Amplify Energy (AMPYW) 10-Q 2012 Q2 Quarterly report

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, 2012

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: 001-35364

MEMORIAL PRODUCTION PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	90-0726667
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1301 McKinney Street, Suite 2100, Houston, TX	77010
(Address of principal executive offices)	(Zip Code)

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

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

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

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

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

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

As of July 31, 2012, the registrant had 16,937,429 common units, 5,360,912 subordinated units and 22,222 general partner units outstanding.

MEMORIAL PRODUCTION PARTNERS LP

TABLE OF CONTENTS

		Page
	Glossary of Oil and Natural Gas Terms		1
	Names of Entities		6
	Cautionary Note Regarding Forward-Looking Statements		7
	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011		9
	Unaudited Condensed Statements of Consolidated and Predecessor Combined Operations for the Three and Six Months Ended June 30, 2012 and 2011		10
	Unaudited Condensed Statements of Consolidated and Predecessor Combined Cash Flows for the Three and Six Months Ended June 30, 2012 and 2011		11
	Unaudited Condensed Statements of Consolidated Equity for the Six Months Ended June 30, 2012		12
	Notes to Unaudited Condensed Consolidated and Predecessor Combined Financial Statements
	Note 1 – Organization and Basis of Presentation		13
	Note 2 – New Accounting Pronouncements		15
	Note 3 – Acquisitions and Divestitures		16
	Note 4 – Fair Value Measurements of Financial Instruments		18
	Note 5 – Risk Management and Derivative Instruments		19
	Note 6 – Asset Retirement Obligations		22
	Note 7 – Long Term Debt		22
	Note 8 – Equity & Distributions		23
	Note 9 – Earnings per Unit		23
	Note 10 – Equity-based Awards		24
	Note 11 – Related Party Transactions		25
	Note 12 – Commitments and Contingencies		26
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.		41
Item 4.	Controls and Procedures.		42
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings.		43
Item 1A.	Risk Factors.		43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.		43
Item 3.	Defaults Upon Senior Securities.		43
Item 4.	Mine Safety Disclosures.		43
Item 5.	Other Information.		43
Item 6.	Exhibits.		44
Signatures			45

i

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

API Gravity: A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

Basin: A large depression on the earth’s surface in which sediments accumulate.

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

Bbl/d: One Bbl per day.

Bcf: One billion cubic feet of natural gas.

Bcfe: One billion cubic feet of natural gas equivalent.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

Boe/d: One Boe per day.

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.

Deterministic Estimate: The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

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.

1

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.

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

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.

Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

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.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

MBtu/d: One thousand Btu per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

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

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

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.

2

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.

OPIS: Oil Price Information Service.

Play: A geographic area with hydrocarbon potential.

Probabilistic Estimate: The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserve Additions: The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions and revisions of previous estimates.

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.

3

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.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

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 based on annualized fourth quarter production and 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.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.

4

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 limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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.

Workover: Operations on a producing well to restore or increase production.

WTI: West Texas Intermediate.

5

NAMES OF ENTITIES

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

• “Memorial Production Partners,” “the Partnership,” “we,” “our,” “us” or like terms refer collectively to Memorial Production Partners LP and its subsidiaries;

• “our general partner” refers to Memorial Production Partners GP LLC, our general partner;

• “Memorial Resource” refers collectively to Memorial Resource Development LLC and its subsidiaries other than the Partnership;

• “our predecessor” refers collectively to (a) BlueStone Natural Resources Holdings, LLC and its wholly-owned subsidiaries, (b) certain oil and natural gas properties owned by Classic Hydrocarbons Holdings, L.P. (“Classic”), and (c) for periods after April 8, 2011, certain oil and natural gas properties owned by WHT Energy Partners LLC, a subsidiary of Memorial Resource that acquired those properties in April 2011, all of which are collectively our predecessor for accounting purposes and the owners, prior to the formation transactions;

• “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.;

• “formation transactions” refers to (i) the contribution by the Funds of their respective controlling ownership interests in certain of their subsidiaries (including our predecessor) to Memorial Resource prior to the closing of our initial public offering and (ii) the contribution by Memorial Resource to us of our properties (including the contribution to us of Columbus Energy, LLC (“Columbus”), a wholly-owned subsidiary of BlueStone Natural Resources Holdings, LLC, and ETX I LLC (“ETX”), a wholly-owned subsidiary of WHT Energy Partners LLC, each of which owned certain of our properties);

• “OLLC” refers to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; and

• “NGP” refers to Natural Gas Partners. The Funds, which are three of the private equity funds managed by NGP, collectively own 100% of Memorial Resource.

6

CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

• business strategies;

• ability to replace the reserves we produce through drilling and property acquisitions;

• drilling locations;

• oil and natural gas reserves;

• technology;

• realized oil and natural gas prices;

• production volumes;

• lease operating expenses;

• general and administrative expenses;

• future operating results;

• cash flows and liquidity;

• availability of drilling and production equipment;

• availability of oil field labor;

• capital expenditures;

• availability and terms of capital;

• marketing of oil and natural gas;

• expectations regarding general economic conditions;

• competition in the oil and natural gas industry;

• effectiveness of risk management activities;

• environmental liabilities;

• counterparty credit risk;

• expectations regarding governmental regulation and taxation;

• expectations regarding developments in oil-producing and natural-gas producing countries; and

• plans, objectives, expectations and intentions.

These types of statements, other than statements of historical fact included in this 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,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “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 state other “forward-looking” information. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations as expressed in this Form 10-Q including, but not limited to:

7

• our ability to generate sufficient cash to pay the minimum quarterly distribution or any other amount on our common units;

• our substantial future capital requirements, which may be subject to limited availability of financing;

• the uncertainty inherent in estimating our reserves;

• our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base;

• cash flows and liquidity;

• potential shortages of drilling and production equipment;

• potential difficulties in the marketing of, and volatility in the prices for, oil and natural gas;

• uncertainties surrounding the success of our secondary and tertiary recovery efforts;

• competition in the oil and natural gas industry;

• general political and economic conditions, globally and in the jurisdictions in which we operate;

• legislation and governmental regulations, including climate change legislation;

• the risk that our hedging strategy may be ineffective or may reduce our income;

• actions of third-party co-owners of interest in properties in which we also own an interest; and

• risks related to potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties.

The forward-looking statements contained in this 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 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 “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011 and “Part II—Item 1A. Risk Factors” appearing within this report and elsewhere in this report. All forward-looking statements speak only as of the date of this 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.

8

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding units)

	June 30,			December 31,
	2012			2011*
ASSETS
Current assets:
Cash and cash equivalents	$	3,372		$	1,088
Accounts receivable:
Oil and natural gas sales		9,087			—
Joint interest owners and other		1,473			—
Affiliates		2,195			2,955
Short-term derivative instruments		24,910			23,069
Prepaid expenses and other current assets		1,462			1,831
Total current assets		42,499			28,943
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		610,926			560,248
Other		289			—
Accumulated depreciation, depletion and impairment		(126,623	)		(111,611	)
Oil and natural gas properties, net		484,592			448,637
Long-term derivative instruments		21,609			13,654
Other long-term assets		1,772			2,012
Total assets	$	550,472		$	493,246
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	646		$	—
Accounts payable – affiliates		503			1,024
Revenues payable		2,068			—
Accrued liabilities		7,813			2,032
Short-term derivative instruments		828			346
Total current liabilities		11,858			3,402
Long-term debt		204,000			120,000
Asset retirement obligations		15,000			14,113
Long-term derivative instruments		1,847			1,040
Other long-term liabilities		825			670
Total liabilities		233,530			139,225
Commitments and contingencies (Note 12)
Equity:
Limited partners:
Common units (16,937,429 units outstanding at June 30, 2012 and 16,661,294 units outstanding at December 31, 2011)		250,610			241,034
Subordinated units (5,360,912 units outstanding at June 30, 2012 and December 31, 2011)		65,897			61,708
General partner (22,222 units outstanding at June 30, 2012 and 22,044 units outstanding at December 31, 2011)		435			426
Total partners’ equity		316,942			303,168
Predecessor capital		—			50,853
Total equity		316,942			354,021
Total liabilities and equity	$	550,472		$	493,246

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

*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.

9

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND PREDECESSOR COMBINED OPERATIONS

(In thousands, except per unit amounts)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011*			2012			2011*
				(Predecessor)						(Predecessor)
Revenues:
Oil & natural gas sales	$	16,639		$	23,027		$	35,399		$	37,209
Other income		31			149			141			252
Total revenues	$	16,670		$	23,176		$	35,540		$	37,461
Costs and expenses:
Lease operating		6,213			5,643			12,234			10,272
Exploration		414			56			414			56
Production and ad valorem taxes		1,708			2,069			3,568			3,477
Depreciation, depletion, and amortization		7,754			7,661			15,012			13,413
Impairment of proved oil and natural gas properties		—			2,893			—			2,893
General and administrative		2,117			2,513			4,474			4,250
Accretion of asset retirement obligations		274			265			562			485
Realized gain on commodity derivative instruments		(9,828	)		(1,026	)		(16,908	)		(2,413	)
Unrealized (gain) loss on commodity derivative instruments		4,851			(2,046	)		(10,677	)		367
Gain on sale of properties		(192	)		(62,721	)		(192	)		(62,729	)
Other, net		197			1,082			327			1,513
Total costs and expenses		13,508			(43,611	)		8,814			(28,416	)
Operating income		3,162			66,787			26,726			65,877
Interest expense		3,577			2,206			4,901			3,240
Income (loss) before income taxes		(415	)		64,581			21,825			62,637
Income tax expense		—			122			183			122
Net income (loss)		(415	)		64,459			21,642			62,515
Net income (loss) attributable to predecessor		(161	)		64,459			1,001			62,515
Net income (loss) attributable to partners	$	(254	)	$	—		$	20,641		$	—
Allocation of net income (loss) attributable to partners:
Limited partners	$	(254	)	$	—		$	20,620		$	—
General partner	$	—		$	—		$	21		$	—
Earnings per unit: (Note 9)
Basic and diluted earnings per unit	$	(0.01	)	$	—		$	0.93		$	—
Weighted average limited partner units outstanding:
Basic and diluted		22,236			—			22,210			—

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

*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.

10

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND PREDECESSOR COMBINED CASH FLOWS

(In thousands)

	For the Six Months Ended June 30,
	2012			2011*
				(Predecessor)
Cash flows from operating activities:
Net income	$	21,642		$	62,515
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		15,012			13,413
Impairment of proved oil and natural gas properties		—			2,893
Unrealized (gain) loss on derivatives		(8,280	)		666
Premiums paid for derivatives		—			(2,847	)
Premiums received for derivatives		—			1,008
Deferred income tax expense		183			122
Amortization of loan origination costs		257			214
Accretion of asset retirement obligations		562			485
Amortization of equity awards		575			—
Gain on sale of properties		(192	)		(62,729	)
Exploration costs		—			56
Changes in operating assets and liabilities:
Accounts receivable		(9,918	)		(6,644	)
Accounts receivable – affiliates		885			—
Prepaid expenses and other assets		144			370
Accounts payable		646			(1,636	)
Accounts payable – affiliates		(521	)		—
Revenue payable		2,068			842
Accrued liabilities		4,351			2,372
Other		—			559
Net cash provided by operating activities		27,414			11,659
Cash flows from investing activities:
Acquisition of oil and natural gas properties		(37,295	)		(137,929	)
Additions to oil and gas properties		(12,306	)		(25,097	)
Additions to other property and equipment		(289	)		(385	)
Proceeds from the sale of oil and gas properties		200			13
Net cash used in investing activities		(49,690	)		(163,398	)
Cash flows from financing activities:
Advances on revolving credit facility – Predecessor		—			91,946
Payments on revolving credit facility – Predecessor		—			(1,003	)
Loan origination fees – Predecessor		—			(901	)
Advances on revolving credit facility – Partnership		84,000
Loan origination fees – Partnership		(20	)		—
Distributions to partners		(12,716	)		—
Predecessor capital contributions		—			52,806
Distribution to Memorial Resource (Note 11)		(45,489	)		—
Contribution (distribution) attributable to net assets transferred (Note 1)		(1,215	)		5,614
Net cash provided by financing activities		24,560			148,462
Net change in cash and cash equivalents		2,284			(3,277	)
Cash and cash equivalents, beginning of period		1,088			5,654
Cash and cash equivalents, end of period	$	3,372		$	2,377
Supplemental cash flows:
Cash paid for interest	$	2,168		$	2,042
Noncash investing and financing activities:
Additions to oil and gas properties – capital accruals	$	1,318		$	—
Fair value of assets acquired in excess of cash paid and net book value of properties transferred		—			69,645
Assumptions of asset retirement obligations related to properties acquired		321			2,661

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

*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.

11

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(In thousands)

				Partners’ Equity
				Limited Partners
	Predecessor*			Common			Subordinated			General Partner			Total
Balance December 31, 2011	$	50,853		$	241,034		$	61,708		$	426		$	354,021
Net income		1,001			15,634			4,986			21			21,642
Distribution attributable to net assets transferred (Note 1)		(1,215	)		—			—			—			(1,215	)
Net book value of net assets transferred (Note 11)		(50,639	)		28,864			21,775			—			—
Amortization of equity awards		—			575			—			—			575
Distributions to partners		—			(9,632	)		(3,072	)		(12	)		(12,716	)
Distribution to Memorial Resource (Note 11)		—			(25,929	)		(19,560	)					(45,489	)
Other					64			60			—			124
Balance June 30, 2012	$	—		$	250,610		$	65,897		$	435		$	316,942

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

*See Note 1 for information regarding these recasted amounts and basis of financial statement presentation.

12

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

General

Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our business activities are conducted through our wholly owned subsidiary Memorial Production Operating LLC (“OLLC”), and its wholly-owned subsidiaries. Our properties are located in Texas and Louisiana and consist of mature, legacy onshore oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells (often referred to as wellbore assignments).

The Partnership was formed in April 2011 to own and acquire oil and natural gas properties in North America. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, Memorial Production Partners GP LLC, which is a wholly owned subsidiary of Memorial Resource Development LLC (“Memorial Resource”). Our general partner is responsible for managing all of the Partnership’s operations and activities.

Memorial Resource is a Delaware limited liability company owned and formed by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. Memorial Resource provides management, administrative, and operations personnel to us and our general partner under an omnibus agreement (see Note 11). The Funds are private equity funds managed by Natural Gas Partners (“NGP”). The Funds collectively directly own, through non-voting membership interests in our general partner, 50% of the economic interest in our incentive distribution rights (“IDRs”). The remaining economic interest in our IDRs is owned by our general partner.

On December 14, 2011, the Partnership completed its initial public offering (“IPO”) of 9,000,000 common units at a price of $19.00 per unit, which generated net proceeds to the Partnership of approximately $146.5 million after deducting underwriting discounts, structuring fees and other offering and formation-related fees. In connection with the closing of the IPO, the Partnership acquired for a combination of cash, common units, and subordinated units (1) substantially all of the oil and natural gas properties and related assets owned by BlueStone Natural Resources Holdings, LLC, a majority-controlled subsidiary of Memorial Resource, (2) certain oil and natural gas properties and related assets owned by Classic Hydrocarbons Holdings, L.P. (“Classic”), a majority-controlled subsidiary of Memorial Resource, and (3) a 40% undivided interest in certain oil and natural gas properties and related assets (the “WHT Assets”) controlled by WHT Energy Partners LLC (“WHT”), which is 50% owned by WildHorse Resources, LLC (“WildHorse”) and 50% owned by Tanos Energy, LLC (“Tanos”), both of which are majority-controlled subsidiaries of Memorial Resource.

We distributed approximately $73.6 million in cash, 7,061,294 common units, and 5,360,912 subordinated units to Memorial Resource to acquire the net assets of our predecessor and repaid $198.3 million of our predecessor’s credit facilities concurrent with the closing of our IPO. The cash portion of this consideration was financed with approximately $130.0 million in borrowings under a new senior secured revolving credit facility (see Note 7) and the net cash proceeds generated from our IPO. This dropdown transaction was accounted for as a combination of entities under common control; therefore, the Partnership accounted for the acquisition at historical cost in a manner similar to the pooling of interest method. Due to the timing of our IPO and the fact that we did not acquire working capital from our predecessor, our consolidated balance sheet as of December 31, 2011 did not include any trade receivables or payables.

On December 22, 2011, the underwriters exercised a portion of their over-allotment option, purchasing an additional 600,000 common units issued by the Partnership, which generated net proceeds to the Partnership of approximately $10.7 million. Of this amount, $10.0 million was used to repay indebtedness under our revolving credit facility.

13

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Predecessor

The Partnership did not own any assets prior to December 14, 2011. The business and operations of the Partnership prior to December 14, 2011 are referred to as “our predecessor.” The following entities are included in the historical combined financial statements of our predecessor: (i) BlueStone Natural Resources Holdings, LLC (“Bluestone”) and its wholly-owned subsidiaries, (ii) certain carved-out oil and natural gas properties (“Classic Carve-Out”) owned by Classic, and (iii) for periods after April 8, 2011, certain oil and natural gas properties owned by WHT, which are collectively our predecessor for accounting and financial reporting purposes, prior to the closing of our IPO. Our predecessor was determined in accordance with the rules and regulations of the SEC.

BlueStone was formed in January 2006 to engage in the acquisition, development, production and exploration and sale of oil and natural gas. BlueStone’s assets include oil and natural gas producing properties located in Texas. Prior to our IPO, Memorial Resource owned an 89.45% interest in BlueStone and certain members of BlueStone’s management owned a 10.55% interest.

Classic was formed in 2006 to engage in the exploration, development, production, and sale of oil and natural gas primarily in East Texas. Prior to our IPO, Memorial Resource owned a 90.21% limited partner interest in Classic and an 83.33% membership interest in the general partner of Classic. The Classic Carve-Out financial statements include the applicable amounts of Craton Energy Holdings III, LP (“Craton”), which was contributed to Classic by one of the Funds in 2009. This contribution was accounted for as a combination of entities under common control; therefore, Classic accounted for the acquisition in a manner similar to the pooling of interest method. Information included in these financial statements is presented as if Craton had been combined throughout the periods presented in which common control existed.

The WHT Assets were acquired on April 8, 2011 from a third party; therefore, the results of operations (proportionally consolidated) were included in our predecessor’s financial statements from that date forward. Prior to April 8, 2011, WHT did not have any oil and natural gas assets.

Our predecessor operated oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our predecessor’s management evaluated performance based on one business segment as there were not different economic environments within the operation of the oil and natural gas properties.

Basis of Presentation

Our predecessor combined financial statements were derived from the historical accounting records of our predecessor and reflect the historical financial position, results of operations and cash flows for periods prior to our IPO. As common control existed among our predecessor entities, our predecessor’s combined financial statements reflect the financial statements of BlueStone and Classic Carve-Out on a combined basis for the for the three and six months ended June 30, 2011 and the WHT Assets from the acquisition date of April 8, 2011 forward.

The Classic Carve-Out amounts included in the accompanying financial statements were determined in accordance with SEC regulations and guidance. Certain expenses incurred by Classic are only indirectly attributable to its ownership of Classic Carve-Out as Classic owns interests in numerous other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to our predecessor, so that the amounts included in the predecessor combined financial statements reflect substantially all of the cost of doing business. Such allocations may or may not reflect future costs associated with the operation of the Partnership.

14

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Our acquisitions of oil and gas properties from Memorial Resource in April and May 2012, as further discussed in Note 11, were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource’s carrying value and our consolidated and predecessor financial statements previously filed with the SEC and reported herein were recast to include the financial position and results attributable to these oil and gas properties for all periods presented on a combined basis. The historical financial position and results attributable to these oil and gas properties were prepared from Memorial Resource’s cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. Distributions attributable to net assets transferred, as presented on our cash flow statement under financing activities, is equal to net cash provided by operating activities less cash used in investing activities attributable to these oil and gas properties. Conversely, contributions attributable to net assets transferred, as presented on our cash flow statement under financing activities, is equal to cash used in investing activities less net cash provided by operating activities attributable to these oil and gas properties.

Our results of operations for the three and six months ended June 30, 2012 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and predecessor combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the SEC. These unaudited condensed consolidated and predecessor combined financial statements and the notes thereto should be read in conjunction with the audited consolidated and predecessor combined financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”).

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and predecessor combined financial statements. Certain amounts in the prior year financial statements have been reclassified to conform with the presentation in the current year financial statements.

Use of Estimates

The preparation of the accompanying unaudited condensed consolidated and predecessor combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the combined financial statements the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Note 2. New Accounting Pronouncements

In May 2011, the FASB issued an accounting standard update that amended previous fair value measurement and disclosure guidance. These amendments generally involve clarifications on how to measure and disclose fair value amounts recognized in the financial statements. They also expand the disclosure requirements, particularly for Level 3 fair value measurements, to include a description of the valuation processes used and an analysis of the sensitivity of the fair value measurements to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any. The Partnership adopted this amendment on January 1, 2012. The amendment did not have a material impact on our financial position, results of operations, cash flows or notes to the financial statements.

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 Partnership’s financial position, results of operations and cash flows.

15

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 3. Acquisitions and Divestitures

The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we and our predecessor conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through capital contributions and borrowings under credit facilities.

The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

2012 Acquisitions

Related Party. Our acquisitions of oil and gas properties from Memorial Resource in April and May 2012, as further discussed in Note 11, were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource’s carrying value.

Third Party.On May 1, 2012, we acquired non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller for approximately $37.3 million, subject to customary post-closing adjustments. The effective date of this transaction was January 1, 2012. This transaction was financed with borrowings under our revolving credit facility. Because this transaction was a joint acquisition with Memorial Resource, the transaction was approved by the board of directors of our general partner (the “Board”) and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. The following table summarizes the fair value of the assets acquired and liabilities assumed as of the acquisition date (dollars in thousands):

Recognized amounts of identifiable assets acquired and liabilities assumed:
Oil and gas properties	$	37,059
Accounts receivable		641
Asset retirement obligations		(321	)
Accrued liabilities		(84	)
Total identifiable net assets	$	37,295

Approximately $1.0 million of revenue and $0.2 million of earnings were recorded in the statement of operations related to this acquisition subsequent to the closing date.

The following unaudited pro forma combined results of operations are provided for the three and six month periods ended June 30, 2012 and 2011 as though the acquisition had been completed on January 1, 2011. The pro forma combined results of operations for the three and six month periods ended June 30, 2012 and 2011 have been prepared by adjusting the historical results of operations to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012			2011		2012		2011
	(In thousands, except per unit amounts)
Revenues	$	17,244		$	25,696	$	37,832	$	42,290
Net income (loss)		(207	)		65,508		22,306		64,416
Basic and diluted earnings per unit		—			—		0.96		—

Acquisition-related costs.Approximately $0.3 million and $0.4 million of acquisition-related costs are included in general and administrative expense in the accompanying statements of operations for the three and six months ended June 30, 2012, respectively.

16

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

2011 Acquisitions

On May 31, 2011, our predecessor acquired BP America Production Company’s (“BP”) interests in wells located in Duval, Jim Hogg, McMullen and Webb counties located in South Texas in exchange for our predecessor’s interest in approximately 10,700 net acres located in the Nueces Field of the Eagle Ford Shale located in South Texas with a net book value of $5.2 million and $20.0 million in cash, subject to certain closing adjustments. The effective date of this transaction was January 1, 2011. Our predecessor paid a total of approximately $12.9 million in cash consideration at closing, net of adjustments.

A preliminary purchase price allocation was recorded in the second quarter of 2011. In the fourth quarter of 2011, the purchase price allocation was finalized with minor adjustments. The final purchase price allocation resulted in the acquisition date fair value of $82.6 million allocated to proved oil and gas properties, $1.2 million allocated to asset retirement obligations, $0.5 million allocated to accrued liabilities and $0.6 million to deferred tax liabilities.

Our predecessor recorded a $62.7 million gain during the three and six months ended June 30, 2011, based upon the preliminary purchase price allocation, the net book value of the Nueces Field properties exchanged to BP, and the cash consideration paid at closing.

On April 8, 2011, our predecessor acquired producing oil and natural gas properties in East Texas (the “Carthage Properties”) from a third party. The acquisition-date fair value of the total consideration transferred was $122.9 million, of which $120.8 million was cash consideration. A preliminary purchase price allocation was recorded in the second quarter of 2011. In the third quarter of 2011, the purchase price allocation was finalized with minor adjustments. The following table summarizes the fair value of the assets acquired and liabilities assumed as of April 8, 2011 (dollars in thousands):

Recognized amounts of identifiable assets acquired and liabilities assumed:
Oil and gas properties	$	122,874
Other property and equipment		418
Suspense liabilities assumed		(664	)
Environmental liabilities assumed		(387	)
Asset retirement obligations		(1,461	)
Total identifiable net assets	$	120,780

Summarized below are the results of operations for the three and six months ended June 30, 2011, on an unaudited pro forma basis, as if the BP and Carthage Properties acquisitions had occurred on January 1, 2010. The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor, the statements of revenues and direct operating expenses for the BP and Carthage Properties and the historical accounting records of the sellers. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Three Months Ended June 30, 2011		For the Six Months Ended June 30, 2011
	(In thousands)		(In thousands)
BP and Carthage Properties:
Revenues	$	26,494	$	50,219
Net income		2,938		4,425

During the three and six months ended June 30, 2011, approximately $1.3 million and $5.9 million of revenue and $0.6 million and $2.3 million of earnings were recorded in the statement of operations, respectively, related to the BP and Carthage Properties acquisitions subsequent to their respective closing dates.

Our predecessor also acquired interests in oil and gas properties, including acreage, in a number of individually insignificant acquisitions during the six months ended June 30, 2011 which aggregated to a total of approximately $4.0 million.

17

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Approximately $0.8 million of acquisition costs related to the 2011 acquisitions is included in other expense in the accompanying statements of operations for both the three and six months ended June 30, 2011.

Note 4. Fair Value Measurements of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange-traded derivatives, such as over-the-counter commodity price swaps, collars, put options and interest rate swaps. At June 30, 2012 and December 31, 2011, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

Level 3 —Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements included in the accompanying balance sheets approximated fair value at June 30, 2012 and December 31, 2011. 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.

The fair market values of the derivative financial instruments reflected in the balance sheets as of June 30, 2012 and December 31, 2011 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2012 and December 31, 2011 for each of the fair value hierarchy levels:

	Fair Value Measurements at June 30, 2012 Using
	Quoted Prices in Active Market (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	52,887	$	—	$	52,887
Liabilities :
Commodity derivatives	$	—	$	6,368	$	—	$	6,368
Interest rate derivatives		—		2,675		—		2,675
Total liabilities	$	—	$	9,043	$	—	$	9,043

18

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

	Fair Value Measurements at December 31, 2011 Using
	Quoted Prices in Active Market (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	39,206	$	—	$	39,206
Liabilities :
Commodity derivatives	$	—	$	3,591	$	—	$	3,591
Interest rate derivatives		—		278		—		278
Total liabilities	$	—	$	3,869	$	—	$	3,869

See Note 5 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:

• The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 6 for a summary of changes in ARO’s.

• 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 proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Note 5. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender in our credit agreement. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had our counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset our $43.8 million net derivative asset receivable against amounts outstanding under our revolving credit facility. See Note 7 for additional information in regards to our revolving credit facility.

19

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Commodity Derivatives

A combination of commodity derivatives (e.g., floating-for-fixed swaps, collars, put options, call spreads, and basis swaps) is used to manage exposure to commodity price volatility. We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub and regional indices such as NGPL TXOK, TETCO STX, and Houston Ship Channel in proximity to the Partnership’s areas of production. We also enter into oil derivative contracts indexed to NYMEX WTI and NGL derivative contracts indexed to OPIS Mont Belvieu. At June 30, 2012 we had the following open commodity positions:

	Remaining 2012			2013			2014		2015		2016		January 2017 Through June 2017
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		601,701			680,172			1,103,375		1,027,778		1,023,275		960,133
Weighted-average fixed price	$	4.54		$	4.36		$	4.36	$	4.28	$	4.56	$	4.25
Collar contracts:
Average Monthly Volume (MMBtu)		660,000			633,000			120,000		80,000		—		—
Weighted-average floor price	$	4.75		$	4.75		$	5.08	$	5.25	$	—	$	—
Weighted-average ceiling price	$	5.85		$	5.82		$	6.31	$	6.75	$	—	$	—
Put options:
Average Monthly Volume (MMBtu)		70,000			—			—		—		—		—
Weighted-average strike price	$	4.80		$	—		$	—	$	—	$	—	$	—
Call spreads(1):
Average Monthly Volume (MMBtu)		80,000			430,000			120,000		80,000		—		—
Weighted-average sold strike price	$	4.20		$	4.59		$	5.08	$	5.25	$	—	$	—
Weighted-average bought strike price	$	5.70		$	5.84		$	6.31	$	6.75	$	—	$	—
Basis swaps:
Average Monthly Volume (MMBtu)		356,633			405,932			—		—		—		—
Spread	$	(0.14	)	$	(0.16	)	$	—	$	—	$	—	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		4,747			4,632			5,352		8,031		7,513		—
Weighted-average fixed price	$	98.63		$	99.53		$	89.99	$	90.93	$	91.03	$	—
Collar contracts:
Average Monthly Volume (Bbls)		4,500			4,750			3,200		—		—		—
Weighted-average floor price	$	86.67		$	87.16		$	90.00	$	—	$	—	$	—
Weighted-average ceiling price	$	115.12		$	116.94		$	117.72	$	—	$	—	$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		10,929			14,505			—		—		—		—
Weighted-average fixed price	$	44.93		$	52.94		$	—	$	—	$	—	$	—
Collar contracts:
Average Monthly Volume (Bbls)		3,800			—			—		—		—		—
Weighted-average floor price	$	75.16		$	—		$	—	$	—	$	—	$	—
Weighted-average ceiling price	$	93.57		$	—		$	—	$	—	$	—	$	—

(1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the collars into swaps.

20

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Interest Rate Swaps

Partnership. Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. At June 30, 2012, we had the following fixed-for floating interest rate swap open positions whereby we receive the floating rate and pay the fixed rate:

Period Covered			Notional ($ in thousands)		Floating Rate	Fixed Rate
	1/17/2012	1/17/2013	$	100,000	1 Month LIBOR	0.600%
	1/17/2013	12/14/2016	$	100,000	1 Month LIBOR	1.305%
	5/17/2012	1/17/2013	$	50,000	1 Month LIBOR	0.600%
	1/17/2013	12/14/2016	$	50,000	1 Month LIBOR	0.970%

Predecessor.In April 2011, our predecessor entered into three interest rate swap agreements in order to mitigate its exposure to interest rate fluctuations. Under these swap agreements, our predecessor received the current 1-month LIBOR and paid a fixed rate of 1.510% on a notional amount of $10 million for each swap, or $30 million in total for the three swaps. The effective dates of the swaps were from April 2011 to April 2014 and were not acquired by the Partnership at its IPO in December 2011. In June 2010, our predecessor entered into an interest rate swap agreement in order to mitigate its exposure to interest rate fluctuations. Under this swap agreement, our predecessor received the current 1-month LIBOR and paid a fixed rate of 1.00% on a notional amount of $50.0 million. The effective date of the swap was from June 2010 to June 2012 and was not acquired by the Partnership at its IPO in December 2011. In 2009, our predecessor entered into two interest rate swap agreements in order to mitigate its exposure to interest rate fluctuations. Under these swap agreements, our predecessor paid 1.62% and received the current 3-month LIBOR rate per month on a notional amount of $6.7 million and $1.7 million, respectively. The effective dates of the swaps were from February 2009 to February 2011.

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, 2012 and December 31, 2011:

		Asset Derivatives						Liability Derivatives
		June 30,			December 31,			June 30,			December 31,
Type	Balance Sheet Location	2012			2011			2012			2011
		(In thousands)
Natural gas contracts	Short-term derivative instruments	$	23,060		$	22,930		$	667		$	44
Oil contracts	Short-term derivative instruments		1,198			83			83			250
NGL contracts	Short-term derivative instruments		1,464			166			62			—
Interest rate swaps	Short-term derivative instruments		—			—			828			162
Gross fair value			25,722			23,179			1,640			456
Netting arrangements	Short-term derivative instruments		(812	)		(110	)		(812	)		(110	)
Net recorded fair value	Short-term derivative instruments	$	24,910		$	23,069		$	828		$	346
Natural gas contracts	Long-term derivative instruments	$	24,543		$	15,595		$	5,256		$	3,034
Oil contracts	Long-term derivative instruments		2,033			432			244			263
NGL contracts	Long-term derivative instruments		589			—			56			—
Interest rate swaps	Long-term derivative instruments		—			—			1,847			116
Gross fair value			27,165			16,027			7,403			3,413
Netting arrangements	Long-term derivative instruments		(5,556	)		(2,373	)		(5,556	)		(2,373	)
Net recorded fair value	Long-term derivative instruments	$	21,609		$	13,654		$	1,847		$	1,040

21

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for financial reporting purposes and neither did our predecessor. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the unrealized and realized gains and losses related to derivative instruments for the three and six months ended June 30, 2012 and 2011 (in thousands):

		For the Three Months Ended June 30,						For the Six Months Ended June 30,
	Statements of Operations Location	2012			2011			2012			2011
Commodity derivative contracts	Realized (gain) loss on commodity derivatives	$	(9,828	)	$	(1,026	)	$	(16,908	)	$	(2,413	)
Commodity derivative contracts	Unrealized (gain) loss on commodity derivatives		4,851			(2,046	)		(10,677	)		367
Interest rate swaps (1)	Interest expense		2,242			583			2,562			636

(1) Included in the amounts are net cash payments of approximately $0.1 million and $0.2 million for both the three and six months ended June 30, 2012 and 2011, respectively.

Note 6. Asset Retirement Obligations

We recognize the fair value of asset retirement obligations related to the plugging, abandonment, and remediation activities of oil and gas producing properties in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the related long-lived assets. The following table represents information regarding our asset retirement obligations for the period indicated (in thousands):

	For the Six  Months Ended June 30,
	2012
Asset retirement obligations at beginning of period	$	14,113
Liabilities added from acquisitions or drilling		325
Accretion expense		562
Asset retirement obligations at end of period	$	15,000

Note 7. Long Term Debt

Our consolidated debt obligations consisted of the following at the dates indicated:

	June 30,		December 31,
	2012		2011
	(In thousands)
$1.0 billion multi-year revolving credit facility, variable-rate, due December 2016	$	204,000	$	120,000

This revolving credit facility, which OLLC entered into at the closing of our IPO, is guaranteed by us and all of our current and future subsidiaries with an initial borrowing base of $300.0 million. In connection with the April 2012 scheduled borrowing base redetermination, the borrowing base remained at $300.0 million. The next borrowing base redetermination is scheduled for October 2012. As of June 30, 2012, available borrowing capacity under this revolving credit facility is $96.0 million. The effective weighted average interest rate for the three and six months ended June 30, 2012 was 2.71% and 2.78%, respectively. The effective weighted average interest rate includes the impact of the commitment fee and excludes the impact of interest rate hedging activity. We were in compliance with the financial covenants of our consolidated debt agreements at June 30, 2012.

In April and May 2012, we borrowed $84.0 million to fund the acquisitions of oil and gas properties and for other general partnership purposes.

22

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 8. Equity & Distributions

Equity Outstanding

The following table summarizes changes in the number of outstanding units since December 31, 2011:

	Common		Subordinated		General Partner
Balance December 31, 2011		16,661,294		5,360,912		22,044
Restricted common units issued		276,135		—		—
General partner units issued		—		—		178
Balance June 30, 2012		16,937,429		5,360,912		22,222

Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 10 for additional information regarding restricted common units that were granted during the six months ended June 30, 2012.

Cash Distributions to Unitholders

On January 26, 2012, the Board declared a quarterly cash distribution for the fourth quarter of 2011 of $0.0929 per unit. The distribution represented a proration of our minimum quarterly distribution of $0.4750 per unit for the period from December 14, 2011 through December 31, 2011. The aggregate distribution of $2.0 million, of which Memorial Resource received $1.2 million, was paid on February 13, 2012 to unitholders of record as of the close of business on February 6, 2012, except for the holders of 177,370 restricted common units that were granted to our general partner’s executive officers and independent director on January 9, 2012 (see Note 10).

On April 19, 2012, the Board declared a quarterly cash distribution for the first quarter of 2012 of $0.48 per unit. The aggregate distribution of $10.7 million, of which Memorial Resource received $6.0 million, was paid on May 14, 2012 to unitholders of record as of the close of business on May 1, 2012.

On July 19, 2012, the Board declared a quarterly cash distribution for the second quarter of 2012 of $0.48 per unit. The aggregate distribution of $10.7 million, of which Memorial Resource received $6.0 million, was paid on August 13, 2012 to unitholders of record as of the close of business on August 1, 2012.

Note 9. Earnings per Unit

The following sets forth the calculation of earnings per unit, or EPU, for the periods indicated (in thousands, except per unit amounts):

	For the Three Months Ended June 30,			For the Six Months Ended June 30,
	2012			2012
Net income (loss) attributable to partners	$	(254	)	$	20,641
Less: General partner’s 0.1% interest in net income (loss)		—			21
Limited partners’ interest in net income (loss)	$	(254	)	$	20,620
Weighted average limited partner units outstanding:
Common units		16,875			16,849
Subordinated units		5,361			5,361
Total		22,236			22,210
Basic and diluted EPU	$	(0.01	)	$	0.93

23

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 10. Equity-based Awards

Long-Term Incentive Plan

In December 2011, the Board adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for employees, officers, consultants and directors of the general partner and any of its affiliates, including Memorial Resource, who perform services for the Partnership. The LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP will be administered by the Board or a committee thereof.

In January 2012, an aggregate of 177,370 restricted common units were granted under the LTIP to our general partner’s executive officers and an independent director of our general partner. In March 2012, the Board granted an award of 3,511 restricted common units under the LTIP to a newly appointed independent director, Mr. P. Michael Highum. In May 2012, an additional 57,321 restricted common units were collectively granted under the LTIP to our general partner’s executive officers. In May 2012, an aggregate of 37,933 restricted common units were granted under the LTIP to other Memorial Resource employees who perform services on behalf of the Partnership. The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions in which one-third of each award vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in the partnership with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by the Partnership to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

The aggregate fair value of the restricted common units awarded to our general partner’s executive officers and other Memorial Resource employees was $4.9 million based on the market price per unit on the date of grant. This amount will be recognized as compensation cost on a straight-line basis over the requisite service period. These awards were granted in recognition of services performed in connection with the completion of our IPO and/or to provide incentive to help drive the Partnership’s future success and to share in the economic benefits of that success. The compensation costs associated with these awards are recorded as direct general and administrative expenses. During the three and six months ended June 30, 2012, we recognized approximately $0.3 million and $0.6 million, respectively, of compensation expense associated with these awards.

The fair value of the restricted unit awards granted to the independent directors of our general partner is remeasured as of the end of each reporting period and will be recognized as compensation cost on a straight-line basis over the requisite service period. The compensation costs associated with these awards are recorded as direct general and administrative expenses. During the three and six months ended June 30, 2012, we recognized less than $0.1 million of compensation expense associated with these awards.

The following table summarizes information regarding restricted common unit awards for the periods presented:

	Number of Units		Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2011		—	$	—
Granted (2)		276,135	$	18.08
Restricted common units outstanding at June 30, 2012		276,135	$	18.08

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

(2) The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.0 million based on grant date market prices of $18.58, $18.52 and $17.14 per unit.

24

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

The unrecognized compensation cost associated with restricted common unit awards was an aggregate $4.4 million at June 30, 2012. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.71 years.

Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to partners as presented on our unaudited condensed statements of consolidated and predecessor combined cash flows. During the six months ended June 30, 2012, the restricted common unitholders received a distribution of approximately $0.1 million. The restricted common unitholders received a distribution of approximately $0.1 million on August 13, 2012 with respect to the quarterly cash distribution for the second quarter of 2012 that the Board declared in July 2012.

Note 11. Related Party Transactions

The following table summarizes our related party receivable and payable amounts included in the accompanying balance sheets at June 30, 2012 and December 31, 2011 (in thousands):

	June 30,			December 31,
	2012			2011
Accounts Receivable/(Payable) – Affiliates:
Memorial Resource	$	(503	)	$	377
Our general partner		17			—
BlueStone		226			2,142
Classic		1,918			436
WHT		34			(1,024	)
Total	$	1,692		$	1,931

For the three and six months ended June 30, 2012, approximately $0.6 million and $1.1 million, respectively, of related party transactions are reflected in the accompanying statements of operations. For the comparable periods in 2011, there was approximately $0.2 million and $0.3 million, respectively, of related party transactions recognized in the accompanying statements of operations.

Agreements

Memorial Resource continues to provide management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. Memorial Resource has entered into agreements with affiliates on our behalf relating to the management, operation and administration of the properties acquired by us on December 14, 2011. Effective May 1, 2012, we record less than $0.1 million monthly for the management fees that Memorial Resource pays to its affiliates and recorded approximately $0.1 million prior to this date. The tax sharing agreement pursuant to which we pay Memorial Resource (or its applicable affiliate(s)) our share of state and local income and other taxes for which our results are included in a combined or consolidated tax return filed by Memorial Resource or its applicable affiliate(s) also remains in effect.

Acquisition of Oil & Gas Producing Properties

On April 2, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $18.5 million, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2013 commodity derivative positions. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

Oil and natural gas properties, net	$	15,164
Short-term derivative instruments, net		715
Long-term derivative instruments, net		674
Asset retirement obligations		(466	)
Accrued liabilities		(17	)
Net assets	$	16,070

25

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

On May 14, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $27.0 million, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2014 commodity derivative positions. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Cotton Valley and Travis Peak fields in Panola and Shelby counties in East Texas. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

Oil and natural gas properties, net	$	31,716
Accounts receivable		612
Short-term derivative instruments, net		1,017
Long-term derivative instruments, net		1,337
Asset retirement obligations		(43	)
Accrued liabilities		(70	)
Net assets	$	34,569

Memorial Resource Revolving Credit Facility

On July 13, 2012, Memorial Resource entered into a new senior secured revolving credit facility which is guaranteed by our general partner. The revolving credit facility is a two-year, $50.0 million credit facility with an initial borrowing base of $35.0 million. Memorial Resource has pledged 7,061,294 of our common units and 5,360,912 of our subordinated common units as security under the credit facility in addition to certain other assets of Memorial Resource.

Note 12. Commitments and Contingencies

Litigation & Environmental

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.

At June 30, 2012 and December 31, 2011, we had $0.9 million and $1.1 million respectively, of environmental reserves recorded on our balance sheets. At June 30, 2012 and December 31, 2011, $0.5 million and $0.8 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.

26

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

AND RESULTS OF OPERATIONS.

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the unaudited condensed financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our annual report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”). 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 a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” We were formed in April 2011 by Memorial Resource to own and acquire oil and natural gas properties in North America and completed our initial public offering (“IPO”) on December 14, 2011. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which Memorial Resource performs services for us and our general partner, including the operation of our properties.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries, Columbus and ETX. Our assets consist of oil and natural gas producing properties that are primarily located in South and East Texas/North Louisiana.

We believe our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), will provide us with access to a portfolio of additional oil and natural gas properties that meet our acquisition criteria. The following table summarizes information about Memorial Resource’s proved oil and natural gas reserves by geographic region as of June 30, 2012 and average net production for the six months ended June 30, 2012:

	Estimated Net Proved Reserves (1)								Average Net Production					Average Reserve-to- Production Ratio (2)
	Bcfe		% Natural Gas			% Proved Developed			MMcfe/d		% of Total
														(Years)
East Texas / North Louisiana		1,183.5		71	%		37	%		104.8		94	%		30.9
Rockies / Midcontinent		51.0		24	%		41	%		6.9		6	%		20.3
Aggregate		1,234.5		69	%		37	%		111.7		100	%		30.3

(1) The estimates of net proved reserves were prepared by Memorial Resource’s internal reserve engineers and are based on various assumptions, including assumptions related to oil and natural gas prices as of June 30, 2012, drilling and operating expenses, capital expenditures, taxes and availability of funds. These internal estimates of net proved reserves may differ materially from estimates of net proved reserves as of December 31, 2012, prepared by independent reserve engineers, as estimates are prepared using SEC pricing (historical twelve month average).

(2) The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of June 30, 2012 by average net production for the six months ended June 30, 2012.

Based on Memorial Resource’s intention to develop its properties and significant ownership interests in us, we believe we may be able to acquire additional assets from Memorial Resource, the Funds, or their respective affiliates in the future. None of Memorial Resource, the Funds, or any of their respective affiliates will have any obligation to offer or sell properties to us. See “— Significant Current Developments” below for additional information regarding the Partnership’s acquisitions of oil and gas properties from Memorial Resource in April and May 2012.

27

Significant Current Developments

Acquisition of Oil & Gas Properties – Common Control

On April 2, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $18.5 million, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2013 commodity derivative positions. The transaction was approved by the board of directors of our general partner (the “Board”) and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas. Memorial Resource will continue to operate 84% of the acquired properties and the remaining 16% will continue to be operated by third parties. Based on average net daily production of 2.3 MMcfe at the time of acquisition, approximately 82% is natural gas and the remaining 18% is oil and NGLs.

On May 14, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $27.0 million, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2014 commodity derivative positions. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Cotton Valley and Travis Peak fields in Panola and Shelby counties in East Texas. Based on average net daily production of 4.2 MMcfe at the time of acquisition, approximately 81% is natural gas and the remaining 19% is oil and NGLs.

Our acquisitions of oil and gas properties from Memorial Resource in April and May 2012 were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource’s carrying value and our consolidated and predecessor financial statements previously filed with the SEC and presented herein were recast to include the financial position and results attributable to these oil and gas properties for all periods presented on a combined basis. The historical financial position and results attributable to these oil and gas properties were prepared from Memorial Resource’s cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. See Note 1 of the unaudited condensed financial statements included in “Item 1. Financial Statements” for more information about the Partnership’s basis of presentation.

Acquisition of Oil & Gas Properties – Third Party

On May 1, 2012, we acquired non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller for approximately $37.3 million, subject to customary post-closing adjustments. The effective date of this transaction was January 1, 2012. This transaction was financed with borrowings under our revolving credit facility. Because this transaction was a joint acquisition with Memorial Resource, the transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. Memorial Resource will operate 75% of the acquired properties and the remaining 25% will be operated by third parties. Based on average net daily production of 3.5 MMcfe at the time of acquisition, approximately 61% is natural gas and the remaining 39% is oil and NGLs. This acquisition was accounted for as a business combination using the acquisition method of accounting. See Note 3 of the unaudited condensed financial statements included in “Item 1. Financial Statements” for more information about this acquisition.

Third Independent Director Appointed to the Board

NASDAQ listing standards required the Board to have at least three independent directors within one year of the date our common units were listed on NASDAQ. Effective August 3, 2012, Robert A. Innamorati was appointed as an independent director to the Board. Mr. Innamorati has served as President of Robert A. Innamorati & Co. Inc., a private investment and advisory firm, since 1995. He previously served as President of a privately-owned diversified investment company with assets in excess of $1.5 billion from 2007 until 2012. Mr. Innamorati also held positions with Banc One Capital Corporation, Drexel Burnham Lambert & Co. Inc. and Blyth Eastman Dillon & Co., Inc. He previously served for six years as a special agent with the United States Secret Service in Washington, D.C. and two years in the United States Marine Corps Reserves. Mr. Innamorati currently serves as a board member of The Texas Rangers Baseball Club where he serves as chairman of the compensation committee and is a member of the finance committee. Mr. Innamorati has also served as a board member for several private companies. Mr. Innamorati received a B.S. in

28

Finance from the McIntire School of Commerce and an MBA from the Darden Graduate School of Business Administration, both at the University of Virginia. He also graduated from the U.S. Treasury Department Law Enforcement Officer’s and U.S. Secret Service Schools. Upon his appointment to the Board, Mr. Innamorati was granted an award of 1,535 restricted common units under the Memorial Production Partners GP LLC Long-Term Incentive Plan, of which one-third will vest on the first, second, and third anniversaries of the date of grant.

Business Environment and Operational Focus

Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production, including the effect of our derivative contracts; (iii) lease operating expenses; (iv) general and administrative expenses; and (v) Adjusted EBITDA (defined below).

Production Volumes

Production volumes directly impact our results of operations. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. We attempt to overcome this natural decline through a combination of acquisitions and development projects and improving the economics of producing oil and natural gas from our properties. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

Realized Prices on the Sale of our Production

We market our natural gas, NGL and oil production to a variety of purchasers based on regional pricing. The relative prices of natural gas, NGL and oil are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets. We expect commodity prices to be volatile in the future. During 2012, natural gas futures traded on the NYMEX fell below $2.00 per MMBtu for the first time in over a decade as a result of supply and demand fundamentals. The decline in gas prices is primarily a result of growing gas production associated with discoveries of significant gas reserves in United States shale plays, combined with the warmer than normal winter of 2011-2012, which has resulted in gas storage levels being at historically high levels. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for any oil, natural gas or NGLs that we produce will generally approximate market prices in the geographic region of the production.

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into commodity derivative contracts covering approximately 65% to 85% of our targeted average net production over a three-to-five year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price swap hedges exceeding a certain percentage of production. By removing a significant portion of this price volatility on our future production through September 2017, we have mitigated, but not eliminated, the potential effects of changing commodity prices on our cash flows from operations for those periods.

Lease Operating Expenses

We strive to increase our production levels to maximize our revenue and cash available for distribution. Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. We monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we monitor our production expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold.

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General & Administrative Expenses

We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource currently intends to allocate its expected general and administrative costs proportionately based on the relative size of our proved and probable reserves in comparison to Memorial Resource’s proved and probable reserves. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf.

Adjusted EBITDA

We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash flow from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

• Interest expense, including realized and unrealized losses on interest rate derivative contracts;

• Income tax expense;

• Depreciation, depletion and amortization (“DD&A”);

• Impairment of goodwill and long-lived assets (including oil and natural gas properties) (“Impairment”);

• Accretion of asset retirement obligations (“AROs”);

• Unrealized losses on commodity derivative contracts;

• Losses on sale of assets and other, net;

• Unit-based compensation expenses;

• Exploration costs;

• Acquisition related costs;

• Net operating cash flow from acquisitions, effective date through closing date; and

• Other non-routine items that we deem appropriate.

Less:

• Interest income;

• Income tax benefit;

• Unrealized gains on commodity derivative contracts;

• Gains on sale of assets and other, net; and

• Other non-routine items that we deem appropriate.

We are required to comply with certain Adjusted EBITDA-related metrics under our revolving credit facility.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

• our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis; and

• the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units.

In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.

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Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

The following tables present our calculation of Adjusted EBITDA as well as a reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated (in thousands):

	For the Three  Months Ended June 30,						For the Six  Months Ended June 30,
	2012			2011			2012			2011
				(Predecessor)						(Predecessor)
				(Recasted)						(Recasted)
Calculation of Adjusted EBITDA:
Net income (loss)	$	(415	)	$	64,459		$	21,642		$	62,515
Interest expense		3,577			2,206			4,901			3,240
Deferred income tax expense		—			122			183			122
DD&A		7,754			7,661			15,012			13,413
Impairment		—			2,893			—			2,893
Accretion of AROs		274			265			562			485
Unrealized (gains) losses on commodity derivative instruments		4,851			(2,046	)		(10,677	)		367
Gain on sale of properties		(192	)		(62,721	)		(192	)		(62,729	)
Acquisition related expenses		285			811			398			811
Unit-based compensation expense		327			—			575			—
Exploration costs		414			56			414			56
Net operating cash flow from acquisitions, effective date through closing date		1,888			—			1,888			—
Adjusted EBITDA	$	18,763		$	13,706		$	34,706		$	21,173

	For the Three  Months Ended June 30,						For the Six  Months Ended June 30,
	2012			2011			2012			2011
				(Predecessor)						(Predecessor)
				(Recasted)						(Recasted)
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA:
Net cash provided by operating activities	$	11,783		$	6,966		$	27,414		$	11,659
Changes in working capital		3,079			2,484			2,345			4,137
Interest expense		3,577			2,206			4,901			3,240
Unrealized (loss) gain on interest rate swaps		(2,135	)		(472	)		(2,397	)		(299	)
Premiums paid for derivatives		—			2,847			—			2,847
Premiums received for derivatives		—			(1,008	)		—			(1,008	)
Amortization of deferred financing fees		(128	)		(128	)		(257	)		(214	)
Acquisition related expenses		285			811			398			811
Exploration costs		414			—			414			—
Net operating cash flow from acquisitions, effective date through closing date		1,888			—			1,888			—
Adjusted EBITDA	$	18,763		$	13,706		$	34,706		$	21,173

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Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2011 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis.

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

Results of Operations

The results of operations for the three and six months ended June 30, 2012 have been derived from our consolidated financial statements. The results of operations for the three and six months ended June 30, 2011 are presented on a combined basis, consisting of the combined financial information of our predecessor. The historical financial data of our predecessor consists of the combined financial data of BlueStone Natural Resources Holdings, LLC, certain oil and natural gas properties owned by Classic and for periods after April 8, 2011, certain oil and natural gas properties owned by WHT. The results of operations covering periods prior to the closing of our IPO on December 14, 2011 may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods. Furthermore, our acquisitions of oil and gas properties from Memorial Resource in April and May 2012 were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource’s carrying value and our consolidated and predecessor financial statements previously filed with the SEC and presented herein were recast to include the financial position and results attributable to these oil and gas properties for all periods presented on a combined basis. See “— Significant Current Developments” for additional information. The following table summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.

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	For the Three Months Ended June 30,							For the Six  Months Ended June 30,
	2012			2011				2012			2011
				(Predecessor)							(Predecessor)
				(Recasted)							(Recasted)
Revenues:
Oil & natural gas sales	$	16,639		$	23,027		��	$	35,399		$	37,209
Other income		31			149				141			252
Total revenues	$	16,670		$	23,176			$	35,540		$	37,461
Costs and expenses:
Lease operating		6,213			5,643				12,234			10,272
Exploration		414			56				414			56
Production and ad valorem taxes		1,708			2,069				3,568			3,477
Depreciation, depletion, and amortization		7,754			7,661				15,012			13,413
Impairment of proved oil and natural gas properties		—			2,893				—			2,893
General and administrative		2,117			2,513				4,474			4,250
Accretion of asset retirement obligations		274			265				562			485
Realized gain on commodity derivative instruments		(9,828	)		(1,026	)			(16,908	)		(2,413	)
Unrealized (gain) loss on commodity derivative instruments		4,851			(2,046	)			(10,677	)		367
Gain on sale of properties		(192	)		(62,721	)			(192	)		(62,729	)
Other, net		197			1,082				327			1,513
Total costs and expenses		13,508			(43,611	)			8,814			(28,416	)
Operating income		3,162			66,787				26,726			65,877
Interest expense		3,577			2,206				4,901			3,240
Income (loss) before income taxes		(415	)		64,581				21,825			62,637
Income tax expense		—			122				183			122
Net income (loss)		(415	)		64,459				21,642			62,515
Net income (loss) attributable to predecessor		(161	)		64,459				1,001			62,515
Net income (loss) attributable to partners	$	(254	)	$	—			$	20,641		$	—
Oil and natural gas revenue:
Oil sales		3,374			2,372				6,595			4,146
NGL sales		2,616			3,020				5,595			3,635
Natural gas sales		10,649			17,635				23,209			29,428
Total oil and natural gas revenue	$	16,639		$	23,027			$	35,399		$	37,209
Production volumes:
Oil (MBbls)		36			23				68			43
NGLs (MBbls)		78			57				136			69
Natural gas (MMcf)		4,499			3,898				8,856			6,670
Total (MMcfe)		5,183			4,379				10,080			7,342
Average net production (MMcfe/d)		57.0			48.1				55.4			40.6
Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	92.91		$	100.99			$	97.42		$	96.53
NGL (per Bbl)	$	33.67		$	53.22			$	41.06		$	52.66
Natural gas (per Mcf)	$	2.37		$	4.52			$	2.62		$	4.41
Total (Mcfe)	$	3.21		$	5.26			$	3.51		$	5.07
Average unit costs per Mcfe:
Lease operating expense	$	1.20		$	1.29			$	1.21		$	1.40
Production and ad valorem taxes	$	0.33		$	0.47			$	0.35		$	0.47
General and administrative expenses	$	0.41		$	0.57			$	0.44		$	0.58
Depletion, depreciation, and amortization	$	1.50		$	1.75			$	1.49		$	1.83

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Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011

We recorded a net loss of $0.4 million for the three months ended June 30, 2012 compared to a net income of $64.5 million recorded by our predecessor for the three months ended June 30, 2011. The three months ended June 30, 2011 included a $62.7 million gain on the sale of properties with no comparable gain recorded during the same period in 2012.

Revenues. Oil, natural gas and NGL revenues for the three months ended June 30, 2012 were $16.6 million, a decrease of $6.4 million compared with same period in 2011. Although production increased 804 MMcfe, or 18%, the average realized sales price (excluding realized gain on derivatives) decreased $2.05 per Mcfe. The unfavorable pricing variance contributed to an $10.6 million decrease in revenues, which was partially offset by a favorable volume variance of $4.2 million. The quarter-to-quarter decrease in revenues is primarily driven by a 48% decrease in the natural gas average realized sales price. Volumes increased primarily due to properties acquired by both the Partnership from a third party in May 2012 and our predecessor in May of 2011.

Lease Operating. Lease operating expenses increased by approximately $0.6 million, or 10%, to approximately $6.2 million for the three months ended June 30, 2012, from approximately $5.6 million for the three months ended June 30, 2011. Lease operating expenses increased primarily due to costs associated with properties acquired by both the Partnership from a third party in May 2012 and our predecessor in May of 2011. On a per Mcfe basis, lease operating expenses decreased from $1.29 per Mcfe for the three months ended June 30, 2011 to $1.20 for the three months ended June 30, 2012.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended June 30, 2012 was $1.7 million, a decrease of $0.4 million compared with the same period in 2011. The decrease in these taxes was mainly due to lower oil, natural gas and NGL revenues during three months ended June 30, 2012 as compared to the same period in 2011.

Depreciation, Depletion and Amortization. DD&A expense increased slightly from approximately $7.7 million for the three months ended June 30, 2011 to approximately $7.8 million for the three months ended June 30, 2012. DD&A per Mcfe decreased from $1.75 per Mcfe for the three months ended June 30, 2011 to $1.50 for the three months ended June 30, 2012 due to an increase in proved reserve volumes between periods relative to the increase in capitalized costs subject to amortization.

Impairment of Proved Oil and Natural Gas Properties. The three months ended June 30, 2011 included a $2.9 million impairment related to an abandoned well in the Burke Unit located in South Texas due to a situation encountered during drilling, causing unrecoverability of costs and future benefit. No impairments were recorded during the three months ended June 30, 2012.

General and Administrative. Our general and administrative expenses include the costs of administrative employees and related benefits, management fees paid to Memorial Resource, professional fees and other costs not directly associated with field operations. General and administrative expenses for the three months ended June 30, 2012 was $2.1 million, which includes $0.3 million of non-cash unit-based compensation expense and $0.3 million of acquisition-related costs.

Our predecessor’s general and administrative expenses included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production. Our predecessor’s general and administrative expenses for the three months ended June 30, 2011 was $2.5 million.

Increased quarter-over-quarter production volumes drove general and administrative expenses lower on a per Mcfe basis from approximately $0.57 per Mcfe during the three months ended June 30, 2011 to $0.41 per Mcfe for the three months ended June 30, 2012.

(Gain) Loss on Commodity Derivative Instruments.We recognized a gain on commodity derivative instruments of approximately $5.0 million during the three months ended June 30, 2012, of which approximately $9.8 million was a realized gain and $4.8 million was an unrealized loss. Our predecessor recognized a gain on commodity derivative instruments of $3.1 million during the three months ended June 30, 2011. The $3.1 million gain was comprised of realized gains of approximately $1.0 million and unrealized gains of approximately $2.1 million.

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Gain on Sale of Properties.Effective January 1, 2011, our predecessor acquired BP’s interests in producing wells located in Duval, Jim Hogg, McMullen and Webb counties in exchange for (i) our predecessor’s interest in approximately 10,700 net acres located in the Nueces Field of the Eagle Ford Shale and (ii) $20 million in cash, subject to certain closing adjustments. The transaction closed on May 31, 2011 and our predecessor paid approximately $12.9 million in cash consideration at closing, net of adjustments. Our predecessor recognized a gain on sale of properties of $62.7 million during the three months ended June 30, 2011 relating to this transaction. See Note 3 of the unaudited condensed financial statements included in “Item 1. Financial Statements” for additional information. There was no comparable gain recorded for the same period in 2012.

Interest Expense. Interest expense is comprised of interest on credit facilities, amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Interest expense was $3.6 million for the three months ended June 30, 2012 attributable to the Partnership’s revolving credit facility, which included unrealized losses on interest rate swaps of approximately $2.1 million and amortization of deferred financing fees of approximately $0.1 million. Our predecessor’s interest expense was comprised of interest on its credit facilities amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Our predecessor’s interest expense was $2.2 million for the three months ended June 30, 2011 which included unrealized losses on interest rate swaps of approximately $0.5 million.

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

We recorded net income of $21.6 million for the six months ended June 30, 2012 compared to net income of $62.5 million recorded by our predecessor for the six months ended June 30, 2011. The six months ended June 30, 2011 included a $62.7 million gain on the sale of properties with no comparable gain recorded during the same period in 2012.

Revenues. Oil, natural gas and NGL revenues for the six months ended June 30, 2012 were $35.4 million, a decrease of $1.8 million compared with same period in 2011. Although production increased 2,738 MMcfe, or 37%, the average realized sales price (excluding realized gain on derivatives) decreased $1.56 per Mcfe. The unfavorable pricing variance contributed to an $15.7 million decrease in revenues, which was partially offset by a favorable volume variance of $13.9 million. The period-to-period decrease in revenues is primarily driven by a 41% decrease in the natural gas average realized sales price. Volumes increased primarily due to properties acquired by both the Partnership from a third party in May 2012 and our predecessor in April and May of 2011.

Lease Operating. Lease operating expenses increased by approximately $1.9 million, or 19%, to approximately $12.2 million for the six months ended June 30, 2012, from approximately $10.3 million for the six months ended June 30, 2011. Lease operating expenses increased primarily due to costs associated with properties acquired by both the Partnership from a third party in May 2012 and our predecessor in April and May of 2011. On a per Mcfe basis, lease operating expenses decreased from $1.40 per Mcfe for the six months ended June 30, 2011 to $1.21 for the six months ended June 30, 2012.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the six months ended June 30, 2012 was $3.6 million, an increase of $0.1 million compared with the same period in 2011. Production taxes decreased by approximately $0.1 million due to lower oil, natural gas and NGL revenues during six months ended June 30, 2012 as compared to the same period in 2011. Ad valorem taxes increased by approximately $0.2 million related to properties acquired by both the Partnership from a third party in May 2012 and our predecessor in April and May of 2011.

Depreciation, Depletion and Amortization. DD&A expense increased from approximately $13.4 million for the six months ended June 30, 2011 to approximately $15.0 million for the six months ended June 30, 2012 due to increased production from 7,342 MMcfe to 10,080 MMcfe related to properties acquired in both 2012 and 2011. DD&A decreased from $1.83 per Mcfe for the six months ended June 30, 2011 to $1.49 per Mcfe for the six months ended June 30, 2012 due to an increase in proved reserve volumes between periods relative to the increase in capitalized costs subject to amortization.

Impairment of Proved Oil and Natural Gas Properties. The six months ended June 30, 2011 included a $2.9 million impairment related to an abandoned well in the Burke Unit located in South Texas due to a situation encountered during drilling, causing unrecoverability of costs and future benefit. No impairments were recorded during the six months ended June 30, 2012.

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General and Administrative. Our general and administrative expenses include the costs of administrative employees and related benefits, management fees paid to Memorial Resource, professional fees and other costs not directly associated with field operations. General and administrative expenses for the six months ended June 30, 2012 was $4.5 million, which includes $0.6 million of non-cash unit-based compensation expense and $0.4 million of acquisition-related costs.

Our predecessor’s general and administrative expenses included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production. Our predecessor’s general and administrative expenses for the six months ended June 30, 2011 was $4.2 million.

Increased period-over-period production volumes drove general and administrative expenses lower on a per Mcfe basis from approximately $0.58 per Mcfe during the six months ended June 30, 2011 to $0.44 per Mcfe for the six months ended June 30, 2012.

(Gain) Loss on Commodity Derivative Instruments.We recognized a gain on commodity derivative instruments of approximately $27.6 million during the six months ended June 30, 2012, of which approximately $16.9 million was realized and $10.7 million was unrealized. Our predecessor recognized a gain on commodity derivative instruments of $2.0 million during the six months ended June 30, 2011. The $2.0 million gain was comprised of realized gains of approximately $2.4 million and unrealized losses of approximately $0.4 million.

Gain on Sale of Properties.Effective January 1, 2011, our predecessor acquired BP’s interests in producing wells located in Duval, Jim Hogg, McMullen and Webb counties in exchange for (i) our predecessor’s interest in approximately 10,700 net acres located in the Nueces Field of the Eagle Ford Shale and (ii) $20 million in cash, subject to certain closing adjustments. The transaction closed on May 31, 2011 and our predecessor paid approximately $12.9 million in cash consideration at closing, net of adjustments. Our predecessor recognized a gain on sale of properties of $62.7 million during the six months ended June 30, 2011 relating to this transaction. See Note 3 of the unaudited condensed financial statements included in “Item 1. Financial Statements” for additional information. There was no comparable gain recorded for the same period in 2012.

Interest Expense. Interest expense is comprised of interest on credit facilities, amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Interest expense was $4.9 million for the six months ended June 30, 2012 attributable to the Partnership’s revolving credit facility, which included unrealized losses on interest rate swaps of approximately $2.4 million and amortization of deferred financing fees of approximately $0.3 million. Our predecessor’s interest expense was comprised of interest on its credit facilities amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Our predecessor’s interest expense was $3.2 million for the six months ended June 30, 2011, which included unrealized losses on interest rate swaps of approximately $0.3 million.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for oil and natural gas and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

As of June 30, 2012, our liquidity of $99.4 million consisted of $3.4 million of available cash and $96.0 million of available borrowings under our revolving credit facility. Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We may also have the ability to issue additional equity and debt as needed. Our primary cash requirements are for distributions to our partners, capital expenditures, debt service and working capital needs.

We expect to fund cash distributions to partners primarily with operating cash flows. We also plan to reinvest a sufficient amount of our operating cash flow to fund our maintenance capital expenditures. Our growth capital expenditures, which include any acquisitions of oil and natural gas properties and related assets, are expected to be primarily funded with borrowings under our revolving credit facility or proceeds from the issuance of additional equity and debt securities. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements. We expect to fund our working capital needs primarily with operating cash flows. It is our belief that we will continue to have adequate liquidity and capital resources to fund our primary cash requirements. As of June 30, 2012, we had a positive working capital balance of $30.6 million.

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Capital Expenditures

For the three months ended June 30, 2012, total capital expenditures were $3.1 million and included maintenance capital expenditures of $2.9 million. For the six months ended June 30, 2012, total capital expenditures were $13.6 million and included maintenance capital expenditures of $5.2 million. See “— Significant Current Developments” for additional information regarding our acquisitions of oil and gas producing properties in April and May of 2012.

Revolving Credit Facility

We have a $1.0 billion revolving credit facility that expires in December 2016. Borrowings under the facility may not exceed a borrowing base determined by the lenders based on our oil and natural gas reserves. As of June 30, 2012, our revolving credit facility had borrowing capacity of $96.0 million ($300.0 million borrowing base less $204.0 million of outstanding borrowings). Our next scheduled borrowing base redetermination is October 2012. As of June 30, 2012, we were in compliance with all of the financial and other covenants under our revolving credit facility.

For additional information regarding our revolving credit facility, see Note 7 of the Notes to Unaudited Condensed Consolidated and Predecessor Combined Financial Statements included under Item 1 of this quarterly report.

Commodity Derivative Contracts

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into commodity derivative contracts covering approximately 65% to 85% of our targeted average net production over a three-to-five year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price swap hedges exceeding a certain percentage of production.

The following table reflects the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged for the periods indicated:

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	For the six months ending December 31,			For the twelve months ending December 31,												For the nine months ending September 30,
	2012			2013			2014			2015			2016			2017
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu/d)		22,229			36,499			40,221			36,420			33,550			30,992
Weighted-average fixed price	$	4.50		$	4.45		$	4.43		$	4.35		$	4.56		$	4.33
Collar contracts:
Average Monthly Volume (MMBtu/d)		18,913			6,674			—			—			—			—
Weighted-average floor price	$	4.83		$	5.07		$	—		$	—		$	—		$	—
Weighted-average ceiling price	$	5.87		$	5.80		$	—		$	—		$	—		$	—
Put options:
Average Monthly Volume (MMBtu/d)		2,283			—			—			—			—			—
Weighted-average strike price	$	4.80		$	—		$	—		$	—		$	—		$	—
Total natural gas volumes hedged (MMBtu/d)		43,425			43,173			40,221			36,420			33,550			30,992
Total weighted-average floor price	$	4.66		$	4.54		$	4.43		$	4.35		$	4.56		$	4.33
Percent of targeted average net production		88	%		87	%		81	%		73	%		68	%		63	%
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls/d)		155			152			176			264			246			247
Weighted-average fixed price	$	98.63		$	99.53		$	89.99		$	90.93		$	91.03		$	87.75
Collar contracts:
Average Monthly Volume (Bbls/d)		147			156			105			—			—			—
Weighted-average floor price	$	86.67		$	87.16		$	90.00		$	—		$	—		$	—
Weighted-average ceiling price	$	115.12		$	116.94		$	117.72		$	—		$	—		$	—
Total crude oil volumes hedged (Bbl/d)		302			308			281			264			246			247
Total weighted-average floor price	$	92.81		$	93.26		$	89.99		$	90.93		$	91.03		$	87.75
Percent of targeted average net production		82	%		84	%		76	%		72	%		67	%		67	%
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls/d)		356			477			—			—			—			—
Weighted-average fixed price	$	44.93		$	52.94		$	—		$	—		$	—		$	—
Collar contracts:
Average Monthly Volume (Bbls/d)		124			—			—			—			—			—
Weighted-average floor price	$	75.16		$	—		$	—		$	—		$	—		$	—
Weighted-average ceiling price	$	93.57		$	—		$	—		$	—		$	—		$	—
Total NGL volumes hedged (Bbl/d)		480			477			—			—			—			—
Total weighted-average floor price	$	52.73		$	52.94		$	—		$	—		$	—		$	—
Percent of targeted average net production		56	%		56	%		—			—			—			—

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Interest Rate Derivative Contracts

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. We had the following fixed-for floating interest rate swap open positions as of August 1, 2012:

Period Covered			Notional ($ in thousands)		Floating Rate	Fixed Rate
	1/17/2012	1/17/2013	$	100,000	1 Month LIBOR	0.600%
	1/17/2013	12/14/2016	$	100,000	1 Month LIBOR	1.305%
	5/17/2012	1/17/2013	$	50,000	1 Month LIBOR	0.600%
	1/17/2013	12/14/2016	$	50,000	1 Month LIBOR	0.970%

Counterparty Exposure

As of June 30, 2012, the fair value of our open derivative contracts was a net receivable of $43.8 million. All of our derivative contracts are with major financial institutions who are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the six months ended June 30, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated and Predecessor Combined Cash Flows included under Item 1 of this quarterly report. Our acquisitions of oil and gas properties from Memorial Resource in April and May 2012 were each accounted for as a transaction between entities under common control. As a result, our consolidated and predecessor financial statements previously filed with the SEC were recast to include the financial position and results attributable to these oil and gas properties for all periods presented on a combined basis. See “— Significant Current Developments” for additional information.

	For the Six Months Ended June 30,
	2012			2011
				(Predecessor)
				(Recasted)
Net cash provided by operating activities	$	27,414		$	11,659
Net cash used in investing activities		(49,690	)		(163,398	)
Net cash provided by financing activities		24,560			148,462

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash flows provided by operating activities increased for the six months ended June 30, 2012 primarily due to an increase in production volumes as a result of properties acquired by the Partnership from an undisclosed third party seller in May 2012 and our predecessor’s acquisition activities in 2011. We used cash flows provided by operating activities primarily to fund distributions to our partners and additions to oil and gas properties. Our predecessor primarily used cash flows provided by operating activities to fund its exploration and development expenditures.

Investing Activities. Cash used in investing activities for the six months ended June 30, 2012 was $49.7 million, driven by a $37.3 million acquisition of oil and natural gas properties from an undisclosed third party seller and $12.3 million for additions to oil and gas properties. During the six months ended June 30, 2012, we participated in 3 new drills in East Texas, none of which were dry holes, for a success rate of 100%.

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Cash used in investing activities for the six months ended June 30, 2011 was $163.4 million, driven mostly by acquisitions of oil and natural gas properties of $137.9 million and $25.1 million for additions to oil and gas properties. During the six months ended June 30, 2011, our predecessor participated in the drilling of 6 wells, one of which was a dry hole, for a success rate of 83%.

Financing Activities. Distributions to partners for the six months ended June 30, 2012 were $12.7 million, of which Memorial Resource received $7.2 million. See Note 8 of the Notes to Unaudited Condensed Consolidated and Predecessor Financial Statements included under Item 1 of this quarterly report for additional information about cash distributions to unitholders. We distributed $45.5 million to Memorial Resource in connection with our acquisitions of oil and gas properties from them in April and May 2012. See “— Significant Current Developments” for additional information. In April and May 2012, we borrowed $84.0 million to fund the acquisitions of oil and gas properties and for other general partnership purposes. During the six months ended June 30, 2012, the net cash provided by operating activities attributable to the net assets transferred from Memorial Resource exceeded the cash used in investing activities by $1.2 million and is reflected as a distribution on our cash flow statement.

During the six months ended June 30, 2011, our predecessor received capital contributions of $52.8 million and had net borrowings of $90.9 million. The cash used in investing activities attributable to the net assets transferred from Memorial Resource exceeded the net cash provided by operating activities by $5.6 million and is reflected as a contribution on our cash flow statement for the six months ended June 30, 2011. Our predecessor primarily used cash flows provided by financing activities to fund its development and property acquisition program.

Contractual Obligations

During the six months ended June 30, 2012, there were no significant changes in our consolidated contractual obligations from those reported in our 2011 Form 10-K except for borrowings made under our revolving credit facility. See Note 7 of the Notes to Unaudited Condensed Consolidated and Predecessor Financial Statements included under Item 1 of this quarterly report for additional information about our debt obligations.

Off–Balance Sheet Arrangements

As of June 30, 2012, we had no off–balance sheet arrangements.

Recent Accounting Developments

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

On July 13, 2012, the SEC’s Office of the Chief Accountant published its final staff report on the Work Plan related to global accounting standards. The SEC directed the staff in February 2010 to develop and execute the work plan. The SEC issued a statement at the time indicating that the information obtained through the Work Plan would aid the SEC in evaluating the implications of incorporating International Financial Reporting Standards (“IFRS”) into the financial reporting system for U.S. companies. The report does not include a recommendation to the SEC about whether or how to incorporate IFRS into the US financial reporting system. The report notes that the SEC still needs to analyze and consider the threshold question — whether and, if so, how and when IFRS should be incorporated into the U.S. financial reporting system. As a result, we do not expect a decision before 2013.

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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 do not believe that our exposures to market risk have changed materially since those reported under Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2011 Form 10-K.

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, 2012, see Note 5 of the Notes to Unaudited Condensed Consolidated and Predecessor Combined Financial Statements included under Item 1 of this quarterly report. In August 2012, we executed additional hedges on a portion of our expected oil and natural gas volumes through the third quarter of 2017. We now have open commodity positions covering the period from July 2012 through September 2017. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Commodity Derivative Contract” for additional details.

Interest Rate Risk

At June 30, 2012, we had $204.0 million of debt outstanding under our revolving credit facility, with a weighted average interest rate of LIBOR plus 2.25%, or 2.50%. 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. The following interest rate swap arrangements were outstanding at June 30, 2012:

• $100,000,000 notional amount fixed-for-floating swap for the period beginning January 17, 2012 and ending January 17, 2013 at a fixed annual rate of 0.60%;

• $100,000,000 notional amount fixed-for-floating swap for the period beginning January 17, 2013 and ending December 14, 2016 at a fixed annual rate of 1.305%;

• $50,000,000 notional amount fixed-for-floating swap for the period beginning May 17, 2012 and ending January 17, 2013 at a fixed annual rate of 0.60%; and

• $50,000,000 notional amount fixed-for-floating swap for the period beginning January 17, 2013 and ending December 14, 2016 at a fixed annual rate of 0.97%.

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 our weighted average interest rate, after giving effect to our interest rate swaps, would be less than $0.1 million per year.

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. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. Each of the counterparties to our derivative contracts is a lender in our credit agreement. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial

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institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had our counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset our $43.8 million net derivative asset receivable against amounts outstanding under our revolving credit facility.

On June 21, 2012, some of the world’s biggest banks were downgraded by rating agency Moody’s Investors Service (“Moody’s”), which cited concerns about the stability of the global financial system. The prospect of downgrades had weighed on the financial industry since Moody’s announced in February 2012 it was reviewing 17 global banks with capital-markets operations. Two of our counterparties were downgraded two notches, but still have investment grade ratings. The downgrades did not materially affect the estimated fair value of our net commodity derivative assets.

ITEM 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report. 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 the principal executive officer and principal financial officer of our general partner, 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 the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2012.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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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 12, “Commitments and Contingencies – Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated and Predecessor Combined Financial Statements included in this quarterly report, which is incorporated herein by reference.

ITEM 1A. RISK FACTORS.

There have been no material changes with respect to the risk factors disclosed in our 2011 Form 10-K.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

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ITEM 6. EXHIBITS.

Exhibit Number	Description
3.1	—	Certificate of Limited Partnership of Memorial Production Partners LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).
3.2	—	First Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).
3.3	—	Certificate of Formation of Memorial Production Partners GP LLC (Incorporated by reference to Exhibit 3.4 of the Partnership’s Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).
3.4	—	Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC (Incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).
31.1*	—	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
32.1*	—	Certifications of Chief Executive Officer and Chief 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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 Production Partners LP
	(Registrant)
	By:	Memorial Production Partners GP LLC, its general partner
Date: August 14, 2012	By:	/s/ Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Vice President and Chief Financial Officer of Memorial Production Partners GP LLC

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