirement obligations at end of period	$	10,779

20

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Long Term Debt

The following table presents our consolidated debt obligations at the dates indicated:

	June 30,			December 31,
	2016			2015
	(In thousands)
$2.0 billion revolving credit facility, variable-rate, due June 2019	$	514,000		$	423,000
5.875% senior unsecured notes, due July 2022 ("Senior Notes") (1) (2)		600,000			600,000
Unamortized debt issuance costs		(10,098	)		(10,936	)
Total long-term debt	$	1,103,902		$	1,012,064

(1) The estimated fair value of this fixed-rate debt was $598.5 million and $525.0 million at June 30, 2016 and December 31, 2015, respectively.  

(2) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

On May 31, 2016, we entered into a sixth amendment to our revolving credit facility to, among other things, permit the sale of MEMP GP, Beta Operating and Services to MEMP.  Effective June 1, 2016, Beta Operating was automatically released as a guarantor and discharged from any and all obligations under or in connection with our revolving credit facility or other related loan documents. The liens on and security interests in the equity interests owned by us in each of MEMP GP, Beta Operating, and Services, and the mortgaged property owned by Beta Operating were automatically released.

Senior Notes

Effective June 1, 2016, the guarantor subsidiaries are 100% owned by the Company; the Company has no material assets or operations independent of the guarantor subsidiaries; and there are no significant restrictions upon the ability of the guarantor subsidiaries to distribute funds to the Company. Additionally, our Senior Notes are jointly and severally, fully and unconditional guaranteed (subject to customary release provisions) by the guarantor subsidiaries.

Borrowing Base

Credit facilities tied to borrowing base are common throughout the oil and gas industry. Our revolving credit facility borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for our credit facility was the following at the date indicated (in thousands):

	June 30,
	2016
$2.0 billion revolving credit facility, variable-rate, due June 2019	$	1,000,000

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,
	2016			2015			2016			2015
Revolving credit facility (1)		2.49	%		1.70	%		2.38	%		1.80	%

(1) As noted in the 2015 10-K, the Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the three months and six months ended for June 30, 2016 was 2.00% and 1.90%, respectively.  The Applicable Margin for the three months and six months ended June 30, 2015, was 1.50% and 1.57%, respectively.

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,
	2016		2015
	(In thousands)
Revolving credit facility	$	4,292	$	4,976
Senior Notes		10,098		10,936
Total unamortized deferred financing costs		14,390		15,912

21

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2016:

Balance December 31, 2015	205,293,743
Restricted common shares issued (Note 11)	1,117,606
Restricted common shares repurchased (1)	(363,159	)
Restricted common shares forfeited	(9,877	)
Balance June 30, 2016	206,038,313

(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 $5.7 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

The Company 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. We have 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 was not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which could have been suspended or discontinued at any time. The Company did not repurchase any shares of common stock under the April 2015 repurchase program. The April 2015 repurchase program expired in April 2016.

Noncontrolling Interests

Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consisted of the equity interests held by: (i) the limited partners of MEMP prior to June 1, 2016 (see Note 1) and (ii) a third party investor in the San Pedro Bay Pipeline Company prior to November 3, 2015.  

Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. These distributions and contributions are a component of net cash provided by discontinued operations from financing activities as presented on our cash flow statement.

22

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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,
	2016			2015			2016			2015
Numerator:
Net income (loss) from continuing operations available to common stockholders	$	(195,833	)	$	(26,614	)	$	(190,116	)	$	22,121
Net income (loss) from discontinued operations available to common stockholders		128			88			168			227
Denominator:
Weighted average common shares outstanding		203,948			189,628			203,807			190,163
Incremental treasury stock method shares (1)		310			364			39			329
Basic EPS from continuing operations	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Diluted EPS from continuing operations (1)	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Basic EPS from discontinued operations	$	—		$	—		$	—		$	—
Diluted EPS from discontinued operations (1)	$	—		$	—		$	—		$	—

(1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. The incremental treasury stock method shares were excluded from the computation of diluted EPS because the inclusion of such shares would have been anti-dilutive.

Note 11. Long-Term Incentive Plans

The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan (“LTIP”) for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2015		1,668,845		$	18.89
Granted (2)		1,117,606		$	13.13
Forfeited		(9,877	)	$	18.84
Vested		(1,145,885	)	$	18.87
Restricted common shares outstanding at June 30, 2016 (3)		1,630,689		$	14.96

(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 2016 was $14.7 million based on a grant date market price ranging from $13.08 to $15.58 per share.

(3) Effective immediately prior to the effective time of the Merger, each outstanding share of our unvested restricted common stock will fully vest and any applicable restrictions will lapse and, at the effective time of the Merger, each such share will be treated as a share of our common stock, including with respect to the right to receive 0.375 of a fully vested share of Range Common Stock.

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,
2016		2015		2016		2015
$	10,521	$	1,957	$	13,673	$	3,443

The unrecognized compensation cost associated with restricted common share awards was $23.2 million at June 30, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.44 years.

23

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

LTIP Modification. On March 9, 2016, certain employees were impacted by an involuntary termination which, upon the Board’s approval, accelerated the vesting schedule of unvested awards under the LTIP that otherwise would have been forfeited upon a voluntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of $1.1 million was recognized.

On June 1, 2016, with the completion of the sale of the Disposition Entities and their subsidiaries to MEMP as discussed in Note 1, we accelerated the vesting schedule of unvested awards under the LTIP for the employees that remained with the Disposition Entities and their subsidiaries. The grant-date fair value compensation cost of approximately $2.5 million was reversed and the modified-date grant fair value compensation cost of $9.8 million was recognized.

Note 12. Incentive Units

MRD Holdco

MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in exchange for cancelled predecessor 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 compensation expense of $74.3 million and $52.6 million for the three and six months ended June 30, 2016, respectively, offset by a deemed capital contribution to MRD Holdco. The unrecognized compensation expense of approximately $6.2 million as of June 30, 2016 will be recognized over the remaining expected service period of 0.25 years.

The fair value of the Exchanged Incentive Units 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, adjustments to non-cash compensation expense will be allocated to us in future periods offset by deemed capital contributions or distributions. As such, these awards are not dilutive to our stockholders.

The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:

	Exchanged Incentive Units			Subsequent Incentive Units
Valuation date	6/30/2016			6/30/2016
Dividend yield		0	%		0	%
Expected volatility		55.00	%		55.00	%
Risk-free rate		0.26	%		0.26	%
Expected life (years)		0.25			0.25

Note 13. Related Party Transactions

Amounts due to MRD Holdco and certain affiliates of NGP at June 30, 2016 and December 31, 2015 are presented as “Accounts payable – affiliates” in the accompanying balance sheets.

NGP Affiliated Companies

During the three and six months ended June 30, 2016, we paid approximately $0.5 million and $3.8 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities.

During the three and six months ended June 30, 2016, we paid approximately $1.1 million and $3.5 million, respectively, to Multi-Shot, LLC, a NGP affiliated company, for services related to our drilling and completion activities, of which less than $0.1 million was attributable to discontinued operations.

During the three months ended June 30, 2016, we also paid a NGP affiliate company approximately $1.1 million for mineral interests located in North Louisiana.

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 and Voting Agreement

A discussion of these agreements is included in our 2015 Form 10-K.

24

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Services Agreement

A discussion of this agreement is included in our 2015 Form 10-K. The services agreement was terminated effective March 1, 2015. During the six months ended June 30, 2015, we recognized approximately $2.0 million of general and administrative expenses under this agreement.  

Midstream Agreements

We have various midstream service agreements with affiliates of PennTex Midstream Partners, LP (“PennTex”), an affiliate of NGP, for the gathering, processing and transportation of natural gas and NGLs. Additionally, we entered into an area of mutual interest and exclusivity agreement (“AMI”) with PennTex pursuant to which PennTex has the exclusive right to provide midstream services to support our current and future production in North Louisiana on our operated acreage within such area (other than production subject to existing third-party commitments). A discussion of these agreements is included in our 2015 Form 10-K.

Pursuant to the gas processing agreement, any deficiency payments made by the Company under this agreement will be treated as prepaid processing fees by PennTex (except for the June 2015 deficiency payment) because we may utilize these deficiency payments as credit for fees owed if we have delivered the total minimum volume commitment under the processing agreement within the initial term of the agreement. We must pay a quarterly deficiency payment based on the firm-commitment fixed fee if the cumulative minimum volume commitment as of the end of such quarter exceeds the sum of (i) the cumulative volumes processed (or credited with respect to plant interruptions) under the processing agreement as of the end of such quarter plus (ii) volumes corresponding to deficiency payments incurred prior to such quarter. During the three and six months ended June 30, 2016, we incurred $3.2 million and $6.5 million, respectively, of deficiency payments. As of June 30, 2016, we had $6.5 million of prepaid processing fees on our balance sheet in the “Other long-term assets” line.

All net costs associated with these agreements are reflected in the statement of operations in the “Gathering, processing, and transportation – affiliate” line.

Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement

A discussion of these agreements is included in our 2015 Form 10-K. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline and Gathering, LLC’s (“Classic Pipeline”) Joaquin gathering system. Additionally, Classic Pipeline assigned its salt water disposal system to MEMP in November 2015. For the three and six months ended June 30, 2015, MEMP incurred gathering and salt water disposal fees of approximately $1.1 million and $2.0 million, respectively, under these agreements. These fees are a component of net income (loss) from discontinued operations as presented on our statement of operations.

Note 14. 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.

25

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Subsequent event. In July 2016, alleged stockholders (“Plaintiffs”) of the Company, filed two class action lawsuits against us and the members of our board of directors relating to the Merger. These lawsuits are styled (i) Roger Mariani v. Memorial Resource Development Corp., et al., Case No. 4:16-cv-2042, in the United States District Court for the Southern District of Texas, Houston Division; and (ii) Joel Morris v. Memorial Resource Development Corp., et al., Case No. 4:16-cv-02183, in the United States District Court for the Southern District of Texas, Houston Division. The Morris action also names Range and Merger Sub as additional defendants. Plaintiffs allege that the joint proxy statement/prospectus filed in connection with the Merger omits allegedly material information concerning, in general and among other things, (i) the valuation analyses prepared by Barclays Capital Inc. (“Barclays”) and Morgan Stanley & Co. LLC (“Morgan Stanley”) in connection with their fairness opinions regarding the Merger, (ii) the financial projections utilized by Barclays and Morgan Stanley and (iii) the background of the Merger. Based on these allegations, Plaintiffs allege that (i) the defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) members of our board of directors have violated Section 20(a) of the Exchange Act. Plaintiffs also allege, in general and among other things, that the terms of the Merger are (i) unfair to our stockholders and (ii) the result of an inadequate process. Based on these allegations, Plaintiffs seek to enjoin us from proceeding with or consummating the Merger. To the extent that the Merger is consummated before injunctive relief is granted, Plaintiffs seek to have the Merger rescinded. Plaintiffs also seek attorneys’ fees. Plaintiffs have not yet served the defendants, and our date to answer, move to dismiss, or otherwise respond to the lawsuit has not yet been set. We cannot predict the outcome of the lawsuits or any others that might be filed, nor can we predict the amount of time and expense that will be required to resolve the lawsuits. We intend to vigorously defend the lawsuits.

There were no environmental reserves recorded on our balance sheet at June 30, 2016 and December 31, 2015 associated with continuing operations.

Third Party Midstream Service Agreements (Gathering & Processing)

The Company has an existing amended and restated midstream service agreement with ETC Field Services LLC (formerly known as Regency Field Services LLC) (“ETC”) for the gathering and processing of natural gas in North Louisiana as discussed in our 2015 Form 10-K. ETC is entitled to receive a payback demand fee from us and other third parties equal to 110% of certain infrastructure improvement costs. The payback demand fee is based upon actual volumes gathered, but not less than a specified monthly demand quantity. Until payout is achieved, there is also a monthly demand quantity associated with gathering and processing fees.

We have the right to request that gas gathered by ETC be delivered to alternative delivery points for processing (e.g., PennTex). Under these circumstances, ETC assesses us a $0.25 per MMBtu gathering only fee to take gas off its system.

Firm Gas Transportation Service Agreement

The Company entered into a long-term firm transportation agreement with Regency Intrastate Gas LP (“RIGS”) to assure the delivery of its natural gas to market.  This agreement’s primary term terminates on December 31, 2025, subject to one-year extensions at either party’s election. This commitment requires a minimum monthly reservation charge that escalates annually by two percent regardless of whether the contracted capacity is used or not. An overrun charge that also escalates annually by two percent applies to gas received in excess of the contracted capacity. In addition to the demand and overrun fees, RIGS retains 1.25% of gas received for fuel. The following table summarizes the reserved capacity and applicable fees associated with this agreement:

Period	Reserved Capacity (MMBtu/d)		Reservation Demand Charge ($/MMBtu)		Overrun Charge ($/MMBtu)
January 1, 2016 to December 31, 2022		300,000		0.075		0.150
January 1, 2023 to December 31, 2025		200,000		0.075		0.150

In the future, additional receipt points may be developed. The following pricing grid, subject to annual escalation, would apply to gas received at any of these future receipt points.

	Reservation Demand Charge ($/MMBtu)		Commodity Charge ($/MMBtu)		Overrun Charge ($/MMBtu)
Total gas receipts ≤ contracted reserved capacity		0.075		0.075	n/a
Total gas receipts > contracted reserved capacity	n/a		n/a			0.150

26

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Sales Delivery Commitment

Recently, the Company and a third party entered into a contract whereby the Company agreed to sell and deliver NGLs produced at gas processing plants owned and operated by PennTex. The NGLs are delivered to a pipeline owned by an affiliate of the third party. The initial term of the contract terminates on December 31, 2022, subject to one-year extensions at either party’s election. The price we receive is tied to published indices, net of transportation and fractionation deductions. Commencing April 1, 2016, through the end of the initial term of the agreement, the minimum sales volume commitment is 6,000 BPD. If we fail to deliver the minimum sales volume commitment, we will be required to pay a deficiency payment equal to transportation and fractionation deductions on undelivered volumes. Currently, transportation and fractionation deductions are approximately $4.39 per barrel.

Related Party Agreements

See Note 13 for additional information.

Note 15. Income Taxes

The Company is a corporation subject to federal and state income taxes. The compensation expense associated with the incentive units of MRD Holdco (discussed in Note 12) creates a nondeductible permanent difference for income tax purposes. 

The Company’s income tax benefit from continuing operations for the three and six months ended June 30, 2016 was $25.3 million and $22.4 million, respectively, compared to $24.6 million of income tax benefit and $22.9 million of income tax expense for the three and six months ended June 30, 2015, respectively. The Company’s effective tax rate from continuing operations for the three and six months ended June 30, 2016 was 11.5% and 10.5%, respectively, compared to 48.1% and 49.0% for the three and six months ended June 30, 2015, respectively. The change in the effective tax rate from 2015 to 2016 was primarily due to a change in non-deductible incentive unit compensation as discussed in Note 12. The effective tax rate for the three and six months ended June 30, 2016 and 2015 differed from the statutory federal income tax rate primarily due to non-deductible incentive unit compensation expense, state income tax, net of federal benefit, and long-term incentive plan compensation expense.

We reported no liability for unrecognized tax benefits as of June 30, 2016 and expect no significant change to the unrecognized tax benefits in the next twelve months.

Consistent with establishing the deferred tax liability through stockholders’ equity in our initial public offering, we reversed a deferred tax liability of approximately $28.0 million through stockholders’ equity in 2015 attributable to the deferred tax effects of the Property Swap in 2015.

27

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 2015 Form 10-K filed with the SEC on February 24, 2016. 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 over-pressured, 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.

As discussed under Note 2 of the Notes to Unaudited Condensed Consolidated 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 adopted this guidance on January 1, 2016 and determined that MEMP was a VIE for which we are the primary beneficiary. On June 1, 2016, we completed the sale of MEMP GP, Beta Operating Company, LLC and MEMP Services LLC (collectively, the “Disposition Entities”), to MEMP for $0.75 million in cash. This sale was a reconsideration event under the amended consolidation guidance which resulted in the deconsolidation of the Partnership.

Prior to the sale of the Disposition Entities and its subsidiaries we had two reportable segments, one of which was MEMP and its subsidiaries. Effective June 1, 2016, we now have one reportable business segment, which is engaged in the acquisition, exploration and development of oil and natural gas properties. Accordingly, we have retrospectively revised our segment disclosures for all periods presented.

Recent Developments

Proposed Merger with Range Resource Corporation

On May 15, 2016, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”), with Range Resources Corporation, a Delaware corporation (“Range”) and a direct wholly-owned subsidiary of Range (“Merger Sub”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth, the Merger Sub will be merged with and into the Company, with the Company continuing as the surviving entity and a wholly owned subsidiary of Range (the “Merger”). If the Merger is completed, each share of our common stock outstanding immediately before that time (including outstanding shares of our restricted common stock, all of which will become fully vested and unrestricted under the terms of the Merger Agreement) will automatically be converted into the right to receive 0.375 of a share of Range common stock, par value $0.01 per share. The Merger is subject to customary closing conditions, including the approval by both Memorial and Range stockholders. We expect the closing of the Merger will occur late in the third quarter of 2016. See Note 1 and Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding the Merger.

Divestiture of MEMP GP and Related Entities

On June 1, 2016, we closed the previously announced divestiture of the Disposition Entities and their subsidiaries to MEMP for $0.75 million in cash. Our financial statements have been retrospectively revised to reflect the Disposition Entities and their subsidiaries as discontinued operations for all periods presented. See Note 1 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Borrowing Base Reaffirmation

In April 2016, the lenders under our revolving credit facility reaffirmed the borrowing base under our revolving credit facility at $1.0 billion, to remain at such level until the next scheduled redetermination, the next interim redetermination or other adjustment to the borrowing base, whichever occurs first.

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Sources of Revenues

Our 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, we 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 as well as the cost of commodity processing.

· Taxes other than income. These consist of severance, ad valorem taxes, and franchise 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 state or local taxing authorities. The Company takes full advantage of all credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural properties. Franchise taxes are privilege taxes levied by states that are imposed on companies, including limited liability companies and partnerships, which gives the businesses the right to be chartered or operate within that state.

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

· 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 Financial Statements included under “Item 1. Financial Statements” 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, audit and other professional fees, and legal compliance expenses.

· Interest expense. The Company finances a portion of its working capital requirements and acquisitions with borrowings under its revolving credit facility and senior note issuances. As a result, we 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 in future periods.

· Income tax expense. We are a corporation subject to federal and state 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; realization of long-term prepaid processing fees; 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.

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A discussion of our critical accounting policies and estimates is included in our 2015 Form 10-K. There have been no significant changes to our critical accounting policies and estimates except for the realization of long-term prepaid processing fees. Pursuant to a gas processing agreement with a related party, any deficiency payments made by the Company under this agreement will be treated as prepaid processing fees by our related party because we may utilize these deficiency payments as credit for fees owed if we have delivered the total minimum volume commitment under the processing agreement within the initial term of the agreement. We must pay a quarterly deficiency payment based on the firm-commitment fixed fee if the cumulative minimum volume commitment as of the end of such quarter exceeds the sum of (i) the cumulative volumes processed (or credited with respect to plant interruptions) under the processing agreement as of the end of such quarter plus (ii) volumes corresponding to deficiency payments incurred prior to such quarter. During the three and six months ended June 30, 2016, we incurred $3.2 million and $6.5 million, respectively, of deficiency payments. As of June 30, 2016, we had $6.5 million of prepaid processing fees on our balance sheet in the “Other long-term assets” line. We expect to make periodic deficiency payments from time-to-time. On a quarterly basis we will make an assessment on whether the long-term asset is recoverable. See Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Results of Operations

Our results of operations for the three and six months ended June 30, 2016 and 2015 presented below have been derived from our consolidated financial statements.

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in thousands)
Oil & natural gas sales	$	98,986		$	78,605		$	180,064		$	165,628
Lease operating		8,189			3,854			14,903			9,076
Gathering, processing, and transportation (including affiliate)		36,809			18,102			72,937			32,865
Taxes other than income		2,991			3,140			5,855			5,915
Depreciation, depletion, and amortization		65,558			35,827			125,357			76,359
Incentive unit compensation expense (benefit)		74,329			16,116			52,569			26,340
General and administrative		24,021			10,323			35,154			23,299
(Gain) loss on commodity derivative and other financial instruments		90,617			30,463			54,175			(77,727	)
Interest expense, net		(12,767	)		(9,613	)		(24,124	)		(19,369	)
Income tax benefit (expense) from continuing operations		25,342			24,644			22,405			(22,914	)
Net income (loss) from continuing operations		(195,833	)		(26,614	)		(190,116	)		23,895
Net income (loss) from discontinued operations		(122,425	)		(113,859	)		(160,522	)		(276,517	)
Net income (loss) attributable to Memorial Resource Development Corp.		(195,961	)		(26,702	)		(190,284	)		22,044
Natural gas and oil revenue:
Oil sales	$	14,855		$	16,752		$	25,750		$	30,145
NGL sales		22,729			14,042			38,123			25,496
Natural gas sales		61,402			47,811			116,191			109,987
Total natural gas and oil revenue	$	98,986		$	78,605		$	180,064		$	165,628
Production Volumes:
Oil (MBbls)		353			315			715			598
NGLs (MBbls)		1,250			669			2,612			1,172
Natural gas (MMcf)		31,377			18,469			59,227			38,664
Total (MMcfe)		40,995			24,373			79,189			49,284
Average net production (MMcfe/d)		450.5			267.8			435.1			272.3
Average sales price:
Oil (per Bbl)	$	42.08		$	53.18		$	36.01		$	50.41
NGL (per Bbl)		18.18			20.99			14.60			21.75
Natural gas (per Mcf)		1.96			2.59			1.96			2.84
Total (Mcfe)	$	2.41		$	3.23		$	2.27		$	3.36
Average unit costs per Mcfe:
Lease operating expense	$	0.20		$	0.16		$	0.19		$	0.18
Gathering, processing, and transportation  (including affiliate)		0.90			0.74			0.92			0.67
Taxes other than income		0.07			0.13			0.07			0.12
General and administrative expenses		0.59			0.42			0.44			0.47
Depletion, depreciation, and amortization		1.60			1.47			1.58			1.55

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Three Months Ended June 30, 2016 Compared to the Three Months Ended June 30, 2015

We recorded a net loss from continuing operations of $195.8 million during the three months ended June 30, 2016 compared to a net loss from continuing operations of $26.6 million during the three months ended June 30, 2015.

· Oil, natural gas and NGL revenues for 2016 totaled $99.0 million, an increase of $20.4 million compared with 2015. Production increased 16.6 Bcfe (approximately 68%) primarily due to drilling activities in North Louisiana. The average realized sales price decreased by a $0.82 per Mcfe (approximately 25%) due to lower commodity prices. The volume and pricing variance contributed to an approximate $53.7 million increase which was partially offset by a $33.3 million decrease in revenues.

· Lease operating expenses were $8.2 million and $3.9 million for 2016 and 2015, respectively. On a per Mcfe basis, lease operating expenses increased to $0.20 for 2016 from $0.16 for 2015 primarily due to an increase in workover expenses and saltwater disposal costs associated with the completion activity during the first quarter.

· Gathering, processing and transportation expenses, including affiliates, were $36.8 million and $18.1 million for 2016 and 2015, respectively. The increase of $18.7 million is primarily due to an increase in natural gas and NGL volumes and an increase in the rate due to efficient cryogenic processing associated with new gas processing plants. On a per Mcfe basis, gathering, processing and transportation expenses, including affiliates, were $0.90 for 2016 compared to $0.74 for 2015.

· DD&A expense for 2016 was $65.6 million compared to $35.8 million for 2015, an increase of $29.8 million. The increase is due to an increase in production volumes and an increase in the rate. Increased production volumes caused DD&A expense to increase by approximately $24.6 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $5.2 million.

· Incentive unit compensation expense for 2016 was $74.3 million related to MRD Holdco incentive units as discussed in Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. Incentive unit compensation expense of approximately $16.1 million was recorded in 2015 related to MRD Holdco incentive units. The increase is primarily related to the increase in our stock price and a change to the estimated initial requisite service period.

· General and administrative expenses for 2016 were $24.0 million compared to $10.3 million for 2015. General and administrative expenses for 2016 included $6.2 million of transaction-related costs compared to $0.1 million of transaction-related costs in 2015. The increase in transaction related costs was primarily due to costs associated with the Disposition Entities and their subsidiaries and the planned Merger with Range. Expense associated with our long-term incentive plan (“LTIP”) awards increased $8.5 million between periods. The increase in LTIP awards is primarily due to the accelerated vesting and expense recognition of MRD awards by certain MEMP employees as a result of the transaction involving the Disposition Entities. The overall increase in general and administrative expense was partially offset by lower salaries and benefits expense.

· Net losses on commodity derivative instruments of $90.6 million were recognized during 2016, consisting of $61.8 million of cash settlement receipts and offset by a $152.4 million decrease in the fair value of open hedge positions. Net losses on commodity derivative instruments of $30.5 million were recognized during 2015, consisting of $37.5 million of cash settlement receipts and offset by a $68.0 million decrease 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 2016 was $12.8 million, including amortization of deferred financing fees of approximately $0.8 million. Net interest expense during 2015 was $9.6 million, including amortization of deferred financing fees of approximately $0.7 million.

Average outstanding borrowings under our revolving credit facility were $535.2 million during 2016. Average outstanding borrowings under our revolving credit facility were $140.5 million during 2015. For both 2016 and 2015, we had an average of $600.0 million aggregate principal amount of the Senior Notes issued and outstanding.

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· Income tax benefit from continuing operations for 2016 was $25.3 million compared to $24.6 million for 2015, resulting in an effective tax rate of 11.5% and 48.1%, respectively. The change in the income tax benefit was primarily attributable to the increase in pre-tax loss for 2016, offset by the change in non-deductible incentive unit compensation expense discussed above.  

· We recorded a net loss from discontinued operations of $122.4 million during 2016 compared to a net loss from discontinued operations of $113.9 million during 2015 primarily due to commodity derivative losses, lower oil and natural gas sales and higher interest expense.  Oil and natural gas sales for 2016 totaled $43.8 million, a decrease of $53.4 million compared with 2015. DD&A for 2016 totaled $30.0 million compared with $46.3 million for 2015. Net losses on commodity derivative instruments of $104.4 million during 2016 compared to $61.4 million during 2015. Other operating income was $6.9 million during 2016 compared to $27.8 million of other operating expense during 2015.

Six Months Ended June 30, 2016 Compared to the Six Months Ended June 30, 2015

We recorded a net loss from continuing operations of $190.1 million during the six months ended June 30, 2016 compared to a net income from continuing operations of $23.9 million during the six months ended June 30, 2015.

· Oil, natural gas and NGL revenues for 2016 totaled $180.1 million, an increase of $14.4 million compared with 2015. Production increased 29.9 Bcfe (approximately 61%) primarily due to drilling activities in North Louisiana. The average realized sales price decreased $1.09 per Mcfe (approximately 32%) primarily due to lower commodity prices. The volume and pricing variance contributed to an approximate $100.5 million increase and $86.1 million decrease in revenues, respectively.

· Lease operating expenses were $14.9 million and $9.1 million for 2016 and 2015, respectively. The $5.8 million increase is primarily due to the increase in production volumes. The lease operating expense rate per Mcfe was consistent between periods.

· Gathering, processing and transportation expenses, including affiliates, were $72.9 million and $32.9 million for 2016 and 2015, respectively. The increase of $40.0 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.

· DD&A expense for 2016 was $125.4 million compared to $76.4 million for 2015, an increase of $49.0 million. The increase is due to an increase in production volumes and an increase in the rate. Increased production volumes caused DD&A expense to increase by approximately $46.4 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $2.6 million.

· Incentive unit compensation expense for 2016 was $52.6 million compared to $26.3 million for 2015 related to MRD Holdco incentive units as discussed in Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. The increase is primarily related to the increase in our stock price and a change to the estimated initial requisite service period.

· General and administrative expenses for 2016 were $35.2 million compared to $23.3 million for 2015. General and administrative expenses for 2016 included $6.2 million of transaction related costs compared to $1.4 million of transaction-related costs in 2015. The increase in transaction related costs was primarily due to costs associated with the Disposition Entities and their subsidiaries and the planned Merger with Range. LTIP awards for 2016 were $13.7 million compared to $3.4 million in 2015. The increase in LTIP awards was primarily due to accelerated vesting and expense recognition for employees that remained with the transaction involving the Disposition Entities and their subsidiaries.

· Net losses on commodity derivative instruments of $54.2 million were recognized during 2016, consisting of $130.0 million of cash settlement receipts offset by a $182.4 million decrease in the fair value of open hedge positions. Net gains on commodity derivative instruments of $77.7 million were recognized during 2015, consisting of $70.3 million of cash settlement receipts and $7.4 million related to the increase in the fair value of open hedge positions.

· Net interest expense during 2016 was $24.1 million, including amortization of deferred financing fees of approximately $1.6 million. Net interest expense during 2015 was $19.4 million, including amortization of deferred financing fees of approximately $1.3 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2016 compared to 2015.

Average outstanding borrowings under our revolving credit facility were $508.5 million during 2016. Average outstanding borrowings under the revolving credit facilities were $161.4 million during 2015. For 2016 and 2015, we had an average of $600.0 million aggregate principal amount of the Senior Notes issued and outstanding.

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· Income tax benefit from continuing operations for 2016 was $22.4 million compared to $22.9 million of income tax expense for 2015. The income tax benefit is primarily a result of the pre-tax loss for 2016 compared to the income tax expense as a result of the pre-tax income for 2015. The effective tax rate was 10.5% for 2016 compared to 49.0% for 2015. The effective tax rate differed from the statutory federal income tax rate primary due to the non-deductibility of incentive unit compensation, state income tax, net of federal benefit, and long-term incentive plan compensation expense.  

· We recorded a net loss from discontinued operations of $160.5 million during 2016 compared to net loss from discontinued operations of $276.5 million during 2015 due to lower commodity prices and oil and natural gas sales. Oil and natural gas sales for 2016 totaled $104.4 million, a decrease of $84.7 million compared with 2015. Impairment expense of $8.3 million was recognized during 2016 compared to $251.3 million during 2015. Net interest expense totaled $51.7 million during 2016 compared to $56.7 million during 2015.

Adjusted EBITDA

Adjusted EBITDA is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by our management in evaluating performance. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating results. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) from continuing operations, our most directly comparable financial measure calculated and presented in accordance with GAAP. Our computation of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

Adjusted EBITDA is defined as net income (loss) from continuing operations, plus interest expense; debt extinguishment cost; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; cash settlements on other financial instruments; losses on sale of properties; stock-based compensation; incentive-based compensation expenses; transaction related costs; exploration costs; equity loss; cash distributions from MEMP; 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; gains on sale of assets and other non-routine items.

Calculation of Adjusted EBITDA

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Net income (loss) from continuing operations	$	(195,833	)	$	(26,614	)	$	(190,116	)	$	23,895
Interest expense, net		12,767			9,613			24,124			19,369
Income tax expense (benefit) from continuing operations		(25,342	)		(24,644	)		(22,405	)		22,914
DD&A		65,558			35,827			125,357			76,359
Accretion of AROs		156			93			295			216
(Gain) loss on commodity derivative instruments		90,617			30,463			54,175			(77,727	)
Cash settlements received (paid) on expired commodity derivative and other financial instruments		69,911			37,539			148,853			70,288
Incentive-based compensation expense		84,850			18,073			66,242			29,783
Exploration costs		4,612			2,230			7,058			2,956
(Gain) loss on sale of properties		—			50			50			50
Transaction related costs		6,179			126			6,209			1,407
Cash distributions from MEMP		—			75			9			151
Adjusted EBITDA	$	113,475		$	82,831		$	219,851		$	169,661

Liquidity and Capital Resources

Historically, the primary sources of liquidity have been through borrowings under credit facilities, capital contributions from NGP, 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 North Louisiana 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.

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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 permit us to complete our remaining planned 2016 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 cannot assure you that operations and other needed capital will be available on acceptable terms, or at all.

As of June 30, 2016, we had $486.0 million of available borrowing capacity under our revolving credit facility. As of June 30, 2016, we had a working capital balance of $51.5 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, 2016, MRD’s total capital expenditures, including unproved leasehold, were approximately $249.6 million related primarily to the development of the Terryville Complex.

Debt Agreements

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 $1.0 billion as of June 30, 2016. 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 2016, the borrowing base under our revolving credit facility was reaffirmed at $1.0 billion. 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, 2016.

Senior Notes

As of June 30, 2016, we had $600.0 million aggregate principal amount of 5.875% senior unsecured notes due 2022 (the “Senior Notes”) outstanding. The 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 Senior Notes are governed by an indenture dated as of July 10, 2014. The Senior Notes are fully and unconditionally guaranteed, subject to customary release provisions, on a senior unsecured basis by certain of our existing subsidiaries.

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, 2016, 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.

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.

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Cash Flows from Operating, Investing and Financing Activities

The following table summarizes cash flows from continuing 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 Cash Flows included under “Item 1. Financial Statements” of this quarterly report.

	For the Six Months Ended June 30,
	2016			2015
Net cash provided by operating activities from continuing operations	$	151,947		$	183,699
Net cash used in investing activities from continuing operations		(245,507	)		(196,800	)
Net cash provided by (used in) financing activities from continuing operations		85,964			(69,197	)

Six Months Ended June 30, 2016 Compared to the Six Months Ended June 30, 2015

Operating Activities. Net cash flows provided by operating activities were $151.9 million during 2016 compared to $183.7 million during 2015. Production increased 29.9 Bcfe (approximately 61%) and average realized sales price decreased $1.09 per Mcfe as previously discussed under “Results of Operations.” Cash paid for interest during 2016 was $22.4 million compared to $35.7 million during 2015 and cash settlements on commodity derivatives were $130.0 million during 2016 compared to $70.3 million during 2015.

Investing Activities. Total cash used in investing activities was $245.5 million during 2016 compared to $196.8 million during 2015. Cash used for additions to oil and gas properties was $265.5 million during 2016 compared to $207.1 million during 2015, which consisted primarily of drilling and completion activities in North Louisiana. Cash settlements received on other financial instruments were $16.2 million during 2016. Cash used for other property and equipment was $0.4 million during 2016 and $3.3 million during 2015 which consisted primarily of computer hardware, software, and other leased office space build out during 2015. In connection with the sale of the Disposition Entities, we sold MEMP furniture, fixtures, and other property and equipment and received $4.2 million.

Financing Activities.  Net borrowings under our revolving credit facility were $91.0 million during 2016.  Amounts borrowed under our revolving credit facility were primarily used for additions to oil and natural gas properties and general corporate purposes, including working capital.  Net repayments under revolving credit facilities were $18.0 million during 2015. Amounts borrowed under our revolving credit facility were primarily used for additions to oil and natural gas properties and general corporate purposes, including working capital during 2015.

Total payments remitted for employees’ tax obligations to the appropriate taxing authorities were approximately $5.7 million during 2016 upon vesting of 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. The Company has retired all of the shares of common stock repurchased and those shares of common stock are no longer issued or outstanding.  

Contractual Obligations

During the six months ended June 30, 2016, there were no significant changes in our consolidated contractual obligations from those reported in our 2015 Form 10-K filed with the SEC on February 24, 2016 except for an addition of a long-term firm transportation agreement entered into with a third party as part of our ordinary course of business. For more information see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report. Additionally, indebtedness under our revolving credit facility was $514.0 million at June 30, 2016 compared to $423.0 million at December 31, 2015. See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information on our indebtedness.

Off–Balance Sheet Arrangements

As of June 30, 2016, 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 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

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that our exposures to market risk have not changed materially since those reported under “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2015 Form 10-K filed with the SEC on February 24, 2016.

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, 2016, see Note 6 of the Notes to Unaudited Condensed Consolidated 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. We had no interest rate swap arrangements outstanding at June 30, 2016.

At June 30, 2016, we had $514.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate based on the LIBOR Market Index Rate plus 2.0%, or 2.47%. Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the variable component of the stated interest rate would be less than $0.2 million per year.

The fair value of our Senior Notes is sensitive to changes in interest rates. We estimate the fair value of our Senior Notes using quoted market prices. The carrying value (net of any discount or premium and debt issuance cost) is compared to the estimated fair value in the table below (in thousands):

	June 30, 2016
	Carrying		Estimated
Description	Amount		Fair Value
5.875% senior notes, fixed-rate, due May 1, 2022	$	589,902	$	598,500

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 6 of the Notes to Unaudited Condensed Consolidated 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, 2016. 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, 2016 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, 2016 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.

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, “Item 1. Financial Statements”, Note 14, “Commitments and Contingencies – Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated Financial Statements included in this quarterly report, which is incorporated herein by reference.

ITEM 1A. RISK FACTORS.

Other than as set forth below, there have been no material changes with respect to the risk factors since those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC on February 24, 2016.

We are subject to litigation related to the Merger, and it is possible that additional claims, including against Range, may be brought by the current plaintiffs or others.

We subject to litigation related to the Merger. See Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements.” It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs or by others in an effort to enjoin the Merger or seek monetary relief from us or Range. We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve any such lawsuits. An unfavorable resolution of any such litigation surrounding the Merger could delay or prevent its consummation. In addition, the costs of defending any such litigation, even if resolved in our favor, could be substantial and such litigation could distract Memorial and Range from pursuing the consummation of the Merger and other potentially beneficial business opportunities.

The Merger is subject to conditions, including certain conditions that may not be satisfied, or completed on a timely basis, if at all.

The Merger is subject to a number of other conditions beyond Range’s and our control that may prevent, delay or otherwise materially adversely affect its completion. We cannot predict whether and when these other conditions will be satisfied. Any delay in completing the Merger could cause the combined company not to realize some or all of the benefits that we expect to achieve if the Merger is successfully completed within its expected time frame.

Failure to complete the Merger could negatively impact our future business and financial results.

We cannot make any assurances that we or Range will be able to satisfy all of the conditions to the Merger or succeed in any litigation brought in connection with the Merger. If the Merger is not completed, our financial results may be adversely affected and we will be subject to several risks, including but not limited to:

· Being required to pay Range a no vote expense payment of $25,000,000, due to the failure to obtain Memorial stockholder approval of the Merger or a termination fee of $75,000,000 due to certain circumstances provided in the Merger Agreement;

· payment of costs relating to the Merger, such as legal, accounting, financial advisor and printing fees, regardless of whether the Merger is completed;

· having had the focus of our management on the Merger instead of on pursuing other opportunities that could have been beneficial to us; and

· being subject to litigation related to any failure to complete the Merger.

If the Merger is not completed, we cannot assure our stockholders that these risks will not materialize and will not materially and adversely affect our business, financial results and stock prices.

The Merger Agreement contains provisions that limit our ability to pursue alternatives to the Merger, could discourage a potential competing acquiror of the Company from making a favorable alternative transaction proposal and, in specified circumstances, could require us to pay a termination fee to Range.

The Merger Agreement contains “no shop” provisions that, subject to limited exceptions, restrict our ability to solicit, initiate, or knowingly encourage or knowingly facilitate, directly or indirectly, any inquiry or proposal in respect of a competing third-party proposal for the acquisition of our stock, business or assets. In addition, in certain circumstances as described in the Merger Agreement, we may be required to pay Range a termination fee of $75,000,000.

These provisions could discourage a potential third-party acquiror that might have an interest in acquiring all or a significant portion of us from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the Merger or might result in a potential third-party

37

acquiror proposing to pay a lower price to the stockholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.

If the Merger Agreement is terminated and we determine to seek another business combination, we may not be able to negotiate a transaction with another party on terms comparable to—or better than—the terms of the Merger.

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, 2016.

							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, 2016 - April 30, 2016		20,363	$	10.32		—		—
May 1, 2016 - May 31, 2016		62,364	$	15.28		—		—
June 1, 2016 - June 30, 2016		259,866	$	15.94		—		—

(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.

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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: July 28, 2016	By:	/s/Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Senior Vice President and Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number		Description
2.1#	—		Agreement and Plan of Merger, dated May 15, 2016, by and among Range Resources Corporation, Medina Merger Sub, Inc., and Memorial Resource Development Corp. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on May 17, 2016).
2.2	—		Voting and Support Agreement, dated May 15, 2016, by and among MRD Holdco LLC, Jay Graham, WHR Incentive LLC, Anthony Bahr, and Range Resources Corporation (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on May 17, 2016).
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).
10.1*	—		Sixth Amendment to Credit Agreement, by and among Memorial Resource Development Corp., as the Borrower, the Lenders party thereto, Bank of America, N.A., as Administrative Agent, Citibank, N.A., as Syndication Agent, JPMorgan Chase Bank, N.A, BMO Harris Bank, N.A, Comerica Bank, Credit Agricole Corporate and Investment Bank, Natixis, MUFG Union Bank, N.A and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the other lenders and parties party thereto, dated as of May 31, 2016.
10.2*	—		Amendment No. 2 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 31, 2016.
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.

# Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. We hereby undertake to furnish supplemental copies of any of the omitted schedules upon request by the U.S. Securities and Exchange Commission.

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EX-10

Exhibit 10.1

Sixth Amendment to Credit Agreement

dated as of May 31, 2016

among

Memorial Resource Development Corp.,
as Borrower,

Bank of America, N.A.,
as Administrative Agent,

Citibank, N.A.,
as Syndication Agent,

JPMorgan Chase Bank, N.A., BMO Harris Bank, N.A., Comerica Bank, Credit Agricole Corporate and Investment Bank, Natixis, MUFG Union Bank, N.A., and Wells Fargo Bank, National Association,
as Co-Documentation Agents

and

the Lenders party hereto

Merrill Lynch, Pierce, Fenner & Smith Incorporated,
Sole Lead Arranger and Sole Bookrunner

Sixth Amendment to Credit Agreement

This Sixth Amendment to Credit Agreement (this “Sixth Amendment”), dated as of May 31, 2016 (the “Sixth Amendment Effective Date”), is among Memorial Resource Development Corp., a corporation formed under the laws of the State of Delaware (the “Borrower”); each of the undersigned guarantors (together with the Borrower, collectively, the “Loan Parties”); each of the Lenders that is a signatory hereto; and Bank of America, N.A., as administrative agent for the Lenders (in such capacity, together with its successors, the “Administrative Agent”).

Recitals

A.The Borrower, the Administrative Agent and the Lenders are parties to that certain Credit Agreement dated as of June 18, 2014 (as amended prior to the date hereof, the “Credit Agreement”), pursuant to which the Lenders have, subject to the terms and conditions set forth therein, made certain credit available to and on behalf of the Borrower.

B.The Borrower has advised the Administrative Agent and the Lenders that it has entered into that certain Purchase and Sale Agreement dated as of April 27, 2016 (the “Applicable PSA”) with Memorial Production Partners LP, a Delaware limited partnership (“MEMP”), and, for the limited purposes set forth therein, MEMP GP, Memorial Production Operating LLC, a Delaware limited liability company, Beta Operating Company, LLC, a Delaware limited liability company (“Beta Operating”), and MEMP Services LLC, a Delaware limited liability company (“Services”), pursuant to which the Borrower will sell to MEMP all of the limited liability company interests in each of MEMP GP, Beta Operating and Services, as more particularly described in the Applicable PSA.  The date on which such sale of such limited liability company interests is consummated is referred to herein as the “MEMP GP Sale Closing Date”.

C.The parties hereto desire to amend the Credit Agreement in certain respects including, without limitation, to accommodate the transactions contemplated by the Applicable PSA, in each case to be effective as of the Sixth Amendment Effective Date.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms.  Each capitalized term which is defined in the Credit Agreement, but which is not defined in this Sixth Amendment, shall have the meaning ascribed such term in the Credit Agreement, as amended hereby.  Unless otherwise indicated, all section references in this Sixth Amendment refer to the Credit Agreement.

Section 2.Amendments as of Sixth Amendment Effective Date.  In reliance on the representations, warranties, covenants and agreements contained in this Sixth Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 4 hereof, the Credit Agreement shall be amended effective as of the Sixth Amendment Effective Date in the manner provided in this Section 2.

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2.1Additional Definitions.  Section 1.02 of the Credit Agreement is hereby amended to add thereto in alphabetical order the following definitions which shall read in full as follows: 

“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

“Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

“EEA Financial Institution” means (a) any credit institution or investment firm established in an EEA Member Country that is subject to the supervision of an EEA Resolution Authority; (b) any entity established in an EEA Member Country that is a parent of an institution described in clause (a) above; or (c) any financial institution established in an EEA Member Country that is a subsidiary of an institution described in the foregoing clauses of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” means any public administrative authority or any Person entrusted with public administrative authority of an EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor thereof), as in effect from time to time.

“Sixth Amendment” means that certain Sixth Amendment to Credit Agreement dated as of the Sixth Amendment Effective Date, among the Borrower, the Guarantors, the Administrative Agent and the Lenders party thereto.

“Sixth Amendment Effective Date” means May 31, 2016.

“Write-Down and Conversion Powers” means the write-down and conversion powers of the applicable EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.

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2.2Amended Definitions.  The definitions of “Defaulting Lender” and “Loan Documents” contained in Section 1.02 of the Credit Agreement are hereby amended as follows: 

(a)The definition of “Defaulting Lender” is hereby amended by restating so much of clause (d) thereof as precedes the proviso to read as follows: “has (or whose bank holding company or any Parent of whom has) been placed into receivership, conservatorship or bankruptcy or become the subject of a Bail-In Action”.

(b)The definition of “Loan Documents” is hereby amended by inserting “the Sixth Amendment,” immediately after the reference therein to “the Fifth Amendment,”.

2.3Amendment to Article VII of the Credit Agreement.  A new Section 7.25 is hereby added to Article VII of the Credit Agreement, which Section 7.25 shall read in full as follows:

Section 7.25No EEA Financial Institution.  No Loan Party is an EEA Financial Institution.

2.4Amendment to Section 9.12 of the Credit Agreement.  Section 9.12(e) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(e)(i) sales and other dispositions of Properties not regulated by Section 9.12(a) to (d) having a fair market value not to exceed $10,000,000 in the aggregate during any 12-month period and (ii) the sale by the Borrower of 100% of the limited liability company interests in MEMP GP, Beta Operating Company, LLC, and MEMP Services LLC to MEMP so long as, in the case of this clause (ii), (A) such sale is in accordance with the Applicable PSA (as defined in the Sixth Amendment) without any waivers or amendments thereto that are materially adverse to the interests of the Lenders, (B) such sale is consummated on or before July 15, 2016, and (C) at the time such sale is consummated, none of MEMP GP, Beta Operating Company, LLC or MEMP Services LLC own any Oil and Gas Properties or any other material properties or Equity Interests not owned by such Person as of the Sixth Amendment Effective Date.

2.5Amendment to Article XII of the Credit Agreement.  A new Section 12.18 is hereby added to Article XII of the Credit Agreement, which Section 12.18 shall read in full as follows:

Section 12.18Acknowledgement and Consent to Bail-In of EEA Financial Institutions.  Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among the parties, each party hereto (including each Secured Party) acknowledges that any liability arising under a Loan Document of any Secured Party that is an EEA Financial Institution, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority, and agrees and consents to, and acknowledges and agrees to be bound by:

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(a)the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising under any Loan Documents which may be payable to it by any Secured Party hereto that is an EEA Financial Institution; and 

(b)the effects of any Bail-In Action on any such liability, including:

(i)a reduction in full or in part or cancellation of any such liability;

(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any EEA Resolution Authority.

Section 3.Amendments as of the MEMP GP Sale Closing Date.  In reliance on the representations, warranties, covenants and agreements contained in this Sixth Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 4 hereof, the Credit Agreement shall be amended effective as of the MEMP GP Sale Closing Date (simultaneously with the consummation of the sale of the limited liability company interests in MEMP GP, Beta Operating and Services to occur on such date) in the manner provided in this Section 3.

3.1Amended Definitions.  The definitions of “Consolidated Restricted Subsidiaries”, “Consolidated Unrestricted Subsidiaries”, “Guarantors”, and “Unrestricted Subsidiary” contained in Section 1.02 of the Credit Agreement are hereby amended as follows:

(a)The definition of “Consolidated Restricted Subsidiaries” is hereby amended by deleting the reference therein to “(other than MEMP GP)”.

(b)The definition of “Consolidated Unrestricted Subsidiaries” is hereby amended by deleting the reference therein to “(a) MEMP GP or (b) MEMP and any other” and replacing it with “any”.

(c)The definition of “Guarantors” is hereby amended by deleting the reference therein to “other than MEMP GP”.

(d)The definition of “Unrestricted Subsidiary” is hereby amended by deleting the proviso therein which reads “provided that in no event shall MEMP GP be an Unrestricted Subsidiary”.

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3.2Deletion of Definition.  The definition of “MEMP GP Debt” contained in Section 1.02 of the Credit Agreement is hereby deleted in its entirety. 

3.3Amendment to Section 8.01 of the Credit Agreement.  Section 8.01 of the Credit Agreement is hereby amended by deleting clauses (a) and (b) thereof in their entirety and replacing them with following clauses (a) and (b) which shall read in full as follows:

(a)Annual Financial Statements.  As soon as available, but in any event in accordance with then applicable law and not later than 15 days after annual financial statements are required to be delivered to the SEC, the Borrower’s audited consolidated balance sheet and related statements of operations, shareholders’ equity and cash flows as of the end of and for such year, setting forth in each case in comparative form the figures for the previous fiscal year, all reported on by KPMG LLP or other independent public accountants of recognized national standing (without a “going concern” or like qualification or exception and without any qualification or exception as to the scope of such audit) to the effect that such consolidated financial statements present fairly in all material respects the financial condition and results of operations of the Borrower and its Consolidated Restricted Subsidiaries on a consolidated (for fiscal years prior to 2016, combined with MEMP and consolidating (combined for the Borrower and the Guarantors)) basis in accordance with GAAP consistently applied; provided that the timely filing with the SEC of the Borrower’s annual report on Form 10-K will satisfy the reporting requirements of this Section 8.01(a) and (ii) unaudited segment balance sheets, audited segment statements of income and unaudited segment statements of cash flows as of the end of and for such year, which are derived from the consolidated (for fiscal years prior to 2016, combined with MEMP and consolidating (combined for the Borrower and the Guarantors)) financial statements of the Borrower.

(b)Quarterly Financial Statements.  For each of the first three fiscal quarters of the Borrower’s fiscal year, as soon as available, but in any event in accordance with then applicable law and not later than 15 days after quarterly financial statements are required to be delivered to the SEC, the Borrower’s (i) unaudited consolidated (for fiscal quarters ending on or before March 31, 2016, combined with MEMP and consolidating (combined for the Borrower and the Guarantors)) balance sheets and related statements of operations, shareholders’ equity and cash flows as of the end of and for such fiscal quarter and the then elapsed portion of the fiscal year, setting forth in each case in comparative form the figures for the corresponding period or periods of (or, in the case of the balance sheet, as of the end of) the previous fiscal year, all certified by one of its Financial Officers as presenting fairly in all material respects the financial condition and results of operations of the Borrower and its Consolidated Restricted Subsidiaries on a consolidated (for fiscal quarters ending on or before March 31, 2016, combined with MEMP and consolidating (combined for the Borrower and the Guarantors)) basis in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes; provided that the timely filing with the SEC of the Borrower’s

5

quarterly reports on Form 10-Q will satisfy the reporting requirements of this Section 8.01(b) and (ii) unaudited segment balance sheets, unaudited segment statements of income and unaudited segment statements of cash flows as of the end of and for such fiscal quarter and the then elapsed portion of the fiscal year, setting forth in each case in comparative form the figures for the corresponding period or periods of (or, in the case of the balance sheet, as of the end of) the previous fiscal year, which are derived from the consolidated (for fiscal quarters ending on or before March 31, 2016, combined with MEMP and consolidating (combined for the Borrower and the Guarantors)) financial statements of the Borrower. 

3.4Amendment to Section 8.17 of the Credit Agreement.  Section 8.17(b) of the Credit Agreement is hereby amended by deleting the reference therein to “(other than MEMP GP solely with respect to MEMP GP Debt)”.

3.5Amendment to Section 9.02 of the Credit Agreement.  Section 9.02(f) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows: “[Reserved];”.

3.6Amendment to Section 9.05 of the Credit Agreement.  Section 9.05(i) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows: “[Reserved]; and”.

3.7Amendment to Section 9.24 of the Credit Agreement.  Section 9.24(b) of the Credit Agreement is hereby amended by deleting the reference therein to “other than MEMP GP”.

3.8Replacement of Schedule 7.14.  Schedule 7.14 to the Credit Agreement shall be replaced in its entirety with Schedule 7.14 attached hereto and Schedule 7.14 attached hereto shall be deemed to be attached as Schedule 7.14 to the Credit Agreement.

Section 4.Conditions Precedent to this Sixth Amendment.  The effectiveness of the amendments to the Credit Agreement contained in Section 2 and in Section 3 hereof is subject to the following:

4.1The Administrative Agent shall have received counterparts of this Sixth Amendment from the Loan Parties and the Majority Lenders.

4.2The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the Sixth Amendment Effective Date.

4.3No Default, Event of Default, or Borrowing Base Deficiency shall exist immediately prior to or after giving effect to the amendments to the Credit Agreement contained in Section 2 hereof.

4.4The Administrative Agent shall have received such other documents as the Administrative Agent or counsel to the Administrative Agent may reasonably request.

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The Administrative Agent shall notify the Borrower and the Lenders of the effectiveness of this Sixth Amendment, and such notice shall be conclusive and binding.

Section 5.Representations and Warranties; Etc.  Each Loan Party hereby affirms: (a) that as of the date hereof, all of the representations and warranties contained in each Loan Document to which such Loan Party is a party are true and correct in all material respects as though made on and as of the date hereof (unless made as of a specific earlier date, in which case, was true as of such date and except to the extent that any such representation and warranty is qualified by materiality, in which case such representation and warranty shall continue to be true and correct in all respects), (b) no Defaults exist under the Loan Documents or will, after giving effect to this Sixth Amendment, exist under the Loan Documents and (c) no Material Adverse Effect has occurred.

Section 6.Miscellaneous.

6.1Confirmation and Effect.  The provisions of the Credit Agreement (as amended by this Sixth Amendment) shall remain in full force and effect in accordance with its terms following the effectiveness of this Sixth Amendment.  Each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof”, “herein”, or words of like import shall mean and be a reference to the Credit Agreement as amended hereby, and each reference to the Credit Agreement in any other document, instrument or agreement executed and/or delivered in connection with the Credit Agreement shall mean and be a reference to the Credit Agreement as amended hereby.

6.2Ratification and Affirmation of Loan Parties.  Each of the Loan Parties hereby expressly (a) acknowledges the terms of this Sixth Amendment, (b) ratifies and affirms its obligations under the Guaranty Agreement and the other Loan Documents to which it is a party, as amended hereby, (c) acknowledges, renews and extends its continued liability under the Guaranty Agreement and the other Loan Documents to which it is a party, as amended hereby, (d) ratifies and affirms all Liens granted by it pursuant to the Loan Documents to secure the Indebtedness (except to the extent that such Liens have been released in accordance with the Loan Documents) and (e) agrees that its guarantee under the Guaranty Agreement and the other Loan Documents to which it is a party remains in full force and effect with respect to the Indebtedness, as amended hereby.

6.3Counterparts.  This Sixth Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Sixth Amendment by facsimile or electronic (e.g., pdf) transmission shall be effective as delivery of a manually executed original counterpart hereof.

6.4No Oral Agreement.  This written Sixth Amendment, the Credit Agreement and the other Loan Documents executed in connection herewith and therewith represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or unwritten oral agreements of the parties.  There are no unwritten oral agreements between the parties.

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6.5Governing Law.  This Sixth Amendment (including, but not limited to, the validity and enforceability hereof) shall be governed by, and construed in accordance with, the laws of the State of New York. 

6.6Payment of Expenses.  The Borrower agrees to pay or reimburse the Administrative Agent for all of its out-of-pocket costs and expenses incurred in connection with this Sixth Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

6.7Severability.  Any provision of this Sixth Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

6.8Successors and Assigns.  This Sixth Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

[Signature pages follow]

8

IN WITNESS WHEREOF, the parties hereto have caused this Sixth Amendment to be duly executed effective as of the date first written above.

BORROWER:	MEMORIAL RESOURCE DEVELOPMENT CORP.,
	a Delaware corporation
	By:	/s/ Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Senior Vice President and Chief Financial Officer

GUARANTORS:	MEMORIAL RESOURCE FINANCE CORP.
	By:	/s/ Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Senior Vice President and Chief Financial Officer
	MRD Operating LLC
		By:	Memorial Resource Development Corp.,
			its sole member
	BETA OPERATING COMPANY, LLC
		By:	Memorial Resource Development Corp.,
			its sole member
	LINCOLN MINERALS LLC
		By:	Memorial Resource Development Corp.,
			its sole member
		By:	/s/ Andrew J. Cozby
		Name:	Andrew J. Cozby
		Title:	Senior Vice President and Chief Financial Officer

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

ADMINISTRATIVE AGENT	BANK OF AMERICA, N.A., as Administrative Agent
AND LENDER:
	By:	/s/ Gerund N. Diamond
	Name:	Gerund N. Diamond
	Title:	Assistant Vice President
	BANK OF AMERICA, N.A., as a Lender
	By:	/s/ Raza Jafferi
	Name:	Raza Jafferi
	Title:	Vice President

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	BMO Harris Bank, N.A., as a Lender
	By:
	Name:
	Title:

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Citibank, N.A., as a Lender
	By:	/s/ Saqeeb Ludhi
	Name:	Saqeeb Ludhi
	Title:	Vice President

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Comerica Bank, as a Lender
	By:	/s/ Jeff Treadway
	Name:	Jeff Treadway
	Title:	Senior Vice President

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Credit Agricole Corporate and Investment Bank, as a Lender
	By:	/s/ Sharada Manne
	Name:	Sharada Manne
	Title:	Managing Director
	By:	/s/ Michael Willis
	Name:	Michael Willis
	Title:	Managing Director

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	JPMorgan Chase Bank, N.A., as a Lender
	By:
	Name:
	Title:

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	MUFG Union Bank, N.A., as a Lender
	By:
	Name:
	Title:

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Natixis, NEW YORK BRANCH, as a Lender
	By:
	Name:
	Title:
	By:
	Name:
	Title:

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Wells Fargo Bank, National Association, as a Lender
	By:	/s/ Shiloh Davila
	Name:	Shiloh Davila
	Title:	Director

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Barclays Bank PLC, as a Lender
	By:	/s/ Vanessa Kurbatskiy
	Name:	Vanessa Kurbatskiy
	Title:	Vice President

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Commonwealth Bank of Australia, as a Lender
	By:	/s/ David Pichut
	Name:	David Pichut
	Title:	Senior Associate

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	ING Capital LLC, as a Lender
	By:
	Name:
	Title:
	By:
	Name:
	Title:

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Royal Bank of Canada, as a Lender
	By:	/s/ Jay T. Sartain
	Name:	Jay T. Sartain
	Title:	Authorized Signatory

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	ABN AMRO CAPITAL USA LLC, as a Lender
	By:
	Name:
	Title:
	By:
	Name:
	Title:

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Associated Bank, N.A., as a Lender
	By:
	Name:
	Title:

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	The BANK OF NOVA SCOTIA, as a Lender
	By:	/s/ Alan Dawson
	Name:	Alan Dawson
	Title:	Director

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Capital One, National Association, as a Lender
	By:	/s/ Daryl Stafford
	Name:	Daryl Stafford
	Title:	Vice President

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Société Générale, as a Lender
	By:	/s/ Max Sonnonstine
	Name:	Max Sonnonstine
	Title:	Director

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Compass Bank, as a Lender
	By:	/s/ Kathleen J. Bowen
	Name:	Kathleen J. Bowen
	Title:	Managing Director

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	SOVEREIGN Bank, as a Lender
	By:	/s/ Patrick L. Johnson
	Name:	Patrick L. Johnson
	Title:	Senior Vice President

[Signature Page to Sixth Amendment to Credit Agreement

Memorial Resource Development Corp.]

EX-10

Exhibit 10.2

AMENDMENT NO. 2 TO

AMENDED AND RESTATED AREA OF MUTUAL INTEREST

AND MIDSTREAM EXCLUSIVITY AGREEMENT

This Amendment No. 2 to Amended and Restated Area of Mutual Interest and Midstream Exclusivity Agreement, dated as of May 31, 2016 (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.”

WHEREAS, the Parties entered into that certain Amended and Restated Area of Mutual Interest and Midstream Exclusivity Agreement, dated as of April 14, 2015 (as amended by that certain Amendment No. 1 to Amended and Restated Area of Mutual Interest and Midstream Exclusivity Agreement, dated as of May 20, 2015, the “Agreement”),in order to (1) 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;

WHEREAS, MRD Operating and Stephens Production Company (“Assignee”) will enter into an Exploration and Participation Agreement (the “Participation Agreement”) pursuant to which MRD Operating will assign certain AMI Interests located in the Clay field, Jackson Parish, Louisiana, to Assignee and Assignee will assign certain oil and gas interests located in Jackson Parish, Louisiana to MRD Operating; and

WHEREAS, MRD Operating and Assignee will enter into a Farmout Agreement (the “Farmout Agreement”) pursuant to which MRD Operating will assign certain AMI Interests located in the Cartwright field, Jackson Parish, Louisiana, to Assignee; and

WHEREAS, the Parties desire to amend the Agreement in accordance with Section II.F(xiv) thereof to (i) remove and release the AMI Interests that will be assigned to Assignee within the geographical areas described in the Participation Agreement and the Farmout Agreement from the AMI dedication and exclusivity obligations contained in the Agreement, (ii) to include the oil and gas interests that will be assigned to MRD Operating within the AMI dedication and exclusivity obligations contained in the Agreement; and (iii) to remove MRD WHR LA Midstream LLC as a Party to the Agreement.

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

ARTICLE 1
DEFINITIONS

1.1Definitions. Capitalized terms used herein but not defined shall have the meanings ascribed to them in the Agreement.  As used in this Amendment:

“Amendment Condition” means (i) the Released Interests have been assigned to Assignee, or to an affiliate of Assignee pursuant to the terms of the Participation Agreement and the Farmout Agreement, (ii) the MRD Acquired Interests have been assigned to MRD Operating under the Participation Agreement, and (iii) the difference between the net mineral acres comprising the Released Interests that are located with the Clay AMI and the net mineral acres comprising the MRD Acquired Interests that are located within the Clay AMI is no more than 800 acres.

“Clay AMI” means the area located within the boundaries of the red square depicted on page one (1) of Exhibit B attached hereto and labeled as the “Clay Area Acreage.”

ARTICLE 2
AMENDMENT

2.1Released/Additional Acreage, AMI Interests and Hydrocarbons.  Attached hereto (i) as Exhibit A is a list and description of the oil and gas leases in which MRD Operating intends to convey an ownership interest to Assignee pursuant to the Participation Agreement, and the Farmout Agreement (such interests to be assigned to Assignee are referred to herein as the “Released Interests”); (ii) as Exhibit B are plats showing the lands on which the Released Interests are located in the Clay and Cartwright fields; and (iii) as Exhibit C is a list and description of the oil and gas leases in which Assignee intends to convey an ownership interest to MRD Operating pursuant to the Participation Agreement (such interests to be assigned to MRD Operating are referred to herein as the “MRD Acquired Interests”).  Upon satisfaction of the Amendment Condition (a) the Released Interests (and the Hydrocarbons produced therefrom) are hereby removed from the dedication and exclusivity obligations of the Agreement, and (b) the MRD Acquired Interests (and the Hydrocarbons produced therefrom) are hereby included within the AMI Interests.  Contemporaneously with the conveyance of the Released Interests to Assignee (or an affiliate of Assignee) pursuant to the Participation Agreement and the Farmout Agreement, the Released Interests (and the Hydrocarbons produced therefrom) will not be subject to the Agreement and will no longer be deemed AMI Interests, and contemporaneously with the conveyance of the MRD Acquired Interests to MRD Operating pursuant to the Participation Agreement, the MRD Assigned Interests (and the Hydrocarbons produced therefrom) will be subject to the dedication and exclusivity obligations of the Agreement and will be deemed AMI Interests.

2.2Release. The Parties further agree that, effective as of the release of the Released Interests, each Party is hereby fully released from any and all obligations and liabilities arising from or related to the Agreement, insofar and only insofar as such obligations and liabilities directly relate to the Released Interests.

2

2.3Removal of MRD WHR LA Midstream LLC from Agreement.  MRDWHR LA Midstream LLC hereby consents to be, and hereby is, removed as aparty to the Agreement and all references and other provisions ofthe Agreement pertaining to MRD WHR LA Midstream LLC, including any reference to MRD WHR LA Midstream LLC in its capacity as a “Party” or the “Parties,” shall be deemed to be terminated as ofthe effective date of this Amendment. 

ARTICLE 3

GENERAL PROVISIONS

3.1Governing 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.

3.2Counterparts. This Amendment may be executed in any number of counterparts and by the Parties in separate counterparts, with the same effect as if all Parties had signed the same document.  All such counterparts shall be deemed an original, shall be construed together and shall constitute one and the same instrument. A facsimile or electronic transmission of a scanned, executed counterpart of this Amendment shall be sufficient to bind a Party to the same extent as an original.

3.3Integration 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]

3

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:	President and 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:	President and Chief Operating Officer

Signature Page to Amendment No. 2to Amended and Restated Area of Mutual Interest
and Midstream Exclusivity Agreement

EX-31

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, Jay C. Graham, 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:  July 28, 2016	/s/ Jay C. Graham
	Jay C. Graham
	Chief Executive Officer
	Memorial Resource Development Corp.

EX-31

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:  July 28, 2016	/s/ Andrew J. Cozby
	Andrew J. Cozby
	Senior Vice President & Chief Financial Officer
	Memorial Resource Development Corp.

EX-32

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, Jay C. Graham, 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:  July 28, 2016	/s/ Jay C. Graham
	Jay C. Graham
	Chief Executive Officer
	Memorial Resource Development Corp.
Date:  July 28, 2016	/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

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 13, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
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	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		206,038,313

XML

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 10	$ 0
Accounts receivable	62,174	52,691
Short-term derivative instruments	98,594	227,991
Other financial instruments (Note 6)	27,253	46,106
Prepaid expenses and other current assets	3,381	3,375
Assets of discontinued operation (Note 3)	0	345,541
Total current assets	191,412	675,704
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method (Note 2)	2,409,611	2,160,008
Other	12,256	22,822
Accumulated depreciation, depletion and impairment	(559,930)	(438,383)
Property and equipment, net	1,861,937	1,744,447
Long-term derivative instruments	36,514	91,291
Other long-term assets	10,833	4,976
Assets of discontinued operation (Note 3)	0	2,566,431
Total assets	2,100,696	5,082,849
Current liabilities:
Accounts payable	25,697	25,057
Accounts payable - affiliates	8,062	5,016
Revenues payable	34,117	34,026
Accrued liabilities (Note 2)	72,064	68,876
Liabilities of discontinued operation (Note 3)	0	91,779
Total current liabilities	139,940	224,754
Noncurrent liabilities:
Long-term debt	1,103,902	1,012,064
Asset retirement obligations	10,779	10,079
Deferred tax liabilities	149,355	193,733
Other long-term liabilities	3,083	7,195
Liabilities of discontinued operation (Note 3)	0	2,167,103
Total liabilities	1,407,059	3,614,928
Commitments and contingencies (Note 14)
Stockholders' equity:
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; 206,038,313 shares issued and outstanding at June 30, 2016; 205,293,743 shares issued and outstanding at December 31, 2015	2,060	2,053
Additional paid-in capital	1,627,780	1,560,949
Accumulated earnings (deficit)	(936,203)	(740,175)
Total stockholders' equity	693,637	822,827
Noncontrolling interests	0	645,094
Total equity	693,637	1,467,921
Total liabilities and equity	$ 2,100,696	$ 5,082,849

XML

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Jun. 30, 2016	Dec. 31, 2015
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	206,038,313	205,293,743
Common stock, shares outstanding	206,038,313	205,293,743

XML

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues:
Oil & natural gas sales		$ 98,986	$ 78,605	$ 180,064	$ 165,628
Total revenues		98,986	78,605	180,064	165,628
Costs and expenses:
Lease operating		8,189	3,854	14,903	9,076
Gathering, processing, and transportation		23,353	14,289	45,294	29,052
Gathering, processing, and transportation - affiliate (Note 13)		13,456	3,813	27,643	3,813
Exploration		4,612	2,230	7,058	2,956
Taxes other than income		2,991	3,140	5,855	5,915
Depreciation, depletion, and amortization		65,558	35,827	125,357	76,359
Incentive unit compensation expense (benefit) (Note 12)		74,329	16,116	52,569	26,340
General and administrative		24,021	10,323	35,154	23,299
Accretion of asset retirement obligations		156	93	295	216
(Gain) loss on commodity derivative instruments		90,617	30,463	54,175	(77,727)
(Gain) loss on sale of properties			50	50	50
Total costs and expenses		307,282	120,198	368,353	99,349
Operating income (loss)		(208,296)	(41,593)	(188,289)	66,279
Other income (expense):
Interest expense, net		(12,767)	(9,613)	(24,124)	(19,369)
Other, net		(112)	(52)	(108)	(101)
Total other income (expense)		(12,879)	(9,665)	(24,232)	(19,470)
Income (loss) before income taxes		(221,175)	(51,258)	(212,521)	46,809
Income tax benefit (expense)		25,342	24,644	22,405	(22,914)
Net income (loss) from continuing operations		(195,833)	(26,614)	(190,116)	23,895
Discontinued Operations: (Note 3)
Income (loss) before income taxes		(122,425)	(112,983)	(160,426)	(278,011)
Income tax benefit (expense)			(876)	(96)	1,494
Net income (loss) from discontinued operations		(122,425)	(113,859)	(160,522)	(276,517)
Net income (loss)		(318,258)	(140,473)	(350,638)	(252,622)
Net income (loss) attributable to noncontrolling interest		(122,297)	(113,771)	(160,354)	(274,666)
Net income (loss) attributable to Memorial Resource Development Corp.		(195,961)	(26,702)	(190,284)	22,044
Net (income) allocated to participating restricted stockholders					(150)
Net (income) loss from discontinued operations		128	88	168	227
Net income (loss) from continuing operations available to common stockholders		$ (195,833)	$ (26,614)	$ (190,116)	$ 22,121
Earnings per common share-basic: (Note 10)
Income (loss) from continuing operations		$ (0.96)	$ (0.14)	$ (0.93)	$ 0.12
Income (loss) from discontinued operations		0	0	0	0
Net income (loss)		(0.96)	(0.14)	(0.93)	0.12
Earnings per common share-diluted: (Note 10)
Income (loss) from continuing operations	[1]	(0.96)	(0.14)	(0.93)	0.12
Income (loss) from discontinued operations	[1]	0	0	0	0
Net income (loss)		$ (0.96)	$ (0.14)	$ (0.93)	$ 0.12
Weighted average common and common equivalent shares outstanding:
Basic		203,948	189,628	203,807	190,163
Diluted		203,948	189,628	203,807	190,163

[1] The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. The incremental treasury stock method shares were excluded from the computation of diluted EPS because the inclusion of such shares would have been anti-dilutive.

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UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net income (loss)	$ (350,638)	$ (252,622)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
(Income) loss from discontinued operations	160,522	276,517
Depreciation, depletion, and amortization	125,357	76,359
(Gain) loss on derivatives	54,175	(77,727)
Cash settlements (paid) received on expired derivative instruments	130,000	70,288
Amortization of deferred financing costs	1,560	1,333
Accretion of asset retirement obligations	295	216
Amortization of equity awards	13,673	3,443
(Gain) loss on sale of properties	50	50
Non-cash compensation expense	52,569	26,340
Deferred income tax expense (benefit)	(44,301)	15,197
Exploration costs	236	0
Changes in operating assets and liabilities:
Accounts receivable	(6,849)	3,396
Prepaid expenses and other assets	(6,678)	4,538
Payables and accrued liabilities	23,691	37,537
Other	(1,715)	(1,166)
Net cash provided by continuing operations	151,947	183,699
Net cash provided by discontinued operations	139,770	118,088
Net cash provided by operating activities	291,717	301,787
Cash flows from investing activities:
Additions to oil and gas properties	(265,532)	(207,103)
Additions to other property and equipment	(438)	(3,309)
Other financial instruments	16,220	0
Proceeds from the sale of other property and equipment	4,219	0
Proceeds from the sale of oil and natural gas properties	0	13,612
Other	24	0
Net cash used in continuing operations	(245,507)	(196,800)
Net cash used in discontinued operations	(33,014)	(127,644)
Net cash used in investing activities	(278,521)	(324,444)
Cash flows from financing activities:
Advances on revolving credit facilities	229,000	181,000
Payments on revolving credit facilities	(138,000)	(199,000)
Deferred financing costs	(38)	0
Proceeds from sale of subsidiaries	750	0
MRD equity repurchases	(5,748)	(51,197)
Net cash used in continuing operations	85,964	(69,197)
Net cash provided by (used in) discontinued operations	(86,365)	90,597
Net cash provided by (used in) financing activities	(401)	21,400
Net change in cash and cash equivalents	12,795	(1,257)
Add: cash balance included in assets of discontinued operations at beginning of period	2,175	2,594
Less: cash balance included in assets of discontinued operations at May 31, 2016 and June 30, 2015		4,701
Cash and cash equivalents, beginning of period	0	3,364
Cash and cash equivalents, end of period	$ 10	$ 0

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UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ in Thousands	Total	MEMP [Member]	Common Stock [Member]	Additional paid in capital [Member]	Accumulated earnings (deficit) [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member] MEMP [Member]
Total equity, beginning balance at Dec. 31, 2014	$ 1,702,964		$ 1,935	$ 1,367,346	$ (786,871)
Noncontrolling interests, beginning balance at Dec. 31, 2014						$ 1,120,554
Net income (loss)	(252,622)		0	0	22,044	(274,666)
Share repurchase	(47,785)	$ (45,117)	(28)	0	(47,757)	0	$ (45,117)
Restricted stock awards	0		9	(9)	0	0
Amortization of restricted stock awards	3,443		0	3,443	0	0
Contribution (distribution) related to MRD Holdco incentive units compensation expense (Note 12)	26,340		0	26,340	0	0
Net equity deemed contribution (distribution) related to MEMP property exchange (Note 1)	0		0	(127,149)	0	127,149
Deferred tax effect of MEMP property exchange (Note 15)	28,020		0	28,020	0	0
Distributions	(92,477)		0	0	0	(92,477)
Equity repurchases	(1,196)		(1)	0	(1,195)	0
Amortization of MEMP equity awards	4,906		0	0	0	4,906
Other	(17)		0	(47)	0	30
Total equity, ending balance at Jun. 30, 2015	1,326,459		1,915	1,297,944	(813,779)
Noncontrolling interests, ending balance at Jun. 30, 2015						840,379
Total equity, beginning balance at Dec. 31, 2015	1,467,921		2,053	1,560,949	(740,175)
Noncontrolling interests, beginning balance at Dec. 31, 2015	645,094					645,094
Total stockholders equity, beginning balance at Dec. 31, 2015	822,827
Net income (loss)	(350,638)		0	0	(190,284)	(160,354)
Restricted stock awards	0		11	(11)	0	0
Amortization of restricted stock awards	13,673		0	13,673	0	0
Contribution (distribution) related to MRD Holdco incentive units compensation expense (Note 12)	52,569		0	52,569	0	0
Distributions	(8,295)		0	0	0	(8,295)
Equity repurchases	(5,748)	$ (90)	(4)	0	(5,744)	0	$ (90)
Amortization of MEMP equity awards	4,218		0	0	0	4,218
Adjustments from deconsolidation of subsidiaries (Note 9)	(480,165)		0	0	0	(480,165)
Other	192		0	600	0	(408)
Total equity, ending balance at Jun. 30, 2016	693,637		$ 2,060	$ 1,627,780	$ (936,203)
Noncontrolling interests, ending balance at Jun. 30, 2016	0					$ 0
Total stockholders equity, ending balance at Jun. 30, 2016	$ 693,637

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Background, Organization and Basis of Presentation

6 Months Ended

Jun. 30, 2016

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; (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) “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 (v) “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.

Basis of Presentation

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Under the amended consolidation guidance that we adopted on January 1, 2016 (see Note 2), a limited partnership is considered a variable interest entity (“VIE”) unless a single limited partner or a simple majority of all partners have substantive kick-out or participating rights. The Company determined that MEMP was a VIE and we were deemed the primary beneficiary. On June 1, 2016, we completed the sale of MEMP GP, Beta Operating Company, LLC (“Beta Operating”) and MEMP Services LLC (“Services”) (collectively, the “Disposition Entities”), to MEMP for $0.75 million in cash. This sale was a reconsideration event under the amended consolidation guidance which resulted in the deconsolidation of the Partnership. Our equity statement reflects a loss of $0.1 million related to the deconsolidation of the Disposition Entities and their subsidiaries. Our financial statements have been retrospectively revised to reflect the Disposition Entities and their subsidiaries as discontinued operations for all periods presented (see Note 3). After the completion of the sale, we have one reportable business segment, which is engaged in the acquisition, exploration and development of oil and natural gas properties.  

All material intercompany transactions and balances have been eliminated in preparation of our consolidated financial statements. Our results of operations for the three and six months ended June 30, 2016 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”).

Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to the  acquisition by MEMP of certain assets from the Company in East Texas in February 2015 for certain properties in North Louisiana (the “Property Swap”).

Proposed Merger with Range Resources Corporation

On May 15, 2016, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Range Resources Corporation (“Range”), a Delaware corporation, and Medina Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of Range (“Merger Sub”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth, the Merger Sub will be merged with and into the Company, with the Company continuing as the surviving entity and a wholly owned subsidiary of Range (“the Merger”).

If the Merger is completed, each share of our common stock outstanding immediately before that time (including outstanding shares of our restricted common stock, all of which will become fully vested and unrestricted under the terms of the Merger Agreement) will automatically be converted into the right to receive 0.375 of a share of Range common stock, par value of $0.01 per share (“Range Common Stock”). The Merger is subject to customary closing conditions, including the approval by both Memorial and Range stockholders. We expect the closing of the Merger will occur late in the third quarter of 2016.

In connection with the execution of the Merger Agreement, MRD Holdco, Jay Graham (our chief executive officer), Anthony Bahr and WHR Incentive LLC (a limited liability company controlled by Mr. Graham and Mr. Bahr) (collectively, the “Memorial Stockholders”) entered into a voting and support agreement with Range and have agreed to vote all of the shares held by them in favor of the approval and adoption of the Merger Agreement and the transactions contemplated by the Merger Agreement, including the merger. As of June 30, 2016, the Memorial Stockholders hold and are entitled to vote in the aggregate approximately 47.7% of the issued and outstanding shares of our common stock entitled to vote at our special meeting.  In addition, certain other stockholders of the Company who are not party to the voting and support agreement are party to an existing voting agreement, as discussed in our 2015 Form 10-K, pursuant to which those stockholders are required to vote all of the shares of our common stock that they own as directed by MRD Holdco. As of June 30, 2016, those additional stockholders hold and are entitled to vote in the aggregate approximately 2.7% of the outstanding shares of our common stock entitled to vote at our special meeting.

Upon completion of the Merger, our common stock currently listed on the NASDAQ will cease to be listed for trading on the NASDAQ and will subsequently be deregistered under the Securities Exchange Act of 1934, as amended.

Use of Estimates

The preparation of the accompanying unaudited condensed consolidated 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 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; realization of long-term prepaid processing fees; 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.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2016

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 2015 Form 10-K.

Oil and Natural Gas Properties

Oil and natural gas properties consisted of the following at the dates indicated (in thousands):

	June 30,		December 31,
	2016		2015
	(In thousands)
Proved oil and natural gas properties	$	1,984,500	$	1,740,530
Support equipment and facilities		7,191		4,719
Unproved oil and natural gas properties		417,920		414,759
Total oil and natural gas properties	$	2,409,611	$	2,160,008

At June 30, 2016 and December 31, 2015, we had $147.4 million and $174.0 million, respectively, capitalized in proved oil and natural gas properties related to wells in various stages of drilling and completion, which have been excluded from the depletion base.

Accrued liabilities

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

	June 30,		December 31,
	2016		2015
Accrued capital expenditures	$	24,084	$	40,197
Accrued interest payable		17,665		17,657
Accrued lease operating expense		1,414		2,031
Accrued general and administrative expenses		5,871		4,030
Accrued ad valorem taxes		1,619		157
Accrued current income taxes		20,007		1,911
Other miscellaneous, including operator advances		1,404		2,893
Total accrued liabilities	$	72,064	$	68,876

Supplemental Cash Flow Information

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

	For the Six Months Ended
	June 30,
	2016			2015
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	22,418		$	35,650
Cash paid for taxes		3,800			2,000
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(16,113	)		25,560
(Increase) decrease in accounts receivable related to other financial instruments		2,633			—
Assumptions of asset retirement obligations related to properties acquired or drilled		530			—

New Accounting Pronouncements

Improvements to Employee Share-Based Payment Accounting. In March 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in additional paid-in capital (“APIC”). Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement and the APIC pools will be eliminated. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before companies can recognize them and requires companies to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires a company to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, companies will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required.  

The new guidance is effective for reporting periods beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. The Company is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively.

Leases. In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company is currently evaluating the standard and the impact on the Company’s financial statements and related footnote 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. We adopted this guidance on January 1, 2016 and determined that MEMP was a VIE for which the Company is the primary beneficiary for accounting purposes. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements. On June 1, 2016, we completed the sale of the Disposition Entities to MEMP as discussed in Note 1, which triggered a reconsideration event under the guidance which resulted in the deconsolidation of the Partnership.  

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.

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Discontinued Operations

6 Months Ended

Jun. 30, 2016

Discontinued Operations And Disposal Groups [Abstract]

Discontinued Operations

Note 3. Discontinued Operations

As previously discussed in Note 1, we sold the Disposition Entities and their subsidiaries on June 1, 2016 to MEMP. Below is a reconciliation of carrying amounts of major classes of assets and liabilities included as part of discontinued operations as reflected on the balance sheet associated with this disposal transaction (in thousands):

	December 31,
	2015
ASSETS
Current assets:
Cash and cash equivalents	$	2,175
Accounts receivable		61,404
Short-term derivative instruments		272,320
Prepaid expenses and other current assets		9,642
Total current assets		345,541
Property and equipment, net		1,946,937
Long-term derivative instruments		461,810
Restricted investments		152,631
Other long-term assets		5,053
Total assets	$	2,911,972
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,792
Accounts payable - affiliates		193
Revenues payable		27,021
Accrued liabilities		52,923
Short-term derivative instruments		2,850
Total current liabilities		91,779
Long-term debt		2,000,579
Asset retirement obligations		162,989
Long-term derivative instruments		1,441
Deferred tax liabilities		2,094
Total liabilities	$	2,258,882

Below is a reconciliation of major line items constituting pretax profit (loss) of discontinued operations to the after tax profit (loss) of discontinued operations that are presented in the statement of operations (in thousands):

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Revenues:
Oil & natural gas sales	$	43,806		$	97,221		$	104,429		$	189,170
Other revenues		186			917			429			1,786
Total revenues		43,992			98,138			104,858			190,956
Costs and expenses:
Lease operating		19,347			44,888			55,043			85,366
Gathering, processing, and transportation		6,166			9,548			15,375			18,214
Exploration		3			32			125			122
Taxes other than income		2,534			6,058			6,542			12,713
Depreciation, depletion, and amortization		29,954			46,286			74,383			97,552
Impairment of proved oil and natural gas properties		—			—			8,342			251,347
General and administrative (1)		9,092			14,377			22,616			28,888
Accretion of asset retirement obligations		1,828			1,686			4,535			3,320
(Gain) loss on commodity derivative instruments		104,365			61,403			52,620			(84,056	)
(Gain) loss on sale of properties		—			—			(96	)		—
Other, net		—			(943	)		119			(943	)
Total costs and expenses		173,289			183,335			239,604			412,523
Operating income (loss)		(129,297	)		(85,197	)		(134,746	)		(221,567	)
Other income (expense):
Interest expense, net		(19,142	)		(27,910	)		(51,694	)		(56,728	)
Other, net		26,014			124			26,014			284
Total other income (expense)		6,872			(27,786	)		(25,680	)		(56,444	)
Pretax profit (loss) of discontinued operations		(122,425	)		(112,983	)		(160,426	)		(278,011	)
Income tax benefit (expense)		—			(876	)		(96	)		1,494
Net income (loss) from discontinued operations	$	(122,425	)	$	(113,859	)	$	(160,522	)	$	(276,517	)

(1) Included $4.4 million and $12.2 million, for the three and six months ended June 30, 2016; and $8.5 million and $17.0 million for the three and six months ended June 30, 2015 that was allocated to discontinued operations under an omnibus agreement.  This omnibus agreement was terminated on June 1, 2016, and we entered into a transition services agreement (“TSA”) with MEMP to manage post-closing separation costs and activities through February 2017. At June 30, 2016, we owed MEMP approximately $1.9 million under the TSA.

In connection with the sale of the Disposition Entities, we received $4.2 million from MEMP for the sale of furniture, fixtures, and other property and equipment. We also received an additional $5.4 million from MEMP related to both the settlement of a receivable that had been previously eliminated in consolidation and prepaid expenses. We paid MEMP approximately $1.9 million, which represented a settlement related to corporate office space.

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Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 4. Acquisitions and Divestitures

Transaction-related costs, which include costs associated with our proposed Merger with Range, 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,
2016		2015		2016		2015
$	6,179	$	126	$	6,209	$	1,407

2016 Acquisitions and Divestitures

There were no material acquisitions during the three and six months ended June 30, 2016. In addition, there were no material divestitures during the three and six months ended June 30, 2016, except for the Disposition Entities and their subsidiaries as discussed in Note 1.

2015 Acquisition and Divestitures

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 (the “Rockies Divestiture”) and recorded a gain of less than $0.1 million related to the sale.

On June 1, 2015, we entered into an oil and gas lease option agreement with a third party pursuant to which we have the right to obtain one or more oil and gas leases in North Louisiana. The option is exercisable through February 2017. The purchase price of this option was approximately $4.0 million. The purchase price has been capitalized as part of unproved properties and will be expensed if the option is not exercised.

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Fair Value Measurements of Financial Instruments

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements of Financial Instruments

Note 5. 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), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at June 30, 2016 and December 31, 2015. 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, 2016 and December 31, 2015 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, 2016 and December 31, 2015 for each of the fair value hierarchy levels:

	Fair Value Measurements at June 30, 2016 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	$	—	$	135,658	$	—	$	135,658
Liabilities:
Commodity derivatives	$	—	$	550	$	—	$	550

	Fair Value Measurements at December 31, 2015 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	319,762	$	—	$	319,762
Liabilities:
Commodity derivatives	$	—	$	480	$	—	$	480

See Note 6 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 7 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. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach.

· Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate 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.

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Risk Management and Derivative and Other Financial Instruments

6 Months Ended

Jun. 30, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Risk Management and Derivative and Other Financial Instruments

Note 6. Risk Management and Derivative and Other Financial Instruments

Derivative and other financial 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 and other financial instruments, 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, and other financial instruments 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 and other financial instruments is minimized by limiting exposure to any single counterparty and entering into derivative and other financial 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 or other financial 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 or other financial instrument, 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, 2016, we had net derivative and other financial assets of $162.4 million. After taking into effect netting arrangements, we had counterparty exposure of $16.6 million related to derivative and other financial instruments of which all was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $145.8 million against amounts outstanding under our revolving credit facility at June 30, 2016. See Note 8 for additional information regarding our revolving credit facility.

Commodity Derivatives and Other Financial Instruments

We may use a combination of commodity derivatives and other financial instruments (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, 2016 is net of deferred premiums of $10.5 million.

During the year ended December 31, 2015, we restructured our existing 2018 crude oil and natural gas hedges for crude oil and NGL swaps that will settle in 2016. Cash settlements of approximately $92.3 million from the terminated 2018 positions were received and applied as premiums for the new crude oil and NGL swaps. Certain contracts are classified as other financial instruments, which required bifurcation, based on the relationship between the fixed swap price and the market price at the restructure dates. Due to bifurcation, $27.3 million of the restructured contracts represents other financial assets at June 30, 2016.

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as TGT Z1 in proximity to our areas of production. We also enter into oil derivative contracts indexed primarily to NYMEX-WTI. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

At June 30, 2016, we had the following open commodity positions (excluding embedded derivatives):

	Remaining
	2016			2017
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,120,000			1,770,000
Weighted-average fixed price	$	4.06		$	4.24
Collar contracts:
Average Monthly Volume (MMBtu)		1,000,000			1,050,000
Weighted-average floor price	$	4.00		$	4.00
Weighted-average ceiling price	$	4.71		$	5.06
Purchased put option contracts:
Average Monthly Volume (MMBtu)		6,700,000			5,350,000
Weighted-average strike price	$	3.54		$	3.48
Weighted-average deferred premium	$	(0.34	)	$	(0.32	)
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		1,120,000			200,000
Spread - Henry Hub	$	(0.10	)	$	(0.08	)
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		32,833			28,000
Weighted-average fixed price	$	83.91		$	84.70
Collar contracts:
Average Monthly Volume (Bbls)		26,600			—
Weighted-average floor price	$	80.00		$	—
Weighted-average ceiling price	$	99.70		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		366,758			—
Weighted-average fixed price	$	39.93		$	—

At June 30, 2016, we had the following open embedded derivative positions:

	Remaining
	2016
Oil Hybrid Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		27,211
Weighted-average fixed price	$	46.50
Initial net investment price		62.29
Total contract swap price	$	108.79
NGL Hybrid Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		111,175
Weighted-average fixed price	$	15.77
Initial net investment price		25.61
Total contract swap price	$	41.38

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, 2016 and December 31, 2015. 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	2016			2015			2016			2015
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	98,937		$	228,349		$	343		$	358
Netting arrangements	Short-term derivative instruments		(343	)		(358	)		(343	)		(358	)
Net recorded fair value	Short-term derivative instruments	$	98,594		$	227,991		$	—		$	—
Commodity contracts	Long-term derivative instruments	$	36,721		$	91,413		$	207		$	122
Netting arrangements	Long-term derivative instruments		(207	)		(122	)		(207	)		(122	)
Net recorded fair value	Long-term derivative instruments	$	36,514		$	91,291		$	—		$	—

(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 periods indicated (in thousands):

		For the Three Months Ended				For the Six Months Ended
	Statements of	June 30,				June 30,
	Operations Location	2016		2015		2016		2015
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	90,617	$	30,463	$	54,175	$	(77,727	)

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 7. 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, 2016 (in thousands):

Asset retirement obligations at beginning of period	$	10,079
Liabilities added from acquisitions or drilling		530
Revision of estimates		(125	)
Accretion expense		295
Asset retirement obligations at end of period	$	10,779

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Long Term Debt

6 Months Ended

Jun. 30, 2016

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,
	2016			2015
	(In thousands)
$2.0 billion revolving credit facility, variable-rate, due June 2019	$	514,000		$	423,000
5.875% senior unsecured notes, due July 2022 ("Senior Notes") (1) (2)		600,000			600,000
Unamortized debt issuance costs		(10,098	)		(10,936	)
Total long-term debt	$	1,103,902		$	1,012,064

(1) The estimated fair value of this fixed-rate debt was $598.5 million and $525.0 million at June 30, 2016 and December 31, 2015, respectively.  

(2) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

On May 31, 2016, we entered into a sixth amendment to our revolving credit facility to, among other things, permit the sale of MEMP GP, Beta Operating and Services to MEMP.  Effective June 1, 2016, Beta Operating was automatically released as a guarantor and discharged from any and all obligations under or in connection with our revolving credit facility or other related loan documents. The liens on and security interests in the equity interests owned by us in each of MEMP GP, Beta Operating, and Services, and the mortgaged property owned by Beta Operating were automatically released.

Senior Notes

Effective June 1, 2016, the guarantor subsidiaries are 100% owned by the Company; the Company has no material assets or operations independent of the guarantor subsidiaries; and there are no significant restrictions upon the ability of the guarantor subsidiaries to distribute funds to the Company. Additionally, our Senior Notes are jointly and severally, fully and unconditional guaranteed (subject to customary release provisions) by the guarantor subsidiaries.

Borrowing Base

Credit facilities tied to borrowing base are common throughout the oil and gas industry. Our revolving credit facility borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for our credit facility was the following at the date indicated (in thousands):

	June 30,
	2016
$2.0 billion revolving credit facility, variable-rate, due June 2019	$	1,000,000

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,
	2016			2015			2016			2015
Revolving credit facility (1)		2.49	%		1.70	%		2.38	%		1.80	%

(1) As noted in the 2015 10-K, the Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the three months and six months ended for June 30, 2016 was 2.00% and 1.90%, respectively.  The Applicable Margin for the three months and six months ended June 30, 2015, was 1.50% and 1.57%, respectively.

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,
	2016		2015
	(In thousands)
Revolving credit facility	$	4,292	$	4,976
Senior Notes		10,098		10,936
Total unamortized deferred financing costs		14,390		15,912

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Stockholders' Equity and Noncontrolling Interests

6 Months Ended

Jun. 30, 2016

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, 2016:

Balance December 31, 2015	205,293,743
Restricted common shares issued (Note 11)	1,117,606
Restricted common shares repurchased (1)	(363,159	)
Restricted common shares forfeited	(9,877	)
Balance June 30, 2016	206,038,313

(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 $5.7 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

The Company 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. We have 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 was not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which could have been suspended or discontinued at any time. The Company did not repurchase any shares of common stock under the April 2015 repurchase program. The April 2015 repurchase program expired in April 2016.

Noncontrolling Interests

Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consisted of the equity interests held by: (i) the limited partners of MEMP prior to June 1, 2016 (see Note 1) and (ii) a third party investor in the San Pedro Bay Pipeline Company prior to November 3, 2015.  

Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. These distributions and contributions are a component of net cash provided by discontinued operations from financing activities as presented on our cash flow statement.

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Earnings per Share

6 Months Ended

Jun. 30, 2016

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,
	2016			2015			2016			2015
Numerator:
Net income (loss) from continuing operations available to common stockholders	$	(195,833	)	$	(26,614	)	$	(190,116	)	$	22,121
Net income (loss) from discontinued operations available to common stockholders		128			88			168			227
Denominator:
Weighted average common shares outstanding		203,948			189,628			203,807			190,163
Incremental treasury stock method shares (1)		310			364			39			329
Basic EPS from continuing operations	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Diluted EPS from continuing operations (1)	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Basic EPS from discontinued operations	$	—		$	—		$	—		$	—
Diluted EPS from discontinued operations (1)	$	—		$	—		$	—		$	—

(1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. The incremental treasury stock method shares were excluded from the computation of diluted EPS because the inclusion of such shares would have been anti-dilutive.

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Long-Term Incentive Plans

6 Months Ended

Jun. 30, 2016

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Long-Term Incentive Plans

Note 11. Long-Term Incentive Plans

The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan (“LTIP”) for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2015		1,668,845		$	18.89
Granted (2)		1,117,606		$	13.13
Forfeited		(9,877	)	$	18.84
Vested		(1,145,885	)	$	18.87
Restricted common shares outstanding at June 30, 2016 (3)		1,630,689		$	14.96

(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 2016 was $14.7 million based on a grant date market price ranging from $13.08 to $15.58 per share.

(3) Effective immediately prior to the effective time of the Merger, each outstanding share of our unvested restricted common stock will fully vest and any applicable restrictions will lapse and, at the effective time of the Merger, each such share will be treated as a share of our common stock, including with respect to the right to receive 0.375 of a fully vested share of Range Common Stock.

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,
2016		2015		2016		2015
$	10,521	$	1,957	$	13,673	$	3,443

The unrecognized compensation cost associated with restricted common share awards was $23.2 million at June 30, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.44 years.

LTIP Modification. On March 9, 2016, certain employees were impacted by an involuntary termination which, upon the Board’s approval, accelerated the vesting schedule of unvested awards under the LTIP that otherwise would have been forfeited upon a voluntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of $1.1 million was recognized.

On June 1, 2016, with the completion of the sale of the Disposition Entities and their subsidiaries to MEMP as discussed in Note 1, we accelerated the vesting schedule of unvested awards under the LTIP for the employees that remained with the Disposition Entities and their subsidiaries. The grant-date fair value compensation cost of approximately $2.5 million was reversed and the modified-date grant fair value compensation cost of $9.8 million was recognized.

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Incentive Units

6 Months Ended

Jun. 30, 2016

Compensation Related Costs [Abstract]

Incentive Units

Note 12. Incentive Units

MRD Holdco

MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in exchange for cancelled predecessor 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 compensation expense of $74.3 million and $52.6 million for the three and six months ended June 30, 2016, respectively, offset by a deemed capital contribution to MRD Holdco. The unrecognized compensation expense of approximately $6.2 million as of June 30, 2016 will be recognized over the remaining expected service period of 0.25 years.

The fair value of the Exchanged Incentive Units 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, adjustments to non-cash compensation expense will be allocated to us in future periods offset by deemed capital contributions or distributions. As such, these awards are not dilutive to our stockholders.

The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:

	Exchanged Incentive Units			Subsequent Incentive Units
Valuation date	6/30/2016			6/30/2016
Dividend yield		0	%		0	%
Expected volatility		55.00	%		55.00	%
Risk-free rate		0.26	%		0.26	%
Expected life (years)		0.25			0.25

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Related Party Transactions

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Related Party Transactions

Note 13. Related Party Transactions

Amounts due to MRD Holdco and certain affiliates of NGP at June 30, 2016 and December 31, 2015 are presented as “Accounts payable – affiliates” in the accompanying balance sheets.

NGP Affiliated Companies

During the three and six months ended June 30, 2016, we paid approximately $0.5 million and $3.8 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities.

During the three and six months ended June 30, 2016, we paid approximately $1.1 million and $3.5 million, respectively, to Multi-Shot, LLC, a NGP affiliated company, for services related to our drilling and completion activities, of which less than $0.1 million was attributable to discontinued operations.

During the three months ended June 30, 2016, we also paid a NGP affiliate company approximately $1.1 million for mineral interests located in North Louisiana.

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 and Voting Agreement

A discussion of these agreements is included in our 2015 Form 10-K.

Services Agreement

A discussion of this agreement is included in our 2015 Form 10-K. The services agreement was terminated effective March 1, 2015. During the six months ended June 30, 2015, we recognized approximately $2.0 million of general and administrative expenses under this agreement.

Midstream Agreements

We have various midstream service agreements with affiliates of PennTex Midstream Partners, LP (“PennTex”), an affiliate of NGP, for the gathering, processing and transportation of natural gas and NGLs. Additionally, we entered into an area of mutual interest and exclusivity agreement (“AMI”) with PennTex pursuant to which PennTex has the exclusive right to provide midstream services to support our current and future production in North Louisiana on our operated acreage within such area (other than production subject to existing third-party commitments). A discussion of these agreements is included in our 2015 Form 10-K.

Pursuant to the gas processing agreement, any deficiency payments made by the Company under this agreement will be treated as prepaid processing fees by PennTex (except for the June 2015 deficiency payment) because we may utilize these deficiency payments as credit for fees owed if we have delivered the total minimum volume commitment under the processing agreement within the initial term of the agreement. We must pay a quarterly deficiency payment based on the firm-commitment fixed fee if the cumulative minimum volume commitment as of the end of such quarter exceeds the sum of (i) the cumulative volumes processed (or credited with respect to plant interruptions) under the processing agreement as of the end of such quarter plus (ii) volumes corresponding to deficiency payments incurred prior to such quarter. During the three and six months ended June 30, 2016, we incurred $3.2 million and $6.5 million, respectively, of deficiency payments. As of June 30, 2016, we had $6.5 million of prepaid processing fees on our balance sheet in the “Other long-term assets” line.

All net costs associated with these agreements are reflected in the statement of operations in the “Gathering, processing, and transportation – affiliate” line.

Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement

A discussion of these agreements is included in our 2015 Form 10-K. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline and Gathering, LLC’s (“Classic Pipeline”) Joaquin gathering system. Additionally, Classic Pipeline assigned its salt water disposal system to MEMP in November 2015. For the three and six months ended June 30, 2015, MEMP incurred gathering and salt water disposal fees of approximately $1.1 million and $2.0 million, respectively, under these agreements. These fees are a component of net income (loss) from discontinued operations as presented on our statement of operations.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2016

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 14. 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.

Subsequent event. In July 2016, alleged stockholders (“Plaintiffs”) of the Company, filed two class action lawsuits against us and the members of our board of directors relating to the Merger. These lawsuits are styled (i) Roger Mariani v. Memorial Resource Development Corp., et al., Case No. 4:16-cv-2042, in the United States District Court for the Southern District of Texas, Houston Division; and (ii) Joel Morris v. Memorial Resource Development Corp., et al., Case No. 4:16-cv-02183, in the United States District Court for the Southern District of Texas, Houston Division. The Morris action also names Range and Merger Sub as additional defendants. Plaintiffs allege that the joint proxy statement/prospectus filed in connection with the Merger omits allegedly material information concerning, in general and among other things, (i) the valuation analyses prepared by Barclays Capital Inc. (“Barclays”) and Morgan Stanley & Co. LLC (“Morgan Stanley”) in connection with their fairness opinions regarding the Merger, (ii) the financial projections utilized by Barclays and Morgan Stanley and (iii) the background of the Merger. Based on these allegations, Plaintiffs allege that (i) the defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) members of our board of directors have violated Section 20(a) of the Exchange Act. Plaintiffs also allege, in general and among other things, that the terms of the Merger are (i) unfair to our stockholders and (ii) the result of an inadequate process. Based on these allegations, Plaintiffs seek to enjoin us from proceeding with or consummating the Merger. To the extent that the Merger is consummated before injunctive relief is granted, Plaintiffs seek to have the Merger rescinded. Plaintiffs also seek attorneys’ fees. Plaintiffs have not yet served the defendants, and our date to answer, move to dismiss, or otherwise respond to the lawsuit has not yet been set. We cannot predict the outcome of the lawsuits or any others that might be filed, nor can we predict the amount of time and expense that will be required to resolve the lawsuits. We intend to vigorously defend the lawsuits.

There were no environmental reserves recorded on our balance sheet at June 30, 2016 and December 31, 2015 associated with continuing operations.

Third Party Midstream Service Agreements (Gathering & Processing)

The Company has an existing amended and restated midstream service agreement with ETC Field Services LLC (formerly known as Regency Field Services LLC) (“ETC”) for the gathering and processing of natural gas in North Louisiana as discussed in our 2015 Form 10-K. ETC is entitled to receive a payback demand fee from us and other third parties equal to 110% of certain infrastructure improvement costs. The payback demand fee is based upon actual volumes gathered, but not less than a specified monthly demand quantity. Until payout is achieved, there is also a monthly demand quantity associated with gathering and processing fees.

We have the right to request that gas gathered by ETC be delivered to alternative delivery points for processing (e.g., PennTex). Under these circumstances, ETC assesses us a $0.25 per MMBtu gathering only fee to take gas off its system.

Firm Gas Transportation Service Agreement

The Company entered into a long-term firm transportation agreement with Regency Intrastate Gas LP (“RIGS”) to assure the delivery of its natural gas to market.  This agreement’s primary term terminates on December 31, 2025, subject to one-year extensions at either party’s election. This commitment requires a minimum monthly reservation charge that escalates annually by two percent regardless of whether the contracted capacity is used or not. An overrun charge that also escalates annually by two percent applies to gas received in excess of the contracted capacity. In addition to the demand and overrun fees, RIGS retains 1.25% of gas received for fuel. The following table summarizes the reserved capacity and applicable fees associated with this agreement:

Period	Reserved Capacity (MMBtu/d)		Reservation Demand Charge ($/MMBtu)		Overrun Charge ($/MMBtu)
January 1, 2016 to December 31, 2022		300,000		0.075		0.150
January 1, 2023 to December 31, 2025		200,000		0.075		0.150

In the future, additional receipt points may be developed. The following pricing grid, subject to annual escalation, would apply to gas received at any of these future receipt points.

	Reservation Demand Charge ($/MMBtu)		Commodity Charge ($/MMBtu)		Overrun Charge ($/MMBtu)
Total gas receipts ≤ contracted reserved capacity		0.075		0.075	n/a
Total gas receipts > contracted reserved capacity	n/a		n/a			0.150

Sales Delivery Commitment

Recently, the Company and a third party entered into a contract whereby the Company agreed to sell and deliver NGLs produced at gas processing plants owned and operated by PennTex. The NGLs are delivered to a pipeline owned by an affiliate of the third party. The initial term of the contract terminates on December 31, 2022, subject to one-year extensions at either party’s election. The price we receive is tied to published indices, net of transportation and fractionation deductions. Commencing April 1, 2016, through the end of the initial term of the agreement, the minimum sales volume commitment is 6,000 BPD. If we fail to deliver the minimum sales volume commitment, we will be required to pay a deficiency payment equal to transportation and fractionation deductions on undelivered volumes. Currently, transportation and fractionation deductions are approximately $4.39 per barrel.

Related Party Agreements

See Note 13 for additional information.

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Income Taxes

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Note 15. Income Taxes

The Company is a corporation subject to federal and state income taxes. The compensation expense associated with the incentive units of MRD Holdco (discussed in Note 12) creates a nondeductible permanent difference for income tax purposes. 

The Company’s income tax benefit from continuing operations for the three and six months ended June 30, 2016 was $25.3 million and $22.4 million, respectively, compared to $24.6 million of income tax benefit and $22.9 million of income tax expense for the three and six months ended June 30, 2015, respectively. The Company’s effective tax rate from continuing operations for the three and six months ended June 30, 2016 was 11.5% and 10.5%, respectively, compared to 48.1% and 49.0% for the three and six months ended June 30, 2015, respectively. The change in the effective tax rate from 2015 to 2016 was primarily due to a change in non-deductible incentive unit compensation as discussed in Note 12. The effective tax rate for the three and six months ended June 30, 2016 and 2015 differed from the statutory federal income tax rate primarily due to non-deductible incentive unit compensation expense, state income tax, net of federal benefit, and long-term incentive plan compensation expense.

We reported no liability for unrecognized tax benefits as of June 30, 2016 and expect no significant change to the unrecognized tax benefits in the next twelve months.

Consistent with establishing the deferred tax liability through stockholders’ equity in our initial public offering, we reversed a deferred tax liability of approximately $28.0 million through stockholders’ equity in 2015 attributable to the deferred tax effects of the Property Swap in 2015.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2016

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; (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) “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 (v) “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.

Basis of Presentation

Basis of Presentation

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Under the amended consolidation guidance that we adopted on January 1, 2016 (see Note 2), a limited partnership is considered a variable interest entity (“VIE”) unless a single limited partner or a simple majority of all partners have substantive kick-out or participating rights. The Company determined that MEMP was a VIE and we were deemed the primary beneficiary. On June 1, 2016, we completed the sale of MEMP GP, Beta Operating Company, LLC (“Beta Operating”) and MEMP Services LLC (“Services”) (collectively, the “Disposition Entities”), to MEMP for $0.75 million in cash. This sale was a reconsideration event under the amended consolidation guidance which resulted in the deconsolidation of the Partnership. Our equity statement reflects a loss of $0.1 million related to the deconsolidation of the Disposition Entities and their subsidiaries. Our financial statements have been retrospectively revised to reflect the Disposition Entities and their subsidiaries as discontinued operations for all periods presented (see Note 3). After the completion of the sale, we have one reportable business segment, which is engaged in the acquisition, exploration and development of oil and natural gas properties.  

All material intercompany transactions and balances have been eliminated in preparation of our consolidated financial statements. Our results of operations for the three and six months ended June 30, 2016 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”).

Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to the  acquisition by MEMP of certain assets from the Company in East Texas in February 2015 for certain properties in North Louisiana (the “Property Swap”).

Proposed Merger with Range Resources Corporation

Proposed Merger with Range Resources Corporation

On May 15, 2016, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Range Resources Corporation (“Range”), a Delaware corporation, and Medina Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of Range (“Merger Sub”). The Merger Agreement provides that, upon the terms and subject to the conditions set forth, the Merger Sub will be merged with and into the Company, with the Company continuing as the surviving entity and a wholly owned subsidiary of Range (“the Merger”).

If the Merger is completed, each share of our common stock outstanding immediately before that time (including outstanding shares of our restricted common stock, all of which will become fully vested and unrestricted under the terms of the Merger Agreement) will automatically be converted into the right to receive 0.375 of a share of Range common stock, par value of $0.01 per share (“Range Common Stock”). The Merger is subject to customary closing conditions, including the approval by both Memorial and Range stockholders. We expect the closing of the Merger will occur late in the third quarter of 2016.

In connection with the execution of the Merger Agreement, MRD Holdco, Jay Graham (our chief executive officer), Anthony Bahr and WHR Incentive LLC (a limited liability company controlled by Mr. Graham and Mr. Bahr) (collectively, the “Memorial Stockholders”) entered into a voting and support agreement with Range and have agreed to vote all of the shares held by them in favor of the approval and adoption of the Merger Agreement and the transactions contemplated by the Merger Agreement, including the merger. As of June 30, 2016, the Memorial Stockholders hold and are entitled to vote in the aggregate approximately 47.7% of the issued and outstanding shares of our common stock entitled to vote at our special meeting.  In addition, certain other stockholders of the Company who are not party to the voting and support agreement are party to an existing voting agreement, as discussed in our 2015 Form 10-K, pursuant to which those stockholders are required to vote all of the shares of our common stock that they own as directed by MRD Holdco. As of June 30, 2016, those additional stockholders hold and are entitled to vote in the aggregate approximately 2.7% of the outstanding shares of our common stock entitled to vote at our special meeting.

Upon completion of the Merger, our common stock currently listed on the NASDAQ will cease to be listed for trading on the NASDAQ and will subsequently be deregistered under the Securities Exchange Act of 1934, as amended.

Use of Estimates

Use of Estimates

The preparation of the accompanying unaudited condensed consolidated 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 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; realization of long-term prepaid processing fees; 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.

Oil and Natural Gas Properties

Oil and Natural Gas Properties

Oil and natural gas properties consisted of the following at the dates indicated (in thousands):

	June 30,		December 31,
	2016		2015
	(In thousands)
Proved oil and natural gas properties	$	1,984,500	$	1,740,530
Support equipment and facilities		7,191		4,719
Unproved oil and natural gas properties		417,920		414,759
Total oil and natural gas properties	$	2,409,611	$	2,160,008

At June 30, 2016 and December 31, 2015, we had $147.4 million and $174.0 million, respectively, capitalized in proved oil and natural gas properties related to wells in various stages of drilling and completion, which have been excluded from the depletion base.

Accrued liabilities

Accrued liabilities

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

	June 30,		December 31,
	2016		2015
Accrued capital expenditures	$	24,084	$	40,197
Accrued interest payable		17,665		17,657
Accrued lease operating expense		1,414		2,031
Accrued general and administrative expenses		5,871		4,030
Accrued ad valorem taxes		1,619		157
Accrued current income taxes		20,007		1,911
Other miscellaneous, including operator advances		1,404		2,893
Total accrued liabilities	$	72,064	$	68,876

Supplemental Cash Flow Information

Supplemental Cash Flow Information

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

	For the Six Months Ended
	June 30,
	2016			2015
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	22,418		$	35,650
Cash paid for taxes		3,800			2,000
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(16,113	)		25,560
(Increase) decrease in accounts receivable related to other financial instruments		2,633			—
Assumptions of asset retirement obligations related to properties acquired or drilled		530			—

New Accounting Pronouncements

New Accounting Pronouncements

Improvements to Employee Share-Based Payment Accounting. In March 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in additional paid-in capital (“APIC”). Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement and the APIC pools will be eliminated. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before companies can recognize them and requires companies to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires a company to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, companies will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required.  

The new guidance is effective for reporting periods beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. The Company is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively.

Leases. In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company is currently evaluating the standard and the impact on the Company’s financial statements and related footnote 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. We adopted this guidance on January 1, 2016 and determined that MEMP was a VIE for which the Company is the primary beneficiary for accounting purposes. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements. On June 1, 2016, we completed the sale of the Disposition Entities to MEMP as discussed in Note 1, which triggered a reconsideration event under the guidance which resulted in the deconsolidation of the Partnership.  

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.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Schedule of Oil and Natural Gas Properties

Oil and natural gas properties consisted of the following at the dates indicated (in thousands):

	June 30,		December 31,
	2016		2015
	(In thousands)
Proved oil and natural gas properties	$	1,984,500	$	1,740,530
Support equipment and facilities		7,191		4,719
Unproved oil and natural gas properties		417,920		414,759
Total oil and natural gas properties	$	2,409,611	$	2,160,008

Schedule of Accrued Liabilities

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

	June 30,		December 31,
	2016		2015
Accrued capital expenditures	$	24,084	$	40,197
Accrued interest payable		17,665		17,657
Accrued lease operating expense		1,414		2,031
Accrued general and administrative expenses		5,871		4,030
Accrued ad valorem taxes		1,619		157
Accrued current income taxes		20,007		1,911
Other miscellaneous, including operator advances		1,404		2,893
Total accrued liabilities	$	72,064	$	68,876

Schedule of Supplemental Cash Flow from Continuing Operations

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

	For the Six Months Ended
	June 30,
	2016			2015
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	22,418		$	35,650
Cash paid for taxes		3,800			2,000
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(16,113	)		25,560
(Increase) decrease in accounts receivable related to other financial instruments		2,633			—
Assumptions of asset retirement obligations related to properties acquired or drilled		530			—

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Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2016

Discontinued Operations And Disposal Groups [Abstract]

Schedule of Reconciliation of Carrying Amounts of Major Classes of Assets and Liabilities Included as Part of Discontinued Operations

Below is a reconciliation of carrying amounts of major classes of assets and liabilities included as part of discontinued operations as reflected on the balance sheet associated with this disposal transaction (in thousands):

	December 31,
	2015
ASSETS
Current assets:
Cash and cash equivalents	$	2,175
Accounts receivable		61,404
Short-term derivative instruments		272,320
Prepaid expenses and other current assets		9,642
Total current assets		345,541
Property and equipment, net		1,946,937
Long-term derivative instruments		461,810
Restricted investments		152,631
Other long-term assets		5,053
Total assets	$	2,911,972
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,792
Accounts payable - affiliates		193
Revenues payable		27,021
Accrued liabilities		52,923
Short-term derivative instruments		2,850
Total current liabilities		91,779
Long-term debt		2,000,579
Asset retirement obligations		162,989
Long-term derivative instruments		1,441
Deferred tax liabilities		2,094
Total liabilities	$	2,258,882

Schedule of Reconciliation of Major Line Items Constituting Pretax Profit (Loss) of Discontinued Operations to After Tax Profit (Loss) of Discontinued Operations

Below is a reconciliation of major line items constituting pretax profit (loss) of discontinued operations to the after tax profit (loss) of discontinued operations that are presented in the statement of operations (in thousands):

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Revenues:
Oil & natural gas sales	$	43,806		$	97,221		$	104,429		$	189,170
Other revenues		186			917			429			1,786
Total revenues		43,992			98,138			104,858			190,956
Costs and expenses:
Lease operating		19,347			44,888			55,043			85,366
Gathering, processing, and transportation		6,166			9,548			15,375			18,214
Exploration		3			32			125			122
Taxes other than income		2,534			6,058			6,542			12,713
Depreciation, depletion, and amortization		29,954			46,286			74,383			97,552
Impairment of proved oil and natural gas properties		—			—			8,342			251,347
General and administrative (1)		9,092			14,377			22,616			28,888
Accretion of asset retirement obligations		1,828			1,686			4,535			3,320
(Gain) loss on commodity derivative instruments		104,365			61,403			52,620			(84,056	)
(Gain) loss on sale of properties		—			—			(96	)		—
Other, net		—			(943	)		119			(943	)
Total costs and expenses		173,289			183,335			239,604			412,523
Operating income (loss)		(129,297	)		(85,197	)		(134,746	)		(221,567	)
Other income (expense):
Interest expense, net		(19,142	)		(27,910	)		(51,694	)		(56,728	)
Other, net		26,014			124			26,014			284
Total other income (expense)		6,872			(27,786	)		(25,680	)		(56,444	)
Pretax profit (loss) of discontinued operations		(122,425	)		(112,983	)		(160,426	)		(278,011	)
Income tax benefit (expense)		—			(876	)		(96	)		1,494
Net income (loss) from discontinued operations	$	(122,425	)	$	(113,859	)	$	(160,522	)	$	(276,517	)

(1) Included $4.4 million and $12.2 million, for the three and six months ended June 30, 2016; and $8.5 million and $17.0 million for the three and six months ended June 30, 2015 that was allocated to discontinued operations under an omnibus agreement.  This omnibus agreement was terminated on June 1, 2016, and we entered into a transition services agreement (“TSA”) with MEMP to manage post-closing separation costs and activities through February 2017. At June 30, 2016, we owed MEMP approximately $1.9 million under the TSA.

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Acquisitions and Divestitures (Tables)

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

Transaction-Related Costs

Transaction-related costs, which include costs associated with our proposed Merger with Range, 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,
2016		2015		2016		2015
$	6,179	$	126	$	6,209	$	1,407

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Fair Value Measurements of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016 and December 31, 2015 for each of the fair value hierarchy levels:

	Fair Value Measurements at June 30, 2016 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	$	—	$	135,658	$	—	$	135,658
Liabilities:
Commodity derivatives	$	—	$	550	$	—	$	550

	Fair Value Measurements at December 31, 2015 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	319,762	$	—	$	319,762
Liabilities:
Commodity derivatives	$	—	$	480	$	—	$	480

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Risk Management and Derivative and Other Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Schedule of Open Commodity Positions

At June 30, 2016, we had the following open commodity positions (excluding embedded derivatives):

	Remaining
	2016			2017
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,120,000			1,770,000
Weighted-average fixed price	$	4.06		$	4.24
Collar contracts:
Average Monthly Volume (MMBtu)		1,000,000			1,050,000
Weighted-average floor price	$	4.00		$	4.00
Weighted-average ceiling price	$	4.71		$	5.06
Purchased put option contracts:
Average Monthly Volume (MMBtu)		6,700,000			5,350,000
Weighted-average strike price	$	3.54		$	3.48
Weighted-average deferred premium	$	(0.34	)	$	(0.32	)
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		1,120,000			200,000
Spread - Henry Hub	$	(0.10	)	$	(0.08	)
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		32,833			28,000
Weighted-average fixed price	$	83.91		$	84.70
Collar contracts:
Average Monthly Volume (Bbls)		26,600			—
Weighted-average floor price	$	80.00		$	—
Weighted-average ceiling price	$	99.70		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		366,758			—
Weighted-average fixed price	$	39.93		$	—

At June 30, 2016, we had the following open embedded derivative positions:

	Remaining
	2016
Oil Hybrid Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		27,211
Weighted-average fixed price	$	46.50
Initial net investment price		62.29
Total contract swap price	$	108.79
NGL Hybrid Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		111,175
Weighted-average fixed price	$	15.77
Initial net investment price		25.61
Total contract swap price	$	41.38

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, 2016 and December 31, 2015. 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	2016			2015			2016			2015
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	98,937		$	228,349		$	343		$	358
Netting arrangements	Short-term derivative instruments		(343	)		(358	)		(343	)		(358	)
Net recorded fair value	Short-term derivative instruments	$	98,594		$	227,991		$	—		$	—
Commodity contracts	Long-term derivative instruments	$	36,721		$	91,413		$	207		$	122
Netting arrangements	Long-term derivative instruments		(207	)		(122	)		(207	)		(122	)
Net recorded fair value	Long-term derivative instruments	$	36,514		$	91,291		$	—		$	—

Schedule of Gains and Losses Related to Derivative Instruments

The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):

		For the Three Months Ended				For the Six Months Ended
	Statements of	June 30,				June 30,
	Operations Location	2016		2015		2016		2015
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	90,617	$	30,463	$	54,175	$	(77,727	)

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016 (in thousands):

Asset retirement obligations at beginning of period	$	10,079
Liabilities added from acquisitions or drilling		530
Revision of estimates		(125	)
Accretion expense		295
Asset retirement obligations at end of period	$	10,779

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Long Term Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Consolidated Debt Obligations

The following table presents our consolidated debt obligations at the dates indicated:

	June 30,			December 31,
	2016			2015
	(In thousands)
$2.0 billion revolving credit facility, variable-rate, due June 2019	$	514,000		$	423,000
5.875% senior unsecured notes, due July 2022 ("Senior Notes") (1) (2)		600,000			600,000
Unamortized debt issuance costs		(10,098	)		(10,936	)
Total long-term debt	$	1,103,902		$	1,012,064

(1) The estimated fair value of this fixed-rate debt was $598.5 million and $525.0 million at June 30, 2016 and December 31, 2015, respectively.  

(2) 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 our credit facility was the following at the date indicated (in thousands):

	June 30,
	2016
$2.0 billion revolving credit facility, variable-rate, due June 2019	$	1,000,000

Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations

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,
	2016			2015			2016			2015
Revolving credit facility (1)		2.49	%		1.70	%		2.38	%		1.80	%

(1) As noted in the 2015 10-K, the Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the three months and six months ended for June 30, 2016 was 2.00% and 1.90%, respectively.  The Applicable Margin for the three months and six months ended June 30, 2015, was 1.50% and 1.57%, respectively.

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,
	2016		2015
	(In thousands)
Revolving credit facility	$	4,292	$	4,976
Senior Notes		10,098		10,936
Total unamortized deferred financing costs		14,390		15,912

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Stockholders' Equity and Noncontrolling Interests (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016:

Balance December 31, 2015	205,293,743
Restricted common shares issued (Note 11)	1,117,606
Restricted common shares repurchased (1)	(363,159	)
Restricted common shares forfeited	(9,877	)
Balance June 30, 2016	206,038,313

(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 $5.7 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.

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Earnings per Share (Tables)

6 Months Ended

Jun. 30, 2016

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,
	2016			2015			2016			2015
Numerator:
Net income (loss) from continuing operations available to common stockholders	$	(195,833	)	$	(26,614	)	$	(190,116	)	$	22,121
Net income (loss) from discontinued operations available to common stockholders		128			88			168			227
Denominator:
Weighted average common shares outstanding		203,948			189,628			203,807			190,163
Incremental treasury stock method shares (1)		310			364			39			329
Basic EPS from continuing operations	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Diluted EPS from continuing operations (1)	$	(0.96	)	$	(0.14	)	$	(0.93	)	$	0.12
Basic EPS from discontinued operations	$	—		$	—		$	—		$	—
Diluted EPS from discontinued operations (1)	$	—		$	—		$	—		$	—

(1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. The incremental treasury stock method shares were excluded from the computation of diluted EPS because the inclusion of such shares would have been anti-dilutive.

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Long-Term Incentive Plans (Tables)

6 Months Ended

Jun. 30, 2016

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Summary of Information Regarding Restricted Common Stock Awards

The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan (“LTIP”) for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2015		1,668,845		$	18.89
Granted (2)		1,117,606		$	13.13
Forfeited		(9,877	)	$	18.84
Vested		(1,145,885	)	$	18.87
Restricted common shares outstanding at June 30, 2016 (3)		1,630,689		$	14.96

(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 2016 was $14.7 million based on a grant date market price ranging from $13.08 to $15.58 per share.

(3) Effective immediately prior to the effective time of the Merger, each outstanding share of our unvested restricted common stock will fully vest and any applicable restrictions will lapse and, at the effective time of the Merger, each such share will be treated as a share of our common stock, including with respect to the right to receive 0.375 of a fully vested share of Range Common Stock.

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,
2016		2015		2016		2015
$	10,521	$	1,957	$	13,673	$	3,443

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Incentive Units (Tables)

6 Months Ended

Jun. 30, 2016

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	6/30/2016			6/30/2016
Dividend yield		0	%		0	%
Expected volatility		55.00	%		55.00	%
Risk-free rate		0.26	%		0.26	%
Expected life (years)		0.25			0.25

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2016

Commitments And Contingencies Disclosure [Abstract]

Summary of Reserved Capacity and Applicable Fees

The following table summarizes the reserved capacity and applicable fees associated with this agreement:

Period	Reserved Capacity (MMBtu/d)		Reservation Demand Charge ($/MMBtu)		Overrun Charge ($/MMBtu)
January 1, 2016 to December 31, 2022		300,000		0.075		0.150
January 1, 2023 to December 31, 2025		200,000		0.075		0.150

Summary of Pricing Grid Subject to Annual Escalation for Gas Received

The following pricing grid, subject to annual escalation, would apply to gas received at any of these future receipt points.

	Reservation Demand Charge ($/MMBtu)		Commodity Charge ($/MMBtu)		Overrun Charge ($/MMBtu)
Total gas receipts ≤ contracted reserved capacity		0.075		0.075	n/a
Total gas receipts > contracted reserved capacity	n/a		n/a			0.150

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Background, Organization and Basis of Presentation - Additional Information (Detail) $ / shares in Units, $ in Thousands		1 Months Ended		6 Months Ended
	Jun. 01, 2016 USD ($)	Jun. 30, 2016 Segment $ / shares	Feb. 28, 2015 USD ($)	Jun. 30, 2016 USD ($) $ / shares	Jun. 30, 2015 USD ($)	May 15, 2016 $ / shares	Dec. 31, 2015 $ / shares
Consolidation And Basis Of Presentation [Line Items]
Proceeds from sale of subsidiaries				$ 750	$ 0
Number of reportable business segments | Segment		1
Equity transfer from stockholders’ equity to noncontrolling interest			$ 127,100
Common stock, par value | $ / shares		$ 0.01		$ 0.01			$ 0.01
Percentage of voting rights held by stockholders		47.70%		47.70%
Percentage of voting rights held by additional stockholders		2.70%		2.70%
Range Resources Corporation [Member] | Scenario Plan [Member]
Consolidation And Basis Of Presentation [Line Items]
Share exchange ratio due to merger						0.375
Common stock, par value | $ / shares						$ 0.01
Disposition Entities [Member]
Consolidation And Basis Of Presentation [Line Items]
Proceeds from sale of subsidiaries	$ 750
Loss related deconsolidation				$ (100)

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Summary of Significant Accounting Policies - Schedule of Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Proved oil and natural gas properties	$ 1,984,500	$ 1,740,530
Support equipment and facilities	7,191	4,719
Unproved oil and natural gas properties	417,920	414,759
Total oil and natural gas properties	$ 2,409,611	$ 2,160,008

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Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Capitalized in proved oil and natural gas properties	$ 147.4	$ 174.0

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Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Accrued capital expenditures	$ 24,084	$ 40,197
Accrued interest payable	17,665	17,657
Accrued lease operating expense	1,414	2,031
Accrued general and administrative expenses	5,871	4,030
Accrued ad valorem taxes	1,619	157
Accrued current income taxes	20,007	1,911
Other miscellaneous, including operator advances	1,404	2,893
Total accrued liabilities	$ 72,064	$ 68,876

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Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow from Continuing Operations (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 22,418	$ 35,650
Cash paid for taxes	3,800	2,000
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	(16,113)	25,560
(Increase) decrease in accounts receivable related to other financial instruments	2,633	0
Assumptions of asset retirement obligations related to properties acquired or drilled	$ 530	$ 0

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Discontinued Operations - Schedule of Reconciliation of Carrying Amounts of Major Classes of Assets and Liabilities Included as Part of Discontinued Operations (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	May 31, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 14,960	$ 2,175	$ 4,701	$ 2,594
Short-term derivative instruments	$ 98,594		227,991
Total current assets	0		345,541
Long-term derivative instruments	36,514		91,291
Current liabilities:
Accounts payable - affiliates	8,062		5,016
Revenues payable	34,117		34,026
Total current liabilities	0		91,779
Long-term debt	1,103,902		1,012,064
Asset retirement obligations	$ 10,779		10,079
Disposition Entities [Member] | Discontinued Operations [Member]
Current assets:
Cash and cash equivalents			2,175
Accounts receivable			61,404
Short-term derivative instruments			272,320
Prepaid expenses and other current assets			9,642
Total current assets			345,541
Property and equipment, net			1,946,937
Long-term derivative instruments			461,810
Restricted investments			152,631
Other long-term assets			5,053
Total assets			2,911,972
Current liabilities:
Accounts payable			8,792
Accounts payable - affiliates			193
Revenues payable			27,021
Accrued liabilities			52,923
Short-term derivative instruments			2,850
Total current liabilities			91,779
Long-term debt			2,000,579
Asset retirement obligations			162,989
Long-term derivative instruments			1,441
Deferred tax liabilities			2,094
Total liabilities			$ 2,258,882

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Discontinued Operations - Schedule of Reconciliation of Major Line Items Constituting Pretax Profit (Loss) of Discontinued Operations to After Tax Profit (Loss) of Discontinued Operations (Detail) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues:
Oil & natural gas sales		$ 98,986	$ 78,605	$ 180,064	$ 165,628
Costs and expenses:
Lease operating		8,189	3,854	14,903	9,076
Gathering, processing, and transportation		23,353	14,289	45,294	29,052
Exploration		4,612	2,230	7,058	2,956
Taxes other than income		2,991	3,140	5,855	5,915
Accretion of asset retirement obligations		156	93	295	216
(Gain) loss on commodity derivative instruments		90,617	30,463	54,175	(77,727)
(Gain) loss on sale of properties			50	50	50
Other income (expense):
Interest expense, net		(12,767)	(9,613)	(24,124)	(19,369)
Other, net		(112)	(52)	(108)	(101)
Total other income (expense)		(12,879)	(9,665)	(24,232)	(19,470)
Pretax profit (loss) of discontinued operations		(122,425)	(112,983)	(160,426)	(278,011)
Income tax benefit (expense)			(876)	(96)	1,494
Net income (loss) from discontinued operations		(122,425)	(113,859)	(160,522)	(276,517)
Disposition Entities [Member] | Discontinued Operations [Member]
Revenues:
Oil & natural gas sales		43,806	97,221	104,429	189,170
Other revenues		186	917	429	1,786
Total revenues		43,992	98,138	104,858	190,956
Costs and expenses:
Lease operating		19,347	44,888	55,043	85,366
Gathering, processing, and transportation		6,166	9,548	15,375	18,214
Exploration		3	32	125	122
Taxes other than income		2,534	6,058	6,542	12,713
Depreciation, depletion, and amortization		29,954	46,286	74,383	97,552
Impairment of proved oil and natural gas properties		0	0	8,342	251,347
General and administrative	[1]	9,092	14,377	22,616	28,888
Accretion of asset retirement obligations		1,828	1,686	4,535	3,320
(Gain) loss on commodity derivative instruments		104,365	61,403	52,620	(84,056)
(Gain) loss on sale of properties		0	0	(96)	0
Other, net		0	(943)	119	(943)
Total costs and expenses		173,289	183,335	239,604	412,523
Operating income (loss)		(129,297)	(85,197)	(134,746)	(221,567)
Other income (expense):
Interest expense, net		(19,142)	(27,910)	(51,694)	(56,728)
Other, net		26,014	124	26,014	284
Total other income (expense)		6,872	(27,786)	(25,680)	(56,444)
Pretax profit (loss) of discontinued operations		(122,425)	(112,983)	(160,426)	(278,011)
Income tax benefit (expense)		0	(876)	(96)	1,494
Net income (loss) from discontinued operations		$ (122,425)	$ (113,859)	$ (160,522)	$ (276,517)

[1] (1) Included $4.4 million and $12.2 million, for the three and six months ended June 30, 2016; and $8.5 million and $17.0 million for the three and six months ended June 30, 2015 that was allocated to discontinued operations under an omnibus agreement. This omnibus agreement was terminated on June 1, 2016, and we entered into a transition services agreement (“TSA”) with MEMP to manage post-closing separation costs and activities through February 2017. At June 30, 2016, we owed MEMP approximately $1.9 million under the TSA.

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Discontinued Operations - Schedule of Reconciliation of Major Line Items Constituting Pretax Profit (Loss) of Discontinued Operations to After Tax Profit (Loss) of Discontinued Operations (Parenthetical) (Detail) - Disposition Entities [Member] - Discontinued Operations [Member] - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
General and administrative	[1]	$ 9,092	$ 14,377	$ 22,616	$ 28,888
Omnibus Agreement [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
General and administrative		4,400	$ 8,500	12,200	$ 17,000
Transition Services Agreement [Member] | MEMP [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
General and administrative expense payable		$ 1,900		$ 1,900

[1] (1) Included $4.4 million and $12.2 million, for the three and six months ended June 30, 2016; and $8.5 million and $17.0 million for the three and six months ended June 30, 2015 that was allocated to discontinued operations under an omnibus agreement. This omnibus agreement was terminated on June 1, 2016, and we entered into a transition services agreement (“TSA”) with MEMP to manage post-closing separation costs and activities through February 2017. At June 30, 2016, we owed MEMP approximately $1.9 million under the TSA.

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Discontinued Operations - Additional Information (Detail) - Discontinued Operations [Member] - MEMP [Member] $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from sale of furniture, fixtures and other property and equipment	$ 4.2
Proceeds from settlement of receivable	5.4
Payments for settlement related to corporate office space	$ 1.9

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Acquisitions and Divestitures - Transaction Related Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
General and administrative expense [Member]
Business Acquisition [Line Items]
Acquisition related costs	$ 6,179	$ 126	$ 6,209	$ 1,407

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Acquisitions and Divestitures - Additional Information (Detail) $ in Thousands			3 Months Ended	6 Months Ended
	Jun. 01, 2015 USD ($)	Apr. 17, 2015 USD ($)	Jun. 30, 2016 Acquisition Divestiture	Jun. 30, 2016 USD ($) Acquisition Divestiture	Jun. 30, 2015 USD ($)
Business Acquisition And Divestiture [Line Items]
Number of material acquisitions | Acquisition			0	0
Number of divestitures | Divestiture			0	0
Proceeds from sale of subsidiaries				$ 750	$ 0
North Louisiana [Member]
Business Acquisition And Divestiture [Line Items]
Payments to acquire oil and gas properties and leases	$ 4,000
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from sale of subsidiaries		$ 13,600
Gain (loss) on sale of oil and gas properties		$ 100

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Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value, Measurements [Member] - Commodity derivatives [Member] - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Assets:
Fair value of derivative asset	$ 135,658	$ 319,762
Liabilities:
Fair value of derivative liability	550	480
Quoted Prices in Active Market (Level 1) [Member]
Assets:
Fair value of derivative asset	0	0
Liabilities:
Fair value of derivative liability	0	0
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	135,658	319,762
Liabilities:
Fair value of derivative liability	550	480
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Fair value of derivative asset	0	0
Liabilities:
Fair value of derivative liability	$ 0	$ 0

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Risk Management and Derivative and Other Financial Instruments - Additional Information (Detail) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk	$ 145,800,000
Effect netting arrangements, counterparty exposure	16,600,000
Derivative asset	162,400,000
Deferred premiums	10,500,000
Cash settlement receipt		$ 92,300,000
Other financial assets	27,253,000	$ 46,106,000
Cash collateral received or pledged	$ 0

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Risk Management and Derivative and Other Financial Instruments - Schedule of Open Commodity Positions Excluding Embedded Derivatives (Detail)	6 Months Ended
	Jun. 30, 2016 MMBTU $ / MMBTU bbl
Natural Gas Derivative Fixed Price Swap 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,770,000
Weighted-average fixed price	4.24
Natural Gas Derivative Collar 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,050,000
Weighted-average floor price	4.00
Weighted-average ceiling price	5.06
Natural Gas Derivative Put Option 2017 [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	5,350,000
Weighted-average strike price	3.48
Weighted-average deferred premium	(0.32)
Natural Gas Derivative TGTZ1 Swap 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	200,000
Natural Gas Derivative TGTZ1 Swap Henry Hub 2017 [Member]
Derivative [Line Items]
Spread	(0.08)
Crude Oil Derivative Fixed Price Swap 2017 [Member]
Derivative [Line Items]
Weighted-average fixed price	84.70
Average Monthly Volume (Bbls) | bbl	28,000
Natural Gas Derivative Fixed Price Swap 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,120,000
Weighted-average fixed price	4.06
Natural Gas Derivative Collar 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,000,000
Weighted-average floor price	4.00
Weighted-average ceiling price	4.71
Natural Gas Derivative Put Option 2016 [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	6,700,000
Weighted-average strike price	3.54
Weighted-average deferred premium	(0.34)
Natural Gas Derivative TGTZ1 Swap 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,120,000
Natural Gas Derivative TGTZ1 Swap Henry Hub 2016 [Member]
Derivative [Line Items]
Spread	(0.10)
Crude Oil Derivative Fixed Price Swap 2016 [Member]
Derivative [Line Items]
Weighted-average fixed price	83.91
Average Monthly Volume (Bbls) | bbl	32,833
Crude Oil Derivative Collar 2016 [Member]
Derivative [Line Items]
Weighted-average floor price	80.00
Weighted-average ceiling price	99.70
Average Monthly Volume (Bbls) | bbl	26,600
NGL Derivative Fixed Price Swap 2016 [Member]
Derivative [Line Items]
Weighted-average fixed price	39.93
Average Monthly Volume (Bbls) | bbl	366,758

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Risk Management and Derivative and Other Financial Instruments - Schedule of Open Embedded Derivative Positions (Detail) - 2016 [Member] - Fixed price swap contracts [Member]	6 Months Ended
	Jun. 30, 2016 $ / bbl bbl
Oil Hybrid Contracts [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	27,211
Weighted-average fixed price	46.50
Initial net investment price	62.29
Total contract swap price	108.79
NGL Hybrid Contracts [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	111,175
Weighted-average fixed price	15.77
Initial net investment price	25.61
Total contract swap price	41.38

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Risk Management and Derivative and Other Financial 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, 2016	Dec. 31, 2015
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 98,594	$ 227,991
Asset Derivatives, Net recorded fair value	36,514	91,291
Short-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Netting arrangements	(343)	(358)
Liability Derivatives, Netting arrangements	(343)	(358)
Liability Derivatives, Net recorded fair value	0	0
Short-term derivative instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	98,937	228,349
Liability Derivatives, Gross fair value	343	358
Long-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Netting arrangements	(207)	(122)
Liability Derivatives, Netting arrangements	(207)	(122)
Liability Derivatives, Net recorded fair value	0	0
Long-term derivative instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	36,721	91,413
Liability Derivatives, Gross fair value	$ 207	$ 122

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Risk Management and Derivative and Other Financial Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	$ 90,617	$ 30,463	$ 54,175	$ (77,727)
Commodity derivative contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	$ 90,617	$ 30,463	$ 54,175	$ (77,727)

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Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period			$ 10,079
Liabilities added from acquisitions or drilling			530
Revision of estimates			(125)
Accretion expense	$ 156	$ 93	295	$ 216
Asset retirement obligations at end of period	$ 10,779		$ 10,779

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Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized debt issuance costs		$ (14,390)	$ (15,912)
Long-term debt		1,103,902	1,012,064
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Credit facility		514,000	423,000
Unamortized debt issuance costs		(4,292)	(4,976)
5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	[1],[2]	600,000	600,000
Unamortized debt issuance costs		$ (10,098)	$ (10,936)

[1] 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 $598.5 million and $525.0 million at June 30, 2016 and December 31, 2015, respectively.

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Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 2,000,000,000
Maturity date	Jun. 18, 2019
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	$ 598,500,000	$ 525,000,000

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Long Term Debt - Additional Information (Detail)	Jun. 01, 2016
Guarantor Subsidiaries [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Ownership percentage on guarantor subsidiaries	100.00%

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Long Term Debt - Borrowing Base Credit Facility (Detail)	Jun. 30, 2016 USD ($)
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 1,000,000,000

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Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Jun. 30, 2016 USD ($)
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000

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Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail)		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	[1]	2.49%	1.70%	2.38%	1.80%

[1] As noted in the 2015 10-K, the Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the three months and six months ended for June 30, 2016 was 2.00% and 1.90%, respectively. The Applicable Margin for the three months and six months ended June 30, 2015, was 1.50% and 1.57%, respectively.

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Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Parenthetical) (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Debt Disclosure [Abstract]
Base rate borrowing percentage	2.00%	1.50%	1.90%	1.57%

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Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 14,390	$ 15,912
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	4,292	4,976
Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 10,098	$ 10,936

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Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) - USD ($)		1 Months Ended	6 Months Ended
	Mar. 16, 2015	Apr. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Statement Of Stockholders Equity [Abstract]
Common stock, shares authorized			600,000,000		600,000,000
Common stock, par value			$ 0.01		$ 0.01
Payments for repurchase of common stock	$ 47,800,000			$ 47,785,000
Stock repurchased and retired during period, shares	2,764,887	0
Stock repurchase program, authorized amount		$ 50,000,000
Stock Repurchase Program Expiration Date			2016-04

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Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail)	6 Months Ended
	Jun. 30, 2016 shares
Class of Stock [Line Items]
Beginning Balance	205,293,743
Ending Balance	206,038,313
Common Stock [Member]
Class of Stock [Line Items]
Restricted common shares issued (Note 11)	1,117,606
Restricted common shares repurchased	(363,159)
Restricted common shares forfeited	(9,877)

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Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Parenthetical) (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Statement Of Stockholders Equity [Abstract]
Payments remitted for employees tax obligations	$ 5.7

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Numerator:
Net income (loss) from continuing operations available to common stockholders		$ (195,833)	$ (26,614)	$ (190,116)	$ 22,121
Net income (loss) from discontinued operations available to common stockholders		$ 128	$ 88	$ 168	$ 227
Denominator:
Weighted average common shares outstanding		203,948	189,628	203,807	190,163
Incremental treasury stock method shares	[1]	310	364	39	329
Basic EPS from continuing operations		$ (0.96)	$ (0.14)	$ (0.93)	$ 0.12
Diluted EPS from continuing operations	[1]	(0.96)	(0.14)	(0.93)	0.12
Basic EPS from discontinued operations		0	0	0	0
Diluted EPS from discontinued operations	[1]	$ 0	$ 0	$ 0	$ 0

[1] The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. The incremental treasury stock method shares were excluded from the computation of diluted EPS because the inclusion of such shares would have been anti-dilutive.

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Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Stock [Member]	6 Months Ended
	Jun. 30, 2016 $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common shares outstanding, Number of Shares, Beginning Balance | shares	1,668,845
Granted, Number of Shares | shares	1,117,606
Forfeited, Number of Shares | shares	(9,877)
Vested, Number of Shares | shares	(1,145,885)
Restricted common shares outstanding, Number of Shares, Ending Balance | shares	1,630,689
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance | $ / shares	$ 18.89
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	13.13
Forfeited, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	18.84
Vested, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	18.87
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance | $ / shares	$ 14.96

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Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Stock [Member] $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) $ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value | $	$ 14.7
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 13.13
Right to receive fully vested share of range common stock	0.375
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 13.08
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 15.58

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Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$ 10,521	$ 1,957	$ 13,673	$ 3,443

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Long-Term Incentive Plans - Additional Information (Detail) - USD ($) $ in Millions			6 Months Ended
	Jun. 01, 2016	Mar. 09, 2016	Jun. 30, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Unrecognized compensation cost			$ 23.2
Unrecognized compensation cost weighted-average period			2 years 5 months 9 days
Fair value of compensation cost reversed	$ 2.5	$ 0.5
Fair value of compensation cost recognized on the date plan modification	$ 9.8	$ 1.1

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Incentive Units - Additional Information (Detail) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2016 USD ($) shares	Jun. 30, 2016 USD ($) shares
Equity Incentive Plan [Line Items]
Remaining expected life		2 years 5 months 9 days
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 | $	$ (74.3)	$ (52.6)
Unrecognized compensation expense | $	$ 6.2	$ 6.2
Remaining expected life		3 months
MRD Holdco LLC [Member] | Subsequent Incentive Units [Member]
Equity Incentive Plan [Line Items]
Subsequent incentive units	70	70

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Incentive Units - Fair Value of Incentive Units Estimated (Detail)	6 Months Ended
	Jun. 30, 2016
Exchanged Incentive Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Dividend yield	0.00%
Expected volatility	55.00%
Risk-free rate	0.26%
Expected life (years)	3 months
Subsequent Incentive Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Dividend yield	0.00%
Expected volatility	55.00%
Risk-free rate	0.26%
Expected life (years)	3 months

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Related Party Transactions - Additional Information (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Related Party Transaction [Line Items]
General and administrative	$ 24,021,000	$ 10,323,000	$ 35,154,000	$ 23,299,000
Gas Processing Agreement [Member]
Related Party Transaction [Line Items]
Deficiency payments	3,200,000		6,500,000
Gas Processing Agreement [Member] | Other Long-term Assets [Member]
Related Party Transaction [Line Items]
Prepaid processing fees	6,500,000		6,500,000
Cretic Energy Services, LLC [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses	500,000		3,800,000
Multi-Shot, LLC [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses	1,100,000		3,500,000
Multi-Shot, LLC [Member] | Discontinued Operations [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses	100,000		$ 100,000
Natural Gas Partners [Member] | North Louisiana [Member]
Related Party Transaction [Line Items]
Mineral interests payments	$ 1,100,000
WHR Management Company [Member]
Related Party Transaction [Line Items]
General and administrative				2,000,000
Classic Operating And Classic Pipeline [Member] | Water Disposal Agreement [Member]
Related Party Transaction [Line Items]
Salt water disposal fees		$ 1,100,000		$ 2,000,000

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Commitments and Contingencies - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2016 USD ($) bbl / d $ / MMBTU $ / bbl	Dec. 31, 2015 USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Environmental reserves liability	$ 0
Agreement termination, date	Dec. 31, 2022
Extension term of gas agreement	1 year
Transportation and fractionation deductions | $ / bbl	4.39
Sales Delivery Commitment [Member] | April 1, 2016 to December 31, 2022 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum sales volume commitment | bbl / d	6,000
ETC Field Services LLC [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Payback demand fee received by the third party	110.00%
Natural gas assesses per MMBtu | $ / MMBTU	0.25
Regency Intrastate Gas LP [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Agreement termination, date	Dec. 31, 2025
Extension term of gas agreement	1 year
Annual inflation escalator	2.00%
Percentage of retained gas received for fuel	1.25%
Annual inflation escalator for overrun	2.00%
Continuing Operations [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Environmental reserves liability		$ 0

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Commitments and Contingencies - Summary of Reserved Capacity and Applicable Fees (Detail)	6 Months Ended
	Jun. 30, 2016 MMBTU / d $ / MMBTU
January 1, 2016 to December 31, 2022 [Member] | Reserved Capacity
Other Commitments [Line Items]
Reserved Capacity | MMBTU / d	300,000
January 1, 2016 to December 31, 2022 [Member] | Reservation Demand Charge
Other Commitments [Line Items]
Firm gas transportation service fees	0.075
January 1, 2016 to December 31, 2022 [Member] | Overrun Charge
Other Commitments [Line Items]
Firm gas transportation service fees	0.150
January 1, 2023 to December 31, 2025 [Member] | Reserved Capacity
Other Commitments [Line Items]
Reserved Capacity | MMBTU / d	200,000
January 1, 2023 to December 31, 2025 [Member] | Reservation Demand Charge
Other Commitments [Line Items]
Firm gas transportation service fees	0.075
January 1, 2023 to December 31, 2025 [Member] | Overrun Charge
Other Commitments [Line Items]
Firm gas transportation service fees	0.150

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Commitments and Contingencies - Summary of Pricing Grid Subject to Annual Escalation for Gas Received (Detail)	Jun. 30, 2016 $ / MMBTU
Total gas receipts ≤ contracted reserved capacity [Member] | Reservation Demand Charge
Other Commitments [Line Items]
Firm gas transportation service fees	0.075
Total gas receipts ≤ contracted reserved capacity [Member] | Commodity Charge
Other Commitments [Line Items]
Firm gas transportation service fees	0.075
Total gas receipts > contracted reserved capacity [Member] | Overrun Charge
Other Commitments [Line Items]
Firm gas transportation service fees	0.150

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Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Effective tax rate	11.50%	48.10%	10.50%	49.00%
Income tax expense (benefit)	$ (25,342,000)	$ (24,644,000)	$ (22,405,000)	$ 22,914,000
Unrecognized tax benefits	$ 0		$ 0
Reversed deferred tax liability					$ 28,000,000