Amplify Energy Corp - FORM 10-K

Attached files

file	filename
EX-21.1 - LIST OF SUBSIDIARIES OF MEMORIAL PRODUCTION PARTNERS LP - Amplify Energy Corp	d320669dex211.htm
EX-23.2 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Amplify Energy Corp	d320669dex232.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - Amplify Energy Corp	d320669dex321.htm
EX-99.1 - REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Amplify Energy Corp	d320669dex991.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A)/15D-14(A) - Amplify Energy Corp	d320669dex312.htm
EX-23.1 - CONSENT OF KPMG L.L.P. - Amplify Energy Corp	d320669dex231.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A-14(A)/15D-14(A) - Amplify Energy Corp	d320669dex311.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–K

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

For the fiscal year ended December 31, 2011

¨	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

Securities registered pursuant to Section 12(b) of the Act:


Common Units Representing Limited Partner Interests		NASDAQ Global Market
(Title of each class)		(Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 x 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 ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to the Form 10–K x

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	x (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 x

As of June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s equity was not listed on any domestic exchange or over-the-counter market. The registrant’s common units began trading on the NASDAQ Global Market on December 9, 2011. As of March 16, 2012, the registrant had 16,842,175 common units, 5,360,912 subordinated units and 22,222 general partner units outstanding.

MEMORIAL PRODUCTION PARTNERS LP

TABLE OF CONTENTS


		Page
	PART I
Item 1.	Business.		9
Item 1A.	Risk Factors.		31
Item 1B.	Unresolved Staff Comments.		57
Item 2.	Properties.		57
Item 3.	Legal Proceedings.		57
Item 4.	Mine Safety Disclosures.		57

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.		58
Item 6.	Selected Financial Data.		62
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		63
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.		84
Item 8.	Financial Statements and Supplementary Data.		86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.		86
Item 9A.	Controls and Procedures.		86
Item 9B.	Other Information.		87

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.		88
Item 11.	Executive Compensation.		95
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.		101
Item 13.	Certain Relationships and Related Transactions, and Director Independence.		102
Item 14.	Principal Accountant Fees and Services.		107

	PART IV
Item 15.	Exhibits and Financial Statement Schedules.		108
	Signatures		110

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.

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 working interest.

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.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate and natural gas liquids.

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.

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.

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.

NAMES OF ENTITIES

As used in this Form 10-K, 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.

FORWARD–LOOKING STATEMENTS

This Annual Report on Form 10-K 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. These forward-looking statements may be found in “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this report. 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-K including, but not limited to:

•

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 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;

•

the material weakness in our internal control over financial reporting;

•

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 “Item 1A. Risk Factors” 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.

PART I

ITEM 1.

BUSINESS

Overview

Memorial Production Partners LP is a Delaware limited partnership formed in April 2011 by Memorial Resource 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, 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 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. All of our assets were received from Memorial Resource on December 14, 2011 in connection with our initial public offering (“IPO”) and consist of oil and gas producing properties located in Louisiana and Texas. These properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, predictable production profiles and modest capital requirements. As of December 31, 2011:

•

our total estimated proved reserves were approximately 324 Bcfe, of which approximately 79% were classified as proved developed reserves including approximately 13% classified as proved developed non-producing;

•

we had interests in 1,274 gross (590 net) producing wells across our properties, with an average working interest of 46%; and

•

approximately 67 Bcfe, or 21%, of our estimated proved reserves were classified as proved undeveloped, of which approximately 84% were natural gas.

Oil and natural gas reserve information included in this Form 10-K is derived from our reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers. The following table summarizes information about our proved oil and natural gas reserves by geographic region as of December 31, 2011 and our average net production for the year ended December 31, 2011:


	Estimated Net Proved Reserves								Average Net Production (1)					Average Reserve-to- Production Ratio (2)		Producing Wells
	MMcfe		% Natural Gas			% Proved Developed			MMcfe/d		% of Total			Average Reserve-to- Production Ratio (2)		Gross		Net
														(Years)
South Texas		176,481		98	%		87	%		29.5		61	%		16		502		397
East Texas		147,598		74	%		71	%		19.3		39	%		20		772		193

Aggregate		324,079		87	%		79	%		48.8		100	%		18		1,274		590

(1)	During 2011, our predecessor acquired significant oil and gas properties from third parties. As such, the average net production only reflects production from these properties from the acquisition date to December 31, 2011.

(2)	The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of December 31, 2011 by average net production for the year ended December 31, 2011.

Recent Developments

Definitive Agreement to Acquire Oil & Gas Producing Properties from Memorial Resource

On March 7, 2012, we announced the entry into a definitive agreement to acquire certain non-operating interests in oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource for a purchase price of $18.3 million, subject to customary purchase price adjustments. The transaction is expected to close on or about April 2, 2012 and will be financed with borrowings under our revolving credit facility. The transaction also includes the novation of 2012 through 2013 commodity derivative positions to the Partnership. Terms of the transaction were approved by the board of directors of our general partner 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. Approximately 82% of the current net production of 2.3 MMcfe/d is natural gas and the remaining 18% is oil and NGLs.

Initial Public Offering of Memorial Production Partners LP

On December 14, 2011, we completed our IPO of 9,000,000 common units representing limited partner interests in the Partnership at $19.00 per common unit for total net proceeds of approximately $146.5 million after deducting underwriting discounts, structuring fees and other offering and formation-related fees. Our common units are traded on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” In connection with our IPO, Memorial Resource contributed to us certain oil and natural gas properties in South Texas and East Texas in exchange for the net proceeds from our IPO, together with borrowings of $130.0 million under our revolving credit facility (described below), 7,061,294 common units and 5,360,912 subordinated units.

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 at the initial public offering price. Total net proceeds from the exercise of the underwriters’ over-allotment option, after deducting estimated offering costs, were $10.7 million. Of this amount, $10.0 million was used to repay indebtedness under our revolving credit facility.

Upon completion of our IPO and the underwriters’ partial exercise of their over-allotment option, we had 16,661,294 common units, 5,360,912 subordinated units and 22,044 general partner units outstanding. Following our IPO and the underwriters’ exercise of their over-allotment option, Memorial Resource owned approximately 42.4% of the common units and 100% of the subordinated units. Memorial Resource owns all of the voting interests in our general partner, and the Funds own non-voting membership interests in our general partner that entitle them collectively to 50% of all cash distributions and common units received by our general partner in respect of the Partnership’s incentive distribution rights.

New Credit Facility

On December 14, 2011, in connection with our IPO, we entered into a new senior secured revolving credit facility between us as parent guarantor, OLLC as borrower and a syndication of banks as lenders. Our revolving credit facility is a five-year, $1.0 billion revolving credit facility with an initial borrowing base of $300.0 million. The borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts.

Predecessor Acquisitions of Oil & Gas Properties

Our predecessor acquired oil and natural gas properties and related assets from BP America Production Company (“BP”) on May 31, 2011 for $12.9 million in cash, net of closing adjustments, and an exchange of assets located in Texas. Total proved reserves of the acquired properties were estimated by our predecessor’s internal reserve engineers to be 47,075 MMcfe as of December 31, 2010. The BP properties comprised approximately 14% of the total proved reserves conveyed to us on December 14, 2011 by Memorial Resource.

On April 8, 2011, our predecessor acquired producing oil and natural gas properties in East Texas from a third party for $120.8 million. Total proved reserves of the acquired properties were estimated by our predecessor’s internal reserve engineers to be 112,544 MMcfe as of December 31, 2010. These properties comprised approximately 35% of the total proved reserves conveyed to us on December 14, 2011 by Memorial Resource.

Business Strategy

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. To achieve our objective, we intend to execute the following business strategies:

•

Maintain and grow a stable production profile through accretive acquisitions and low-risk development. Our development plans target proved drilling locations that are low cost, present minimal risk, and support a stable production profile. We seek to acquire proved developed properties with long-lived reserves, low production decline rates and identified and predictable development potential. We believe that our management team’s experience positions us to identify, evaluate, execute, integrate and exploit suitable acquisitions.

•

Strategically utilize our relationship with Memorial Resource, the Funds, and their respective affiliates (including NGP) to gain access to and, from time to time, acquire producing oil and natural gas properties that meet our acquisition criteria. We may have the opportunity to acquire producing oil and natural gas properties directly from Memorial Resource, the Funds, or their respective affiliates from time to time in the future. While none of Memorial Resource, the Funds, or any of their respective affiliates is contractually obligated to offer or sell any properties to us, we believe that selling properties to us will enhance Memorial Resource’s and, accordingly, the Funds’ economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on Memorial Resource’s (and the Funds’) limited partner and incentive distribution interests in us.

•

Leverage our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP) to participate in acquisitions of third party producing properties and to increase the size and scope of our potential third-party acquisition targets. Memorial Resource was formed in part to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, NGP and its affiliates (including the Funds) have long histories of pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), we expect that we will have access to their significant pool of management talent and industry relationships, which we believe provides us a competitive advantage in pursuing potential third-party acquisition opportunities. We may have the opportunity to work jointly with Memorial Resource to pursue certain acquisitions of oil and natural gas properties that may not otherwise be attractive acquisition candidates for either of us individually. For example, we and Memorial Resource may jointly pursue an acquisition where we would acquire the proved developed portion of the acquired properties and Memorial Resource would acquire the undeveloped portion. We believe this arrangement will give us access to an array of third-party acquisition opportunities that we would not otherwise be in a position to pursue.

•

Exploit opportunities on our current properties and manage our operating costs and capital expenditures. We intend to pursue low-risk drilling of our proved undeveloped inventory and to perform cost-reducing operational enhancements. Pursuant to an omnibus agreement, Memorial Resource provides us and our general partner with operating, management, and administrative services, which we believe provides us with significant technical expertise and experience that will allow us to identify and execute cost-reducing exploitation and operational improvements on both our existing properties and new acquisitions. Memorial Resource’s operational control of substantially all of our proved reserves as well as its own, often adjoining or complementary, properties enables direct influence and implementation of cost reduction initiatives.

•

Reduce exposure to commodity price risk and stabilize cash flows through a disciplined commodity hedging policy. We intend to maintain a portfolio of 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 in time. These commodity derivative contracts include natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. We believe these commodity derivative contracts will allow us to mitigate the impact of oil and natural gas price volatility, thereby increasing the predictability of our cash flow.

•

Maintain reasonable levels of indebtedness to permit us to opportunistically finance acquisitions. We intend to maintain modest levels of indebtedness in relation to our cash flows from operations. We believe our internally generated cash flows and our borrowing capacity under our revolving credit facility will provide us with the financial flexibility to pursue our acquisition and development strategy in an effective and competitive manner.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:

•

Our long-lived reserves with significant production history and predictable production decline rates. Our total estimated proved reserves as of December 31, 2011 divided by our average net production for the year ended December 31, 2011, which we refer to as our reserve to production index, was 18 years. Based on our forecasted daily production reflected in our reserve reports, the average estimated decline rate for our existing proved developed producing reserves is approximately 11% for the year ending December 31, 2012, approximately 7% compounded average annual decline for the subsequent four years and approximately 6% per year thereafter. Our estimated well life is typically more than 20 years, providing a long history of production that enables better predictability of future production decline rates.

•

Our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), which we believe provide us with access to a portfolio of additional oil and natural gas properties that meet our acquisition criteria. Memorial Resource was formed in part to own and acquire producing properties and to develop properties into mature, long-lived producing assets. As of December 31, 2011, Memorial Resource had (i) total estimated proved reserves of over 1,000 Bcfe, primarily located in East Texas, North Louisiana and the Rockies and (ii) interests in over 233,000 gross (132,000 net) acres of undeveloped properties. Based on Memorial Resource’s intention to develop its properties and Memorial Resource’s 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 “— Recent Developments” for additional information regarding the Partnership’s entry into a definitive agreement to acquire certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource.

•

Our management team’s extensive experience in the acquisition, development and integration of oil and natural gas assets. The members of our management team have extensive experience in the oil and natural gas industry. See “Item 10 — Directors, Executive Officers and Corporate Governance—Directors and Executive Officers” for additional information concerning the background of our management team.

•

Our relationship with Memorial Resource, which provides us with extensive technical expertise in and familiarity with developing and operating oil and natural gas assets within our core focus areas. Through our omnibus agreement with Memorial Resource, we have the operational support of petroleum professionals, many of whom have significant engineering and geoscience expertise in South and/or East Texas, which are our current geographical areas of focus. We believe that this technical expertise differentiates us from, and provides us with a competitive advantage over, many of our competitors. We intend to utilize these resources in maximizing our production and ultimate reserve recovery, which could add substantial value to our assets.

•

Our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), which we believe will help us with access to and in the evaluation and execution of future acquisitions. We believe that our ability to use the industry relationships and broad expertise of Memorial Resource and NGP in expanding our access to acquisitions and evaluating oil and natural gas assets will expand our opportunities and differentiate us from many of our competitors. Additionally,

we expect to have the opportunity to work jointly with Memorial Resource to pursue acquisitions of oil and natural gas properties that we would not otherwise be able to pursue on our own or that may not otherwise be attractive acquisition candidates for either of us individually.

•

Our diverse distribution of reserve value, with 1,274 gross (590 net) producing wells as of December 31, 2011, none of which contains estimated proved reserves in excess of 3% of our total estimated proved reserves as of December 31, 2011. The value of our total estimated proved reserves, as approximated by the standardized measure, is spread across a wide subset of our producing wells. Our top 10 wells by value represent 12% of our total standardized measure at December 31, 2011. The value of our total estimated proved reserves, as approximated by the standardized measure, is also widely distributed across our producing fields. No single producing field in our total estimated proved reserves represents more than 36% of our aggregate standardized measure at December 31, 2011.

•

Our inventory of 305 proved low-risk infill drilling, recompletion and development opportunities in our core operational areas. We have a substantial inventory of low risk, proved undeveloped locations. At December 31, 2011, our properties included approximately 67 Bcfe of estimated proved undeveloped reserves, and had 88 proved identified low-risk proved drilling locations and 217 proved recompletion and development opportunities. In 2012, our capital spending program is expected to be approximately $14—$22 million (including maintenance capital expenditures). We expect our aggregate production in 2012 to be approximately 18-19 Bcfe. For a more detailed discussion of our capital spending program, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Outlook.”

•

Our competitive cost of capital and financial flexibility. Unlike our corporate competitors, we do not expect to be subject to federal income taxation at the entity level. We believe that this attribute should provide us with a lower cost of capital compared to many of our competitors, thereby enhancing our ability to compete for future acquisitions, both individually and jointly with Memorial Resource. We also expect that our ability to issue additional common units and other partnership interests in connection with acquisitions will enhance our financial flexibility. Further, we intend to utilize a modest amount of debt to provide flexibility in our capital structure.

Our Relationship with Memorial Resource

Memorial Resource is a Delaware limited liability company formed by the Funds to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. As part of the formation transactions, the Funds contributed to Memorial Resource their respective ownership of five separate portfolio companies (including those comprising our predecessor), all of which are engaged in the business of owning, acquiring, exploiting, and developing oil and natural gas properties, and certain of which contributed our properties to us. Memorial Resource is engaged in its business with the objective of growing its reserves, production and cash flows, as well as owning our general partner and a significant limited partner interest in us.

Our general partner has entered into an omnibus agreement with Memorial Resource and the Partnership in which Memorial Resource has agreed to provide the administrative, management and operational services that we believe are necessary to allow our general partner to manage, operate and grow our business.

As of December 31, 2011, Memorial Resource had (i) total estimated proved reserves of over 1,000 Bcfe, primarily located in East Texas, North Louisiana and the Rockies and (ii) interests in over 233,000 gross (132,000 net) acres of undeveloped properties. We believe that many of these properties are (or after additional capital is invested will become) suitable for us, based on our criteria that suitable properties consist of mature onshore oil and natural gas reservoirs with long-lived, low-decline, predictable production profiles. We also believe the largely contiguous and overlapping nature of Memorial Resource’s and our East Texas acreage, along with joint ownership in specific properties, provides key operational, logistical and technical benefits derived from our aligned interests and information sharing among personnel, in addition to various economic benefits.

As a result of its significant ownership interests in us and our general partner, we believe Memorial Resource will be motivated to support the successful execution of our business strategy and will provide us with opportunities to pursue acquisitions that will be accretive to our unitholders. Memorial Resource views our partnership as part of its growth strategy, and we believe that Memorial Resource will be incentivized to contribute or sell additional assets to us and to pursue acquisitions jointly with us in the future. However, Memorial Resource regularly evaluates acquisitions and dispositions and may elect to acquire or dispose of properties in the future without offering us the opportunity to participate in those transactions. Moreover, Memorial Resource is free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with future acquisition opportunities. Although we believe Memorial Resource is incentivized to offer properties to us for purchase, none of Memorial Resource, the Funds or any of their respective affiliates has any obligation to sell or offer properties to us. If Memorial Resource fails to present us with, or successfully competes against us for, acquisition opportunities, then our ability to replace or increase our estimated proved reserves may be impaired, which would adversely affect our cash flow from operations and our ability to make cash distributions to our unitholders.

Our Relationship with Natural Gas Partners and the Funds

Founded in 1988, NGP is a family of private equity investment funds with aggregate committed capital of over $7 billion, organized to make direct equity investments in the energy industry. NGP is part of the investment platform of NGP Energy Capital Management, one of the leading investment franchises in the natural resources sector with over $9 billion in aggregate committed capital under management. The employees of NGP are experienced energy professionals with substantial expertise in investing in the oil and natural gas business. In connection with NGP’s business, these employees review a large number of potential acquisitions and are involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which NGP owns interests. We believe that our relationship with NGP, and its experience investing in oil and natural gas companies, provides us with a number of benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals who have experience in assisting the companies in which it has invested to meet their financial and strategic growth objectives. Although we may have the opportunity to make acquisitions as a result of our relationship with NGP, NGP has no legal obligation to offer to us (or inform us about) any acquisition opportunities, may decide not to offer any acquisition opportunities to us and is not restricted from competing with us, and we cannot say which, if any, of such potential acquisition opportunities we would choose to pursue.

The Funds, which are three of the private equity funds managed by NGP, collectively own 100% of Memorial Resource. The Funds collectively directly own, through non-voting membership interests in our general partner, 50% of the economic interest in our incentive distribution rights. The remaining economic interest in our incentive distribution rights is owned by Memorial Resource. Given this alignment of interests between NGP, the Funds, Memorial Resource and us, we believe we benefit from the collective expertise of NGP’s employees and their extensive network of industry relationships, and accordingly the access to potential acquisition opportunities that might not otherwise be available to us.

Our Areas of Operation

On December 14, 2011, Memorial Resource contributed to us certain oil and natural gas properties in South Texas and East Texas geographical areas. The following discussion reflects activity for the year ended December 31, 2011 and as of December 31, 2011.

South Texas

Approximately 54% of our estimated proved reserves as of December 31, 2011 and approximately 61% of our average daily net production for the year ended December 31, 2011 were located in the South Texas region. Our South Texas properties include wells and properties in numerous natural gas weighted fields located in McMullen, Live Oak, Duval, Jim Hogg, Webb and Zapata Counties, Texas, including the NE Thompsonville, Laredo and East Seven Sisters fields. Our South Texas properties contained 176 Bcfe of estimated net proved

reserves as of December 31, 2011 based on our reserve reports. Those properties collectively generated average net production of 29.5 MMcfe/d for the year ended December 31, 2011.

East Texas

Approximately 46% of our estimated proved reserves as of December 31, 2011 and approximately 39% of our average daily net production for the year ended December 31, 2011 were located in the East Texas region. Our East Texas properties include wells and properties located in Navarro, Henderson, Anderson, Wood, Upshur, Gregg, Harrison, Rusk, Panola, Nacogdoches and Shelby Counties, Texas and De Soto Parish, Louisiana. Those properties collectively contained 148 Bcfe of estimated net proved reserves as of December 31, 2011 based on our reserve reports and generated average net production of 19.3 MMcfe/d for the year ended December 31, 2011. Our East Texas properties include properties in the Joaquin and Carthage fields, adjacent natural gas weighted fields located in Panola and Shelby counties. The Joaquin and Carthage fields contain substantially the same stratigraphic intervals and each contains multiple production units.

Our Oil and Natural Gas Data

Our Reserves

Internal Controls. Our proved reserves are estimated at the well or unit level and compiled for reporting purposes by NSAI, our independent reserve engineers. Memorial Resource maintains internal evaluations of our reserves in a secure reserve engineering database. NSAI interacts with Memorial Resource’s internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our senior management on a semi-annual basis. Our reserve estimates are evaluated by NSAI at least annually.

Our internal professional staff works closely with NSAI to ensure the integrity, accuracy and timeliness of data that is furnished to it for its reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide NSAI other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their evaluation of our reserves.

Qualifications of Responsible Technical Persons

Internal Engineers. Larry R. Forney is the technical person at Memorial Resource primarily responsible for liaison with and oversight of our third-party reserve engineers, NSAI, which prepared the reserve report for our properties. Mr. Forney has served as our general partner’s Vice President of Operations and Asset Management since August 2011. From August 2008 to August 2011, Mr. Forney served as President of Mossback Management LLC, a private entity providing contract operating and engineering consulting services, including managing all operations and related business functions for Hungarian Horizon Energy, Ltd and Central European Drilling, Ltd in Budapest, Hungary from July 2010 to August 2011. From July 2004 to July 2008, Mr. Forney served as Vice President of Operations for Greystone Oil & Gas LLP and Managing Director of Greystone Drilling LP. Mr. Forney served as Vice President of Operations for Greystone Petroleum LLC from 2002 until 2004. Mr. Forney was Vice President and Treasurer of Goldrus Producing Company from 1997 to 2002. From 1990 to 1997, Mr. Forney held various positions for the Kelley Oil companies, which culminated in his serving concurrently as Vice President of Operations for Kelley Oil Corporation and Vice President of Concorde Gas Marketing. Prior to 1990, Mr. Forney held various drilling, production and facility construction positions with Pacific Enterprises Oil Corporation and Kerr-McGee Corporation. Mr. Forney is a graduate of the University of Texas at Austin with a B.S. in petroleum engineering and a registered professional engineer in Texas.

Netherland, Sewell & Associates, Inc. NSAI is an independent oil and natural gas consulting firm. No director, officer, or key employee of NSAI has any financial ownership in us, Memorial Resource, the Funds, or any of their respective affiliates. NSAI’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported. NSAI has not performed other work for us, Memorial Resource, the Funds, or any of their respective affiliates that would affect its objectivity. The estimates of proved reserves at December 31, 2011 presented in the NSAI report were overseen by Mr. Justin S. Hamilton, Mr. David E. Nice and Mr. David T. Miller.

Mr. Hamilton has been practicing consulting petroleum engineering at NSAI since 2004. Mr. Hamilton is a Registered Professional Engineer in the State of Texas (License No. 104999) and has over 10 years of practical experience in petroleum engineering, with over 10 years’ experience in the estimation and evaluation of reserves. He graduated from Brigham Young University in 2000 with a Bachelor of Science Degree in Mechanical Engineering and from the University of Texas in 2007 with a Master of Business Administration Degree.

Mr. Nice has been practicing consulting petroleum geology at NSAI since 1998. Mr. Nice is a Licensed Professional Geophysicist in the State of Texas, Geology (License No. 346) and has over 26 years of practical experience in petroleum geosciences, with over 13 years’ experience in the estimation and evaluation of reserves. He graduated from the University of Wyoming in 1982 with a Bachelor of Science Degree in Geology and in 1985 with a Master of Science Degree in Geology.

Mr. Miller is a Licensed Professional Engineer in the State of Louisiana (License No. 22695) and has over 30 years of practical experience in petroleum geosciences, with about 15 years’ experience in the estimation and evaluation of reserves. He graduated from the University of Kentucky in 1981 with a Bachelor of Science Degree in Civil Engineering and from Southern Methodist University in 1994 with a Masters of Business Administration Degree.

All technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; all are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2011, based on our reserve reports prepared by NSAI, our independent reserve engineers. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.


Estimated Proved Reserves
Oil (MBbls)		2,064
NGLs (MBbls)		4,700
Natural gas (MMcf)		283,495

Total (MMcfe) (1)		324,079

Proved developed (MMcfe)		257,481
Proved undeveloped (MMcfe)		66,598
Proved developed reserves as a percentage of total proved reserves		79	%
Standardized measure (in millions)	$	378,262
Oil and Natural Gas Prices (2)
Oil – WTI Posting (Plains) per Bbl	$	92.71
Natural gas – NYMEX Henry Hub per MMBtu	$	4.118

(1)	Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)

Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to derivative contracts, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, please read “Item 1A. Risk Factors — Risks Related to Our Business — Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by the FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves

None of our proved undeveloped reserves as of December 31, 2011 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, Memorial Resource’s drilling and development programs were substantially funded from its cash flow from operations. Our expectation is to continue to fund our drilling and development programs, with respect to maintenance capital expenditures, primarily from our cash flow from operations, and to fund growth capital expenditures with external capital. Based on our current expectations of our cash flows and available external capital (including our revolving credit facility), as well as our drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions in the next five years from our cash flow from operations and, if needed, our revolving credit facility. For a more detailed discussion of our liquidity position, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Production, Revenue and Price History

For a description of the Partnership’s and the predecessor’s historical production, revenues and average sales prices and unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.”

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2011.


	Oil				Natural Gas
	Gross		Net		Gross		Net
Operated(1)		5		2		876		549
Non-operated		1		1		392		38

Total		6		3		1,268		587

(1)	Includes wells operated by Memorial Resource on our behalf.

Developed Acreage

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2011, all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2011 relating to our leasehold acreage.


	Developed Acreage (1)
	Gross (2)		Net (3)
South Texas (4)		82,400		72,744
East Texas		27,020		19,692

Total		109,420		92,436

(1)	Developed acres are acres spaced or assigned to productive wells or wells capable of production.

(2)	A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(3)	A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

(4)	Our South Texas developed acreage, all of which is held by production, includes acreage subject to infill drilling. The infill drilling acreage allows for additional drilling that equates to 1,800 gross and 1,470 net acres, respectfully, which is included in the following Undeveloped Acreage table.

Undeveloped Acreage

The following table sets forth information as of December 31, 2011 relating to our undeveloped leasehold acreage.


	Undeveloped Acreage (1)
	Gross (2)		Net (3)
South Texas (4)		1,800		1,470
East Texas		27,504		19,853

Total		29,304		21,323

(1)	Undeveloped acres are acres spaced or assigned to proved undeveloped reserve locations.

(2)	A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(3)	A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

(4)

Our South Texas undeveloped acreage, all of which is held by production, consists entirely of infill drilling locations. These locations are associated with existing proved developed acreage. Thus, the South Texas acreage included in this table is also included in the preceding Developed Acreage table.

Drilling Activities

Our drilling activities consist entirely of development wells. The following table sets forth information with respect to wells drilled and completed by us and our predecessor during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.


	Year Ended December 31,
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Development wells:
Productive		4.0		3.1		3.0		2.7		4.0		3.7
Dry		—		—		—		—		1.0		0.9
Exploratory wells:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total wells:
Productive		4.0		3.1		3.0		2.7		4.0		3.7
Dry		—		—		—		—		1.0		0.9

Total		4.0		3.1		3.0		2.7		5.0		4.6

Delivery Commitments

We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near future under our existing contracts.

Operations

General

As of December 31, 2011, Memorial Resource operates 65% of the wells and properties containing our proved reserves on our behalf and also is the operator of substantially all of the other wells and properties containing our proved reserves. We design and manage the development, recompletion and/or workover operations, and supervise other operation and maintenance activities, for all of the wells we operate. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on our properties. Independent contractors provide all the equipment and personnel associated with these activities. Pursuant to our omnibus agreement, Memorial Resource provides management, administrative and operating services to our general partner and us to manage and operate our business and assets. See “Item 13. Certain Relationships and Related Transactions, and Director Independence —Omnibus Agreement” for more information about the omnibus agreement.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our properties range from 0% to 59%, or 19% on average, resulting in a net revenue interest to us ranging from 41% to 100%. As of December 31, 2011, most of our leases are held by production and do not require lease rental payments.

Marketing and Major Customers

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


	Years Ending December 31,
	2011			2010			2009
Major customers: (1)
Enterprise Texas Pipeline, LLC		20	%		31	%		32	%
Dominion Gas Ventures, LP		15	%		25	%		43	%
ConocoPhillips		13	%		11	%		(2	)

(1)	Collectively, these major customers purchased production pursuant to existing marketing agreements with terms that are currently on “evergreen” status and renew on a month-to-month basis until either party gives 30-day advance written notice of non-renewal.

(2)	This customer accounted for less than 10% of total revenue for the period indicated.

The production sales agreements covering our properties contain customary terms and conditions for the oil and natural gas industry and provide for sales based on prevailing market prices. A majority of those agreements have terms that renew on a month-to-month basis until either party gives advance written notice of non-renewal.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of a portion of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether, the loss of any such customer could have a detrimental effect on our production volumes in general and on our ability to find substitute customers to purchase our production volumes.

Title to Properties

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews, or obtain indemnification with respect to title, on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our own expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report.

Derivatives Activities

We enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. Our outstanding commodity derivative contracts currently consist of floating-for-fixed swaps, collars, put options, and basis swaps.

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those in our revolving credit facility) to fixed interest rates. 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 under our revolving credit facility. We will continue to evaluate the benefit of employing derivatives in the future. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information.

Competition

We operate in a highly competitive environment for acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry.

Seasonal Nature of Business

The price we receive for our natural gas production is impacted by seasonal fluctuations in demand for natural gas. The demand for natural gas typically peaks during the coldest months and tapers off during the warmest months, with a slight increase during the summer to meet the demands of electric generators. The weather during any particular season can affect this cyclical demand for natural gas. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation.

Hydraulic Fracturing

Hydraulic fracturing has been a part of the completion process for substantially all wells on our producing properties, and substantially all of our properties are economically dependent on our ability to hydraulically fracture the producing formations. We are currently conducting hydraulic fracturing activity in our South Texas and East Texas holdings. As of December 31, 2011, all of our leasehold acreage is currently held by production from existing wells; therefore, fracturing is not currently required to maintain this acreage but it will be required in the future to economically develop the proved non-producing and proved undeveloped reserves associated with this acreage. We plan to utilize hydraulic fracturing operations on nearly all of our proved non-producing and proved undeveloped reserves, or 34% of our total estimated proved reserves as of December 31, 2011.

Almost all of our hydraulic fracturing operations are conducted on vertical wells, which comprise 90% of our proved non-producing and proved undeveloped drilling, recompletion or development opportunities. The fracture treatments on these wells are much smaller and utilize much less water than that typically used on most of the horizontal wells that are being drilled throughout the United States. For example, a typical hydraulic fracture stimulation on one of our horizontal drill wells is pumped in multiple stages, utilizing a total of 1.5 million gallons of non-potable water and 1.6 million pounds of sand or proppant. In comparison, a hydraulic fracture stimulation on one of our new vertical drill wells in South Texas would be pumped utilizing a total of 70,000 gallons of non-potable water and 150,000 pounds of sand or proppant. Hydraulic fracture stimulations for

the recompletions of our existing vertical wells would be pumped utilizing 30,000 and 200,000 gallons of non-potable water and 50,000 and 250,000 pounds of sand or proppant in our South Texas and East Texas properties, respectively.

We follow applicable industry standard practices and legal requirements for groundwater protection in our operating areas, subject to close supervision by state and federal regulators, which conduct inspections during operations that include hydraulic fracturing. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design essentially eliminates a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested to ensure mechanical well integrity prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the pressures.

Regulations applicable to our operating areas do not currently require, and we do not currently evaluate, the environmental impact of typical additives used in fracturing fluid; however, approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand.

We attempt to minimize the use of water in our hydraulic fracturing operations and dispose of it in a way that minimizes the impact to nearby surface and ground water by disposing excess water and water that is produced back from the wells into approved disposal or injection wells. We currently do not discharge water to the surface and we intend to investigate the possibility of utilizing water that is produced from wells for use in hydraulic fracturing. For a discussion of risks associated with hydraulic fracturing and related environmental matters, please read “Item 1A. Risk Factors — Risks Related to Our Business — Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and adversely affect our production” and “Item 1A. Risk Factors — Risks Related to Our Business — Recently proposed rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.”

Insurance

In accordance with customary industry practice, we maintain insurance against many potential operational risks and losses that would be covered by the following policies:

•

Commercial General Liability;

•

Primary Umbrella / Excess Liability;

•

Workers’ Compensation and Employer’s Liability;

•

Control of Well; and

•

Automobile Liability.

We maintain insurance coverage against potential losses that we believe is customary in the industry. As of December 31, 2011, we maintain commercial general liability insurance and umbrella / excess liability insurance with limits of $1 million and $25 million per occurrence, respectively, and $2 million and $25 million in the aggregate, respectively. There is no deductible for our commercial general liability insurance or our umbrella / excess liability insurance. Our general liability insurance covers us for, among other things, legal and contractual liabilities arising out of third party property damage and bodily injury, for sudden or accidental pollution liability. Our umbrella / excess liability insurance is in addition to our general liability policy and triggered if the general liability insurance policy limits are exceeded. In addition, we maintain control of well insurance with per

occurrence limits ranging from $10 million to $20 million and retentions ranging from $100,000 to $250,000. Our control of well policy insures us for blowout risks associated with drilling, completing and operating our wells, including above ground pollution. In addition, we maintain auto liability insurance with limits of $1 million per occurrence. There is no deductible for auto liability insurance.

As of December 31, 2011, we do not have any insurance policies in effect that are intended to provide coverage for losses solely related to our hydraulic fracturing operations. However, we believe our general liability and excess liability insurance policies would cover third-party claims for property damage and bodily injury related to our hydraulic fracturing operations in accordance with, and subject to, the terms of such policies. These policies may not cover fines, penalties or costs and expenses related to government-mandated clean-up of pollution. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We enter into master services agreements, or MSAs, with various fracturing service providers. These MSAs allocate potential liabilities and risks between the parties. Under certain MSAs, we indemnify the hydraulic fracturing service providers for pollution and contamination of any kind, damages to or losses from wells or underground formations and damages to property, including pipelines, storage or production facilities. Under other MSAs, the service providers indemnify us for pollution or contamination that originates above the surface and is caused by the service provider’s equipment or services, unless such pollution or contamination is caused by our gross negligence or willful misconduct, and we indemnify the service providers for all other pollution or contamination that may occur during operations (including that which may result from seepage or any other uncontrolled flow of oil, natural gas or other fluids from the well), unless such pollution or contamination is caused by the service provider’s gross negligence or willful misconduct. Generally, we also agree to indemnify the service providers against claims arising from our employees’ personal injury or death to the extent that our employees are injured by such hydraulic fracturing operations, unless resulting from the service provider’s gross negligence or willful misconduct. Similarly, the service providers agree to indemnify us for liabilities arising from personal injury to or death of any of their employees, unless resulting from our gross negligence or willful misconduct. In addition, the service providers generally agree to indemnify us for loss or destruction of property or equipment that they own, unless resulting from our gross negligence or willful misconduct. In turn, we agree to indemnify the service providers for loss or destruction of property or equipment we own, unless resulting from the service provider’s gross negligence or willful misconduct.

Despite the general allocation of risk discussed above, we may not succeed in enforcing such contractual allocation of risk, we may be required to enter into a MSA with terms that vary from such allocation of risk and we may face risks that fall outside any contractual allocation of risk. As a result, we may incur substantial losses that could materially and adversely affect our financial position, results of operations and cash flows.

Environmental Matters and Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and (v) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability and cash available for distributions. Additionally, the Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on any such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we may incur significant costs and liabilities as a result of any such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that this trend will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In particular, some of the materials used in hydraulic fracturing, as well as its byproducts, could be classified as hazardous wastes. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws impose joint and several and strict liability, without regard to fault or legality of the original conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of the site where the release occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA and comparable state statutes, such persons deemed “responsible parties” may be subject to joint and several and strict liability for removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless

handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

The Oil Pollution Act of 1990, or OPA, is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including the costs of responding to a release of oil to surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities of $350 million. These liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA, OPA and analogous state and local laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act (also known as the Clean Water Act), the State Drinking Water Act, or the SDWA, the OPA and analogous state laws, impose restrictions and strict controls with respect to the unauthorized discharge of pollutants, including oil and hazardous substances, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential to delay the development of natural gas and oil projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain

approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

We routinely apply hydraulic fracturing techniques in many of our oil and natural gas drilling and completion programs. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate oil and natural gas production. Due to public concerns raised regarding the potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Congress continues to consider legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources. The EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal SDWA’s Underground Injection Control (“UIC”) Program by posting a new requirement on its website that requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. Although the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decisions as a “final agency action” and, thus, violative of the notice-and-comment rulemaking procedures of the Administrative Procedures Act. At the same time, the EPA has commenced a multi-year study of the potential environmental impacts of hydraulic fracturing activities, the results of which are anticipated to be available by late 2012. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, including states in which we operate. For example, Texas passed a law in June 2011 requiring its Railroad Commission, or RRC, to establish a disclosure process for hydraulic fracturing fluids. Effective February 1, 2012, the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. In addition, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. Finally, on October 20, 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of wastewater into federal or state waters. Thus, “flowback” and “produced water” must either be injected into permitted disposal wells or transported to public or private treatment facilities for treatment. The EPA asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to properly treat the wastewater before introducing it into public waters. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it to treatment facilities. Proposed rules are expected in 2013 for coalbed methane and 2014 for shale gas. We cannot predict the impact that these standards may have on our business at this time, but these standards could have a material impact on our business, financial condition and results of operations.

Adoption of these or any new laws or regulations placing significant restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Air Emissions

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. In particular, on August 23, 2011, pursuant to a court-ordered consent decree, the EPA published a proposed rule establishing new emissions standards to reduce VOC and sulfur dioxide emissions from several types of processes and equipment used in the oil and gas industry, including a 95 percent reduction in VOCs emitted during construction or modification of hydraulically fractured wells. The consent decree requires the EPA to take final action by April 3, 2012, following a public comment period, which has been completed. These proposed standards, should they be adopted, as well as any future laws and regulations implementing those laws may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of oil and natural gas projects. These laws and regulations also may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Although we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe that such requirements will have a material adverse effect on our operations.

Climate Change

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHGs”) present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which was finalized in April 2010 and became effective in January 2011, purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016; however, it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation’s National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although it remains the subject of several pending lawsuits filed by industry groups. The tailoring rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the tailoring rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the tailoring rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the tailoring rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Finally, in October 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such

facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The EPA also plans to implement GHG emissions standards for power plants in May 2012 and for refineries in November 2012.

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security (ACES) Act that, among other things, would have established a cap-and-trade system to regulate greenhouse gas emissions and would have required an 80% reduction in GHG emissions from sources within the United States between 2012 and 2050. The ACES Act did not pass the Senate, however, and so was not enacted by the 111th Congress. The United States Congress is likely to consider again a climate change bill in the future. In addition, one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur in areas where we operate, they could have an adverse effect on our assets and operations.

National Environmental Policy Act

Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, we have minimal exploration and production activities on federal lands. However, for those current activities as well as for future or proposed exploration and development plans on federal lands governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay the development of oil and natural gas projects.

Endangered Species Act

Environmental laws such as the Endangered Species Act or ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and prohibits taking of endangered species. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. Although some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

OSHA

We are subject to the requirements of the federal Occupational Safety and Health Act or OSHA, and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that we organize and/or disclose information about

hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and the development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, we do not believe that compliance with these laws will have a material adverse impact on us.

Drilling and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

•

the location of wells;

•

the method of drilling and casing wells;

•

the surface use and restoration of properties upon which wells are drilled;

•

the plugging and abandoning of wells; and

•

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of our properties. Sales of condensate and NGLs are not currently regulated and are made at market prices.

State Regulation

The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, the baseline Texas severance tax on oil and gas is 4.6% of the market value of oil produced and 7.5% of the market value of gas produced and saved. A number of exemptions from or reductions of the severance tax on oil and gas production is provided by the State of Texas which effectively lowers the cost of production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

The directors and officers of our general partner manage our operations and activities. However, neither we, nor our subsidiaries, nor our general partner have employees. 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. See “Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement.”

As of December 31, 2011, Memorial Resource had 155 employees. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that Memorial Resource’s relations with its employees are satisfactory. Our general partner also contracts on our behalf for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed.

Offices

Our principal executive office is located at 1301 McKinney Street, Suite 2100, Houston, Texas 77010. Our main telephone number is (713) 588-8300.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our website at www.memorialpp.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the United States Securities and Exchange Commission (“SEC”). These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. Our website also includes our Code of Business Conduct and Ethics and the charter of our audit committee. No information from either the SEC’s website or our website is incorporated herein by reference.

ITEM 1A.

RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a business similar to ours. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment. Other risks are also described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Risks Related to Our Business

We may not have sufficient cash to pay the minimum quarterly distribution on our common units, following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.

We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $0.4750 per unit or any other amount. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders.

The amount of cash we distribute on our units principally depends on the cash we generate from operations, which depends on, among other things:

•

the amount of oil, natural gas and NGLs we produce;

•

the prices at which we sell our oil, natural gas and NGL production;

•

the amount and timing of settlements of our commodity derivatives;

•

the level of our operating costs, including maintenance capital expenditures and payments to our general partner and its affiliates; and

•

the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.

For a description of additional restrictions and factors that may affect our ability to make cash distributions to our unitholders, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

We will be unable to sustain our minimum quarterly distribution without substantial capital expenditures that maintain our asset base. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow and ability to make distributions are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.

Our acquisition and development operations require substantial capital expenditures.

The development and production of our oil and natural gas reserves requires substantial capital expenditures, which will reduce the amount of cash available for distribution to our unitholders. Further, if the borrowing base under our revolving credit facility decreases, or our revenues decrease, as a result of lower oil or natural gas prices or for any other reason, we may not be able to obtain the capital necessary to sustain our operations at the expected levels necessary to generate cash sufficient to make distributions to our unitholders.

A decline in, or sustained low levels of, oil or natural gas prices will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.

Lower oil and natural gas prices may decrease our revenues and thus cash available for distribution to our unitholders. Historically, oil and natural gas prices have been extremely volatile. For example, for the five years ended December 31, 2011, the NYMEX-WTI oil future price ranged from a high of $145.29 per Bbl to a low of $33.87 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $13.58 per MMBtu to a low of $2.51 per MMBtu. From January 1, 2011 to December 31, 2011, the NYMEX-WTI oil future price ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $4.85 per MMBtu to a low of $2.98 per MMBtu. A significant decrease in commodity prices may cause us to reduce the distributions we pay to our unitholders or to cease paying distributions.

Domestic natural gas prices have recently been at relatively historic low levels, due to an oversupply of natural gas in the United States. If natural gas prices remain at these low levels for a sustained period, our cash flow and revenues will be affected, and we may not be able to continue paying distributions to our unitholders.

If commodity prices decline and remain depressed for a prolonged period, a significant portion of our development projects may become uneconomic and cause write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.

Significantly lower oil prices, or sustained lower natural gas prices, would render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would reduce our borrowing base and our ability to pay distributions or fund our operations.

Further, deteriorating commodity prices may cause us to recognize impairments in the value of our oil and natural gas properties. In addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken, our ability to borrow funds under our revolving credit facility and our ability to pay distributions to our unitholders.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could significantly reduce our cash available for distribution and adversely affect our financial condition.

The prices that we receive for our oil and natural gas production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. These discounts, if significant, could reduce our cash available for distribution to our unitholders and adversely affect our financial condition.

Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.

The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices and price expectations at the time we enter into these

transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets or other unforeseen events could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract and, accordingly, prevent us from realizing the benefit of the derivative contract.

Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering is complex, requiring subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. For example, if the prices used in our reserve reports had been $10.00 less per barrel for oil and $1.00 less per MMBtu for natural gas, then the standardized measure of our estimated proved reserves as of December 31, 2011, excluding the effects of our commodity derivative contracts, would have decreased by $126.8 million, from $378.3 million to $251.5 million.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

The present value of future net cash flows from our proved reserves shown in this report, or standardized measure, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (“FASB”), we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements, which is required by the FASB, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from

productive wells that do not produce sufficient revenues to be commercially viable. Any of our development and production operations may incur unscheduled costs or otherwise be curtailed, delayed or canceled as a result of other factors, including:

•

high costs, shortages or delivery delays of rigs, equipment, labor or other services;

•

composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;

•

unexpected operational events and conditions;

•

failure of down hole equipment and tubulars;

•

loss of wellbore mechanical integrity;

•

hydrocarbon or oilfield chemical spills;

•

adverse weather conditions and natural disasters;

•

facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour natural gas;

•

loss of drilling fluid circulation;

•

fires, blowouts, surface craterings and explosions; and

•

surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and cash available for distribution to our unitholders.

Many of our properties are in areas that may have been partially depleted or drained by offset wells.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.

Our expectations for future development activities are planned to be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. Our ability to drill, recomplete and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, and drilling results. Because of these uncertainties, we cannot be certain of the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition and results of operations, and as a result, our ability to make cash distributions to our unitholders.

Shortages of rigs, equipment and crews could delay our operations, increase our costs and delay forecasted revenue.

Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict Memorial Resource’s ability to drill the wells and conduct the operations that it currently has planned relating to the fields where our properties are located. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and reduce our cash available for distribution to our unitholders.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:

•

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;

•

unable to obtain financing for such acquisitions on economically acceptable terms; or

•

outbid by competitors.

If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.

Any acquisitions we complete will be subject to substantial risks.

One of our growth strategies is to acquire additional oil and natural gas reserves from time to time. Even if we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:

•

the validity of our assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs;

•

an inability to successfully integrate the assets or businesses we acquire;

•

a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

•

a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

•

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

•

the diversion of management’s attention from other business concerns;

•

mistaken assumptions about the overall cost of equity or debt;

•

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

•

the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations. Our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

Adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

Our properties are located in South and East Texas. An adverse development in the oil and natural gas business of these geographic areas, such as in our ability to attract and retain field personnel, could have an impact on our results of operations and cash available for distribution to our unitholders.

We are dependent upon a small number of significant customers for a substantial portion of our production sales and we may experience a temporary decline in revenues and production if we lose any of those customers.

We had three individual customers that each accounted for 10% or more of total reported revenues for the year ended December 31, 2011. To the extent any of these significant customers reduce the volume they purchase from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our production, and our revenues and cash available for distribution could decline, which could adversely affect our ability to make cash distributions to our unitholders at the then-current distribution rate or at all. See “Item 1. Business — Marketing and Major Customers.”

Additionally, a failure by any of these significant customers, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.

We may experience a financial loss if Memorial Resource is unable to sell, or receive payment for, a significant portion of our oil and natural gas production.

Under our omnibus agreement, Memorial Resource handles sales of our natural gas, oil and NGL production on our behalf, which depends upon the demand for natural gas, oil and NGLs from potential purchasers of our production. In recent years, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our production. This reduction in potential customers has reduced overall market liquidity. If any one or more of our significant customers reduces the volume of oil and natural gas production it purchases and other customers to sell those volumes to are unable to be found, then the volume of our production sold on our behalf could be reduced, and we could experience a material decline in cash available for distribution.

In addition, a failure by any of these companies, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our results of operation. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be

an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.

We may be unable to compete effectively with larger companies.

The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions to our unitholders.

We may incur additional debt to enable us to pay our quarterly distributions.

We may be unable to pay the minimum quarterly distribution or the then-current distribution rate without borrowing under our revolving credit facility or otherwise. If we use borrowings to pay distributions to our unitholders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness incurred to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution to our unitholders to avoid excessive leverage.

Our revolving credit facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

The operating and financial restrictions and covenants in our credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit facility that are not cured or waived within the appropriate time periods provided in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

Our revolving credit facility allows us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base at that time and, in such case, we could be required to repay any indebtedness outstanding in excess of the borrowing base. If we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

Our business depends in part on pipelines, gathering systems and processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business.

The operation of our properties is largely dependent on the ability of Memorial Resource’s employees.

The continuing production from our properties, and to some extent the marketing of our production, is dependent upon the ability of the operators of our properties. Memorial Resource operates substantially all of our properties, either directly as operator or, where we are the operator of record, on our behalf under the omnibus agreement. As of December 31, 2011, based on proved reserve volumes, Memorial Resource operated on our behalf 65%, Memorial Resource operated 29% and third parties operated 6% of the wells and properties in which we have interests. The success and timing of drilling and development activities on such properties, depend upon a number of factors, including:

•

the nature and timing of drilling and operational activities;

•

the timing and amount of capital expenditures;

•

Memorial Resource’s or the operators’ expertise and financial resources;

•

the approval of other participants in such properties; and

•

the selection and application of suitable technology.

If Memorial Resource or the applicable third party operator is unable to conduct drilling and development activities on our properties on a timely basis, we may be unable to increase our production or offset normal production declines, or we will be required to write off the estimated proved reserves attributable thereto, any of which may adversely affect our production, revenues and results of operations and our cash available for distribution. Any such write-offs of our reserves could reduce our ability to borrow money and could adversely impact our ability to pay distributions on the common units.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, and results of operations.

Our oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. See “Item 1. Business — Environmental Matters and Regulation” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” or GHGs, including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of GHGs. One bill approved by the U.S. House of Representatives in June 2009, known as the American Clean Energy and Security Act of 2009, would have required an 80% reduction in emissions of GHGs from sources within the U.S. between 2012 and 2050 but was not approved by

the U.S. Senate in the 2009-2010 legislative session. The U.S. Congress is likely to continue to consider similar bills. Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs, through the planned development of GHG emission inventories and/or regional GHG cap and trade programs or other mechanisms. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

In addition, in December 2009, the U.S. Environmental Protection Agency (the “EPA”) determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which was finalized in April 2010 and became effective in January 2011, purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016; however, it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation’s National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although it remains the subject of several pending lawsuits filed by industry groups. The tailoring rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the tailoring rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the tailoring rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the tailoring rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Finally, in October 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The EPA also plans to implement GHG emissions standards for power plants in May 2012 and for refineries in November 2012.

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. See “Item 1. Business — Environmental Matters and Regulation” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. See “Item 1. Business — Environmental Matters and Regulation” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”) provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, or CFTC, adopt rules or regulations implementing the Act and providing definitions of terms used in the Act. The Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities. The CFTC has proposed a large number of rules to implement the Act in multiple rulemaking proceedings and has finalized a number of such rules, including a rule imposing position limits (the “Position Limit Rule”). However, many of the regulations necessary to implement the Act and define terms used in the Act have not been adopted. As a result, we do not yet know if we will be required to comply with margin requirements and clearing and trade-execution requirements imposed by the Act or if certain of our counterparties will be required to spin off some of our derivatives contracts to separate entities, which may not be as credit-worthy as our current counterparties. In addition, the International Swaps and Derivatives Association, Inc. and the Securities Industry and Financial Markets Association, two industry associations, have filed a suit in federal court in the District of Columbia against the CFTC challenging the Position Limit Rule. The Act and, to the extent that such challenge to the Position Limit Rule is unsuccessful, the Position Limit Rule, and any other new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and adversely affect our production.

We routinely apply hydraulic fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. The process is typically regulated by state oil and natural gas commissions; however, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress,

called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

Texas adopted a law in June 2011 requiring disclosure to the RRC and the public of certain information regarding the components, as well as the volume of water, used in the hydraulic fracturing process. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism.

Furthermore, on August 23, 2011, the EPA published a proposed rule in the Federal Register to establish new emissions standards to reduce volatile organic compounds (“VOC”) emissions from several types of processes and equipment used in the oil and gas industry, including a 95 percent reduction in VOCs emitted during the construction or modification of hydraulically-fractured wells.

Finally, on October 20, 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of wastewater into federal or state waters. Thus “flowback” and “produced water” must either be injected into permitted disposal wells or transported to public or private treatment facilities for treatment. The EPA asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to properly treat the wastewater before introducing it into public waters. If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial

production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Recently proposed rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.

On August 23, 2011, the EPA published a proposed rule in the Federal Register that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal requires the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rule also establishes specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rule establishes new leak detection requirements for natural gas processing plants. The EPA completed its public comment and public hearing period and must take final action on them by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Also, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and the implied distribution yield. The distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue additional equity or incur debt, and the cost to us of any such issuance or incurrence.

Expenses not covered by our insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We maintain insurance coverage against potential losses that we believe is customary in the industry. However, these policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Risks Inherent in an Investment in Us

Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.

Our general partner has control over all decisions related to our operations. As of March 16, 2012, Memorial Resource owns an approximate aggregate 42% of our outstanding common units and all of our subordinated

units, and 100% of the voting membership interests in our general partner are owned by Memorial Resource. The Funds, in turn, collectively own 100% of Memorial Resource. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner are directors and/or officers of affiliates of our general partner (including Memorial Resource, the Funds and NGP), and certain of our general partner’s executive officers and directors will continue to have economic interests, investments and other economic incentives in the Funds and other NGP-affiliated entities. Conflicts of interest may arise in the future between our general partner and its affiliates (including Memorial Resource, the Funds and NGP), on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. These potential conflicts include, among others, the following situations:

•

neither our partnership agreement nor any other agreement requires Memorial Resource, the Funds or NGP to pursue a business strategy that favors us. The directors and officers of Memorial Resource, the Funds and their respective affiliates (including NGP) have a fiduciary duty to make decisions in the best interests of their respective equity holders, which may be contrary to our interests;

•

our general partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

•

Memorial Resource, the Funds and their affiliates (including NGP) are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer assets to us;

•

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

•

many of the officers and directors of our general partner who provide services to us devote time to affiliates of our general partner, including Memorial Resource, the Funds, and/or NGP, and may be compensated for services rendered to such affiliates;

•

our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without such limitations, reductions, and restrictions, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

•

our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

•

our general partner determines whether a cash expenditure is classified as a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus in any given period and the ability of the subordinated units to convert into common units;

•

we and our general partner have entered into an omnibus agreement with Memorial Resource, pursuant to which among other things, Memorial Resource operates our assets and performs other management, administrative, and operating services for us and our general partner;

•

our general partner is entitled to determine which costs, including allocated overhead, incurred by it and its affiliates, including Memorial Resource, are reimbursable by us, which will include salary,

bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates;

•

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

•

our partnership agreement permits us to classify up to $30.5 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

•

our general partner decides whether to retain separate counsel, accountants, or others to perform services for us;

•

our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations;

•

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

•

our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

•

our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and

•

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including Memorial Resource, the Funds and NGP.

See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Memorial Resource, the Funds and other affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

Our partnership agreement provides that Memorial Resource and the Funds and their respective affiliates (including NGP and its affiliates’ portfolio investments) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Memorial Resource and the Funds and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

NGP and the Funds are established participants in the oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Neither we nor our general partner have any employees and we rely solely on the employees of Memorial Resource to manage our business. The management team of Memorial Resource, which includes the individuals who manage us, also perform substantially similar services for Memorial Resource and its assets, and thus is not solely focused on our business.

Neither we nor our general partner have any employees and we rely solely on Memorial Resource to operate our assets. We and our general partner have entered into an omnibus agreement with Memorial Resource,

pursuant to which, among other things, Memorial Resource agreed to operate our assets and perform other management, administrative, and operating services for us and our general partner.

Memorial Resource provides substantially similar activities with respect to its own assets and operations. Because Memorial Resource provides services to us that are substantially similar to those performed for itself, Memorial Resource may not have sufficient human, technical and other resources to provide those services at a level that Memorial Resource would be able to provide to us if it were solely focused on our business and operations. Memorial Resource may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Memorial Resource’s interests. There is no requirement that Memorial Resource favor us over itself in providing its services. If the employees of Memorial Resource and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

Many of the directors and all of the officers who have responsibility for our management have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

To maintain and increase our levels of production, we will need to acquire oil and gas properties. All of the officers of our general partner hold similar positions with Memorial Resource, and many of the directors of our general partner, who are responsible for managing our general partner’s direction of our operations and acquisition activities, hold positions of responsibility with other entities (including NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, the Funds and their affiliates (including NGP) are in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties, and Memorial Resource is in the business of acquiring and developing oil and natural gas properties. Mr. Hersh, a director of our general partner, is the Chief Executive Officer of NGP Energy Capital Management and a managing partner of NGP; Mr. Gieselman, a director of our general partner, is a managing director of NGP; Mr. Weber, a director of our general partner, is a managing director of NGP and serves as Chief Investment Coordinator for NGP; and Mr. Weinzierl, the President, Chief Executive Officer and Chairman of the board of directors of our general partner, was a managing director and operating partner of NGP before our initial public offering and is now a venture partner with NGP and continues to hold ownership interests in the Funds and certain of their affiliates. Officers of our general partner will continue to devote significant time to the business of Memorial Resource. We cannot assure you that any conflicts that may arise between us and our unitholders, on the one hand, and Memorial Resource or the Funds, on the other hand, will be resolved in our favor. The existing positions held by these directors and officers may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these

existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, see “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Cost reimbursements due to Memorial Resource and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders.

Our partnership agreement requires us to reimburse our general partner and its affiliates for all actual direct and indirect expenses they incur or actual payments they make on our behalf and all other expenses allocable to us or otherwise incurred by our general partner or its affiliates in connection with operating our business, including overhead allocated to our general partner by its affiliates, including Memorial Resource. These expenses include salary, bonus, incentive compensation (including equity compensation) and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all such expenses. None of these reimbursements are capped. The reimbursements to Memorial Resource and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.

We have entered into agreements with Memorial Resource and our general partner pursuant to which, among other things, we will make payments to Memorial Resource. These payments will be substantial and will reduce the amount of cash available for distribution to unitholders. These agreements include the following:

•

an omnibus agreement pursuant to which, among other things, Memorial Resource provides management, administrative and operating services for us and our general partner; and

•

a 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). It is possible that Memorial Resource or its applicable affiliate(s) may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. In such a situation, we would pay Memorial Resource or its applicable affiliate(s) the tax we would have owed had the tax attributes not been available or used for our benefit, even though Memorial Resource or its applicable affiliate(s) had no cash tax expense for that period. Currently, the Texas margin tax (which has a maximum effective tax rate of 0.7% of federal gross income apportioned to Texas) is the only tax that is included in a combined or consolidated tax return with Memorial Resource or its applicable affiliate(s).

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following any reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash contribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as

the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right (if at all) to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.

Our unitholders who fail to furnish certain information requested by our general partner or who our general partner determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.

We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner. Our general partner may require any limited partner or transferee to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units and subordinated units of any holder that is not an eligible citizen or fails to furnish the requested information.

Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Memorial Resource, as owner of our general partner, has the power to appoint and remove our general partner’s directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.

Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is appointed by Memorial Resource. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner has control over all decisions related to our operations. Since Memorial Resource owns our general partner, approximately 42% of our outstanding common units, and all of our subordinated units, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by Memorial Resource and its affiliates) after the subordination period has ended. Assuming we do not issue any additional common units and Memorial Resource does not transfer its common units, Memorial Resource has the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Furthermore, the goals and objectives of Memorial Resource and its affiliates that hold our common units relating to us may not be consistent with those of a majority of the other unitholders. Please read “— Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.”

Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are those capital expenditures required to maintain our long-term asset base, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

•

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or

factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to our partnership agreement;

•

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith and with the honest belief that the decision was in our best interest;

•

generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be (i) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (ii) must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

•

provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•

provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder will become bound by the provisions in our partnership agreement, including the provisions discussed above.

Even if our unitholders are dissatisfied, they cannot remove our general partner without Memorial Resource’s consent.

The public unitholders will be unable initially to remove our general partner without Memorial Resource’s consent because Memorial Resource owns sufficient units to be able to prevent our general partner’s removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. As of March 16, 2012, Memorial Resource owns our general partner, approximately 42% of our outstanding common units, and all of our subordinated units, which together constitutes approximately 56% of all outstanding units.

Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Memorial Resource from transferring all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.

In addition, our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third

party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

We may not make cash distributions during periods when we record net income.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

•

our unitholders’ proportionate ownership interest in us will decrease;

•

the amount of cash available for distribution on each unit may decrease;

•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

•

the ratio of taxable income to distributions may increase;

•

the relative voting strength of each previously outstanding unit may be diminished; and

•

the market price of our common units may decline.

Our partnership agreement restricts the limited voting rights of unitholders, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding (other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner) cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their

common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. As of March 16, 2012, Memorial Resource owns approximately 42% of our outstanding common units and all of our subordinated units.

If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in our partnership agreement, and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 99.9% to our unitholders and 0.1% to our general partner, and will result in a decrease in our minimum quarterly distribution.

Our partnership agreement allows us to add to operating surplus $30.5 million. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:

•

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•

a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Our unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our revolving credit facility may restrict our ability to make distributions.

Our partnership agreement allows us to borrow to make distributions. We may make short-term borrowings under our revolving credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short-term fluctuation in our working capital that would otherwise cause volatility in our quarter-to-quarter distributions.

The terms of our revolving credit facility restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.

Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

•

general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

•

conditions in the oil and natural gas industry;

•

the market price of, and demand for, our common units;

•

our results of operations and financial condition; and

•

prices for oil, NGLs and natural gas.

NASDAQ does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on NASDAQ. Because we are a publicly traded limited partnership, NASDAQ does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of NASDAQ corporate governance requirements.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based on our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas margin tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, the Obama Administration and members of Congress have recently considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the target distribution levels may be adjusted to reflect the impact of that law on us.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

Both President Obama’s Proposed Fiscal Year 2013 Budget and proposed legislation in Congress would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

If the IRS contests any of the federal income tax positions we take, the market for our units may be adversely affected, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our units could be more or less than expected.

If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Because distributions in excess of their allocable share of our total net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and IDC recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units.

We will treat each purchaser of units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depreciation, depletion and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.

We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered to have disposed of those units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as

described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred.

As a result of investing in our units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in Texas and Louisiana. Louisiana currently imposes a personal income tax on individuals. These states also impose an income or franchise tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all U.S. federal, state and local tax returns.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

Information regarding our properties is contained in Item 1. Business “—Our Areas of Operation” and “—Our Oil and Natural Gas Data” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” contained herein.

ITEM 3.

LEGAL PROCEEDINGS

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. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows. No amounts have been accrued at December 31, 2011.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common units are listed and traded on the NASDAQ under the symbol “MEMP.” As of the close of business on March 15, 2012, based upon information received from our transfer agent and brokers and nominees, we had 11 common unitholders of record. This number does not include owners for whom common units may be held in “street” names. The daily high and low sale prices per common unit for the period from December 9, 2011 (the initial listing date of the units) through December 31, 2011 were $19.09 to $17.51.

We have also issued 5,360,912 subordinated units, for which there is no established public trading market. All of the subordinated units are held by Memorial Resource.

Cash Distributions to Unitholders

On January 26, 2012, the board of directors of our general partner declared a quarterly cash distribution for the fourth quarter of 2011 of $0.0929 per unit. This represents a prorated amount that, on an equivalent full-quarter basis, corresponds to our minimum quarterly cash distribution of $0.4750 per unit. The proration period was from the closing date of our IPO, December 14, 2011, through December 31, 2011. The distribution was paid February 13, 2012 to all unitholders of record at 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 “Item 11 — Executive Compensation—Compensation Discussion and Analysis—Elements of Executive Compensation” for additional information concerning the grant of restricted common units.

We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our revolving credit facility, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our revolving credit facility after giving effect to such distribution.

Cash Distribution Policy

Available Cash

Our partnership agreement requires that within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we distribute all of our available cash to unitholders of record on the applicable record date.

Available cash, generally means, for any quarter prior to liquidation, all cash on hand at the end of the quarter:

•

less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

•

provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

•

comply with applicable law, any of our debt instruments or other agreements;

•

provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters;

•

plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from borrowing made after the end of the quarter.

General Partner Interest and Incentive Distribution Rights

Our general partner is entitled to 0.1% of all distributions of available cash that we make prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner also holds the incentive distribution rights, which entitle the holder to additional increasing percentages, up to a maximum of 24.9% of the cash we distribute in excess of $0.59375 per common unit per quarter.

Minimum Quarterly Distribution

During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

•

second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

•

third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages in the table below.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:


	Total Quarterly Distributions Target Amount	Marginal Percentage Interest in Distributions
	Total Quarterly Distributions Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$0.4750		99.9	%		0.1	%
First Target Distribution	up to $0.54625		99.9	%		0.1	%
Second Target Distribution	above $0.54625 up to $0.59375		85.0	%		15.0	%
Thereafter	above $0.59375		75.0	%		25.0	%

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages in the table above.

The subordination period will extend until the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2014 that each of the following tests are met:

•

Distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions payable with respect to a period of twelve consecutive quarters immediately preceding such date;

•

The “adjusted operating surplus” (as defined in our partnership agreement) generated during the period of twelve consecutive quarters immediately preceding that date equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods payable with respect to such period on a fully diluted weighted average basis; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash.

In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

•

the subordination period will end and each subordinated unit will immediately convert into one common unit;

•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•

our general partner will have the right to convert its general partner units into common units or to receive cash in exchange for such general partner units at the equivalent common unit fair market value.

The subordination period will also automatically terminate, and all of the subordinated units will convert into an equal number of common units, on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, if the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded $0.59375 (125% of the minimum quarterly distribution) per quarter for the four quarter period immediately preceding that date;

•

the “adjusted operating surplus” generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.3750 (125% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units, in each case that were outstanding during such four quarter period on a fully diluted weighted average basis, and the corresponding distributions on the incentive distribution rights; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Unregistered Sales of Equity Securities

In connection with our formation on April 27, 2011, we issued (i) a 0.1% general partner interest in us to our general partner for $1 and (ii) a 99.9% limited partner interest in us to Memorial Resource for $999, in each case in an offering exempt from registration under Section 4(2) of the Securities Act.

On December 14, 2011, in connection with our IPO, we issued 7,061,294 common units, 5,360,912 subordinated units, 21,444 general partner units and all of our incentive distribution rights to Memorial Resource and our general partner, as partial consideration for the properties contributed to us, in an offering exempt from registration under Section 4(2) of the Securities Act.

Use of Proceeds from Sale of Registered Securities

On December 14, 2011, we completed our IPO of 9,000,000 common units at price of $19.00 per unit pursuant to a Registration Statement on Form S-1, as amended (File No. 333-175090). We received gross offering proceeds of approximately $171.0 million less approximately $24.5 million for underwriting discounts, structuring fees and other offering and formation-related fees. We used the net offering proceeds of approximately $146.5 million, together with borrowings of approximately $130.0 million under our revolving credit facility, as partial consideration for the contribution by Memorial Resource and its subsidiaries of certain oil and natural gas properties in South Texas and East Texas.

On December 22, 2011, the underwriters purchased an additional 600,000 common units from us at the initial public offering price pursuant to their over-allotment option. We received gross proceeds of approximately $11.4 million less approximately $0.7 million for underwriting discounts and commissions, a structuring fee and offering expenses. We used $10.0 million of the net proceeds to reduce outstanding borrowings under our revolving credit facility.

Issuer Purchases of Equity Securities

None.

ITEM 6.

SELECTED FINANCIAL DATA

The following selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.

Basis of Presentation. The selected financial data as of, and for the years ended, December 31, 2011, 2010, 2009, 2008 and 2007 have been derived from our consolidated financial statements subsequent to the closing of our IPO and our predecessor’s combined financial statements prior to the closing of our IPO. The selected financial data for the year ended December 31, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor for the period from January 1, 2011 to December 13, 2011, and the consolidated financial information of the Partnership for the period from December 14, 2011 to December 31, 2011. The selected financial data covering periods prior to the closing of our IPO may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods.


	For Year Ended December 31,
	2011			2010			2009			2008			2007
	($ in thousands, except per unit data)
													(Unaudited)
Statement of Operations Data:
Revenues:
Oil & natural gas sales	$	72,532		$	37,308		$	24,541		$	49,313		$	11,949
Other income		825			1,433			319			622			153

Total revenues		73,357			38,741			24,860			49,935			12,102

Costs and expenses:
Lease operating		22,507			13,974			11,207			8,843			2,873
Exploration		56			39			2,690			374			—
Production taxes		4,127			2,112			1,464			3,127			1,113
Depreciation, depletion, and amortization		24,341			20,066			15,226			12,353			18,144
Impairment of proved oil and natural gas properties		15,141			11,800			3,480			14,166			—
General and administrative		8,893			6,116			4,811			3,835			2,937
Accretion of assets retirement obligations		1,031			663			320			224			319
(Gain) loss on commodity derivative instruments		(31,050	)		(10,264	)		(10,834	)		(9,815	)		734
Gain on sale of properties		(63,024	)		(1	)		(7,851	)		(7,395	)		—
Other, net		1,613			890			304			—			744

Total costs and expenses		(16,365	)		45,395			20,817			25,712			26,864

Operating income (loss)		89,722			(6,654	)		4,043			24,223			(14,762	)
Interest expense		(7,268	)		(4,438	)		(2,937	)		(3,138	)		(1,135	)

Income (loss) before income taxes		82,454			(11,092	)		1,106			21,085			(15,897	)
Income tax expense		(122	)		(225	)		—			—			—

Net income (loss)		82,332			(11,317	)		1,106			21,085			(15,897	)
Net income (loss) attributable to predecessor		75,740			(11,317	)		1,106			21,085			(15,897	)

Net income attributable to partners	$	6,592		$	—		$	—		$	—		$	—

Allocation of net income attributable to partners:
Limited partners	$	6,585		$	—		$	—		$	—		$	—

General partner	$	7		$	—		$	—		$	—		$	—

Earnings per unit attributable to limited partners:
Basic and diluted earnings per unit	$	0.30		$	n/a		$	n/a		$	n/a		$	n/a

Cash distribution declared per unit	$	n/a		$	n/a		$	n/a		$	n/a		$	n/a

Cash Flow Data:
Net cash flow provided by operating activities	$	35,478		$	20,288		$	12,672		$	32,838		$	6,742
Net cash used in investing activities		158,505			116,687			24,947			45,547			97,416
Net cash provided by financing activities		118,641			96,756			15,989			11,619			93,196
Balance Sheet Data:
Working capital (deficit)	$	23,612		$	4,116		$	9,494		$	(966	)	$	(1,684	)
Total assets		441,894			248,540			146,153			145,529			99,021
Total debt		120,000			115,428			61,784			62,536			46,726
Total equity		303,168			105,801			72,988			54,576			36,488

ITEM 7.

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 financial statements and related notes “Item 8. Financial Statements and Supplementary Data” contained herein. 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. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I—Item 1A of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Forward-Looking Statements” in the front of this report.

Overview

We are a Delaware limited partnership formed in April 2011 by Memorial Resource to own and acquire oil and natural gas properties in North America.

Our oil and natural gas properties are located in South and East Texas. Based on proved reserves volumes at December 31, 2011, we or Memorial Resource operate 94% of the properties in which we have interests, and we own an average working interest of 48% across our oil and natural gas properties. As of December 31, 2011, we had interests in 1,274 gross (590 net) producing wells across our properties, with an average working interest of 46%. As of December 31, 2011, we had estimated proved reserves of 324 Bcfe, of which approximately 79% were classified as proved developed reserves including approximately 13% classified as proved developed non-producing, and a standardized measure of $378.3 million.

Our Initial Public Offering

On December 14, 2011, we completed our IPO of 9,000,000 common units at a price of $19.00 per unit, and on December 22, 2011, we completed the sale of an additional 600,000 common units at a price of $19.00 per unit pursuant to the exercise of the underwriters’ over-allotment option. In connection with the closing of our IPO, we acquired, for a combination of cash and newly-issued common units and subordinated units, (i) 100% of the membership interests of Columbus Energy, LLC, which owned substantially all of the oil and natural gas properties and related assets directly or indirectly owned by BlueStone Natural Resources Holdings, LLC, a majority-owned subsidiary of Memorial Resource, (ii) 100% of the membership interests of ETX I LLC, which owned a 40% undivided interest in certain oil and natural gas properties, and (iii) certain oil and natural gas properties, commodity derivative contracts and related assets owned by Classic Hydrocarbons Holdings, L.P., a majority-owned subsidiary of Memorial Resource.

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:

•

production volumes;

•

realized prices on the sale of oil and natural gas, including the effect of our derivative contracts;

•

lease operating expenses;

•

general and administrative expenses; and

•

Adjusted EBITDA (defined below).

Production Volumes

Production volumes directly impact our results of operations. For more information about our volumes, please read “— Results of Operations” below.

Realized Prices on the Sale of Oil and Natural Gas

We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas 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.

Natural Gas. The NYMEX-Henry Hub future price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO₂ and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to dry natural gas with low Btu content because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO₂ content sells at a premium to natural gas with high sulfur and CO₂ content because of the added cost required to separate the sulfur and CO₂ from the natural gas to render it marketable. Wet natural gas is processed in third-party natural gas plants, where residue natural gas as well as NGLs are recovered and sold. At the wellhead, our natural gas production typically has an average energy content greater than 1,000 Btu and minimal sulfur and CO₂ content and generally receives a premium valuation. The dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds. Generally, these index prices have historically been at a discount to NYMEX-Henry Hub natural gas prices.

Oil. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil’s American Petroleum Institute, or API, gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value, and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil (“sour” oil).

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

The oil produced from our properties is a combination of sweet and sour oil, varying by location. We sell our oil at the NYMEX-WTI price, which is adjusted for quality and transportation differential, depending primarily on location and purchaser. The differential varies, but our oil normally sells at a discount to the NYMEX-WTI price.

Price Volatility. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2011, the NYMEX-WTI oil future price ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $4.85 per MMBtu to a low of $2.98 per MMBtu. For the five years ended December 31, 2011, the NYMEX-WTI oil future price ranged from a high of $145.29 per Bbl to a low of $33.87 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $13.58 per MMBtu to a low of $2.51 per MMBtu.

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. Additionally, we intend to individually identify these non-speculative hedges as “designated hedges” for U.S. federal income tax purposes as we enter into them, resulting in ordinary income treatment of our realized hedge activity.

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. Expenses for utilities, direct labor, water injection and disposal, and materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and other taxes. 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. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed.

A majority of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production. Over the life of natural gas fields, the amount of water produced may increase for a given volume of natural gas production, and, as pressure declines in natural gas wells that also produce water, more power will be needed to provide energy to artificial lift systems that help to remove produced water from the wells. Thus, production of a given volume of natural gas gets more expensive each year as the cumulative natural gas produced from a field increases until, at some point, additional production becomes uneconomic. We believe that one of management’s areas of core expertise lies in reducing these expenses, thus extending the economic life of the field and improving the cash margin of producing natural gas.

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. We typically evaluate our oil and natural gas operating costs on a per Mcfe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.

Production Taxes. Texas regulates the development, production, gathering and sale of oil and natural gas, including imposing production taxes and requirements for obtaining drilling permits. For oil, Texas currently imposes a baseline production tax at 4.6% of the market value of the oil produced and 3/16 of one cent per Bbl produced, and for natural gas, Texas currently imposes a baseline production tax of 7.5% of the market value of the natural gas. However, a significant portion of the wells in Texas are either currently exempt from production tax due to high cost natural gas abatement or reduced rate for post production cost recoupment. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

General and 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 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. For a detailed description of the omnibus agreement, please read “Item 13. Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreement.”

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; 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.

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.

Calculation of Adjusted EBITDA


	For Year Ended December 31,
	2011			2010			2009
	($ in thousands)
Net income (loss)	$	82,332		$	(11,317	)	$	1,106
Interest expense		7,268			4,438			2,937
Income tax expense		122			225			—
DD&A		24,341			20,066			15,226
Impairment		15,141			11,800			3,480
Accretion of AROs		1,031			663			320
Unrealized (gains) losses on commodity derivative instruments		(23,239	)		(2,970	)		6,741
Acquisition related costs		1,045			890			304
Gain on sale of properties		(63,024	)		(1	)		(7,851	)
Exploration costs		56			39			2,690

Adjusted EBITDA	$	45,073		$	23,833		$	24,953

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA


	For Year Ended December 31,
	2011			2010			2009
	($ in thousands)
Net cash provided by operating activities	$	35,478		$	20,288		$	12,672
Changes in working capital		684			(742	)		8,840
Interest expense		7,268			4,438			2,937
Unrealized gain (loss) on interest rate swaps		(776	)		(296	)		309
Premiums paid for derivatives		2,847			—			—
Premiums received for derivatives		(1,008	)		—			—
Acquisition related costs		1,045			890			304
Amortization of deferred financing fees		(465	)		(745	)		(109	)

Adjusted EBITDA	$	45,073		$	23,833		$	24,953

Outlook

In 2012, our capital spending program is expected to be approximately $14 to $22 million excluding acquisitions. We anticipate spending approximately 53% in East Texas and 47% in South Texas primarily on infill drilling, recompletions and capital workovers based on the maximum range. We anticipate spending a majority of our capital budget in the first and second quarter of 2012 by participating in four non-operated horizontal Cotton Valley new drills in the Carthage Field in East Texas. In the second half of 2012, we anticipate spending the balance of our capital budget on one additional horizontal Cotton Valley new drill in East Texas, and recompletions and capital workovers, in both East Texas and South Texas. Without considering potential acquisitions, we expect our aggregate production in 2012 to be approximately 18-19 Bcfe.

Oil and NGL prices have steadily improved since the beginning of 2009, while gas prices have remained volatile and have generally trended lower since 2009. 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, and minimal economic demand growth in the United States. During 2009, 2010 and 2011, economic stimulus initiatives implemented in the United States and worldwide served to stabilize the United States and certain other economies in the world with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain European Union (or “Eurozone”) nations, continue to face economic struggles. The outlook for a continued worldwide economic recovery is cautiously optimistic, but remains uncertain; therefore, the sustainability of the recovery in worldwide demand for energy is difficult to predict. As a result, it is likely that commodity prices will continue to be volatile during 2012. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Significant factors that will impact 2012 commodity prices include: the ongoing impact of economic stimulus initiatives in the United States and worldwide and continuing economic struggles in Eurozone nations’ economies; presidential elections in both the United States and Eurozone; political and economic developments in North Africa and the Middle East in general; demand from Asian and European markets; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to manage oil supply through export quotas; and overall North American NGL and natural gas supply and demand fundamentals. 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.

Commodity hedging remains an important part of our strategy to reduce cash flow volatility. As of March 21, 2012, we have commodity derivative contracts for the years ending December 31, 2012, 2013, 2014, 2015 and 2016 covering approximately 83%, 78%, 68%, 67% and 67%, respectively, of our targeted average net production of natural gas, and we have total hedged volumes for the years ending December 31, 2012, 2013, 2014, 2015 and 2016, respectively, at NYMEX (Henry Hub) equivalent weighted-average hedge prices of $4.74, $4.63, $4.51, $4.50 and $4.67 per MMBtu. We have commodity derivative contracts for the years ending December 31, 2012, 2013, 2014, 2015 and 2016 covering approximately 85%, 77%, 76%, 76%, and 76% respectively, of our targeted average net production of crude oil, and have total hedged volumes for the years ending December 31, 2012, 2013, 2014, 2015, and 2016, respectively, at NYMEX (WTI) weighted-average hedge prices of $89.91, $88.89, $90.28, $91.36 and $91.34 per barrel. We also have commodity derivative contracts for the years ending December 31, 2012 and 2013 covering approximately 30% and 31% respectively, of our targeted average net production of NGLs, and have total hedged volumes for the years ending December 31, 2012 and 2013, respectively, at NYMEX weighted-average hedge prices of $72.22 and $73.11 per barrel.

In 2012, we plan to maintain our focus on adding reserves through acquisitions and development projects and improving the economics of producing oil and natural gas from our properties. We expect these acquisition

opportunities may come from Memorial Resource, the Funds, and their respective affiliates, as well as from unrelated third parties. 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.

Critical Accounting Policies and Estimates

Oil and Natural Gas Properties

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

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and natural gas reserves related to the associated field. The timing of any write downs of unproven properties, if warranted, depends upon the nature, timing, and extent of planned exploration and development activities and their results.

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

Proved Oil and Natural Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and predecessor combined financial statements are estimated in accordance with the rules established by the SEC and the FASB. In January 2010, the FASB updated its oil and gas estimation and disclosure requirements to align its requirements with the requirements of the modernized oil and gas reporting rules released by the SEC on December 31, 2008. These rules, which became effective during 2009, require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We intend to use NSAI to prepare a reserve report as of December 31 of each year and to prepare internal estimates of our proved reserves as of June 30 of each year.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and gas properties are depleted by field using the units-of-production method. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment. For example, if the SEC prices used for our December 31, 2011 reserve report had been $10.00 less per Bbl and $1.00 less per MMBtu, then the standardized measure of our estimated proved reserves as of December 31, 2011 would have decreased by approximately $126.8 million, from $378.3 million to $251.5 million.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production, drilling results, or lower commodity prices. The estimated future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Nonproducing oil and natural gas properties, which consist of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves, are assessed for impairment on a property-by-property basis. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management.

Asset Retirement Obligations

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

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2011 or 2010.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, floors, collars, and forward sales) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are

recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statements of operations. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. There were no derivatives designated as hedges for financial accounting purposes at December 31, 2011 or 2010.

Changes in the fair value of derivative financial instruments that do not qualify for accounting treatment as hedges are recognized currently in the statements of operations.

Results of Operations

The results of operations for the years ended December 31, 2011, 2010 and 2009 have been derived from our consolidated financial statements subsequent to the closing of our IPO and our predecessor’s combined financial statements prior to the closing of our IPO. The results of operations for the year ended December 31, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor for the period from January 1, 2011 to December 13, 2011 and the consolidated financial information of the Partnership for the period from December 14, 2011 to December 31, 2011. The results of operations covering periods prior to the closing of our IPO may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods.

Factors Affecting the Comparability of the Historical Financial Results 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. Our predecessor did not contribute all of its properties to us. The comparability of our predecessor’s results of operations among the periods presented is impacted by:

•

The following significant acquisitions by our predecessor:

•

Two separate acquisitions of assets in South Texas in March and May 2009, respectively, for a net purchase price of approximately $15.9 million.

•

The Forest Oil asset acquisition in June 2010 for approximately $65.9 million.

•

Two separate acquisitions of assets in East Texas in January and March 2010, respectively, for a net purchase price of approximately $14 million.

•

Two separate acquisitions of assets in South Texas in April and May 2010, respectively, for a total purchase price of approximately $23.2 million.

•

Oil and natural gas properties and related assets acquired from BP in May 2011, including the related disposition to BP of certain assets previously acquired from Forest Oil.

•

The acquisition of 40% of the oil and natural gas properties and related assets from a third party in April 2011.

•

The sale of certain non-core oil and natural gas properties located in South Texas in 2009 for $11.8 million.

As a result of the factors listed above, historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.


	For Year Ended December 31,
	2011			2010			2009
	(in thousands, except operating and per unit amounts)
Revenues:
Oil & natural gas sales	$	72,532		$	37,308		$	24,541
Other income		825			1,433			319

Total revenues	$	73,357		$	38,741		$	24,860

Costs and expenses:
Lease operating		22,507			13,974			11,207
Exploration		56			39			2,690
Production taxes		4,127			2,112			1,464
Depreciation, depletion, and amortization		24,341			20,066			15,226
Impairment of proved oil and natural gas properties		15,141			11,800			3,480
General and administrative		8,893			6,116			4,811
Accretion of asset retirement obligations		1,031			663			320
Gain on derivative instruments		(31,050	)		(10,264	)		(10,834	)
Gain on sale of properties		(63,024	)		(1	)		(7,851	)
Other, net		1,613			890			304

Total costs and expenses		(16,365	)		45,395			20,817

Operating income (loss)		89,722			(6,654	)		4,043
Interest expense		(7,268	)		(4,438	)		(2,937	)

Income (loss) before income taxes		82,454			(11,092	)		1,106
Income tax expense		(122	)		(225	)		—

Net income (loss)		82,332			(11,317	)		1,106
Net income (loss) attributable to predecessor		75,740			(11,317	)		1,106

Net income (loss) attributable to partners	$	6,592		$	—		$	—

Oil and natural gas revenue:
Oil sales	$	7,618		$	3,438		$	3,521
NGL sales		8,028			1,404			924
Natural gas sales		56,886			32,466			20,096

Total oil and natural gas revenue	$	72,532		$	37,308		$	24,541

Production Volumes:
Oil (MBbls)		83			45			61
NGLs (MBbls)		156			34			33
Natural gas (MMcf)		13,685			7,314			5,282

Total (MMcfe)		15,124			7,792			5,847

Average net production (MMcfe/d)		41.4			21.3			16.0

Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	91.26		$	75.81		$	58.01
NGL (per Bbl)		51.32			41.02			27.61
Natural gas (per Mcf)		4.16			4.44			3.80

Total (Mcfe)	$	4.80		$	4.79		$	4.20

Average unit costs per Mcfe:
Lease operating expense	$	1.49		$	1.79		$	1.92
Production taxes	$	0.27		$	0.27		$	0.25
General and administrative expenses	$	0.59		$	0.78		$	0.82
Depletion, depreciation, and amortization	$	1.61		$	2.58		$	2.60

Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010

Net income was $82.3 million for the year ended December 31, 2011, of which $75.7 was attributable to our predecessor. Our predecessor recorded a net loss of $11.3 million for the year ended December 31, 2010, none of which was attributable to the Partnership. Our predecessor recorded an aggregate gain on the sale of properties of $63.0 million during 2011 with no comparable gain recorded during 2010.

Revenues. Oil, natural gas and NGL revenues for 2011 totaled $72.5 million, an increase of $35.2 million compared with 2010. The increase was primarily the result of increased production of 7,332 MMcfe, or 94%, primarily related to the 2010 acquisitions of certain oil and gas assets in South Texas that were fully integrated in 2011, the acquisition of properties from BP in May 2011 and the acquisition of certain oil and gas assets in April 2011. The average realized sales price (excluding realized gain on derivatives) in 2011 was $4.80 per Mcfe, which was consistent with $4.79 per Mcfe in 2010.

Lease Operating. Lease operating expenses increased by approximately $8.5 million or 61% to approximately $22.5 million for the year ended December 31, 2011, from approximately $14.0 million for the year ended December 31, 2010. Lease operating expenses increased primarily due to costs associated with the South Texas properties acquired in 2010 which were fully integrated in 2011, the BP properties acquired in May 2011 and the acquisition of certain oil and gas assets in April 2011.

Production Taxes. Production taxes for 2011 totaled $4.1 million, an increase of $2.0 million compared with 2010. The increase in production taxes was primarily due to higher oil, natural gas and NGL revenues during 2011. Production taxes were 5.7% as a percentage of revenue in both 2011 and 2010.

Depreciation, Depletion and Amortization. DD&A expense increased from approximately $20.1 million for the year ended December 31, 2010 to approximately $24.3 million for the year ended December 31, 2011 due to increased production from 7,792 MMcfe to 15,124 MMcfe related to acquisitions in 2010 and 2011. DD&A expense per Mcfe decreased from $2.58 to $1.61 between 2010 and 2011 due to a higher proportional increase in proved reserve volumes when compared to the increase in capitalized costs subject to DD&A.

Impairment of Proved Oil and Natural Gas Properties. Our predecessor recognized non-cash impairments to proved oil and natural gas properties during 2011 of $15.1 million as compared to $11.8 million during 2010. The $15.1 million of impairments during 2011 were all attributable to our predecessor and there were no impairments recorded subsequent to our IPO closing on December 14, 2011.

For the year ended December 31, 2011, approximately $3.1 million of the $15.1 million of impairments related to a well abandoned in the Burke Unit located in South Texas due to a situation encountered during drilling, causing costs and future benefits to become unrecoverable. The remaining $12.0 million of impairments consisted of $6.9 million to the Craton field and $4.0 million to the Cayuga field, both of which are located in East Texas, as well as $0.1 million to the Benavides field and $1.0 million to the Wishbone field in South Texas. For these impairments, the estimated future cash flows expected from properties in these fields were compared to their carrying values and determined to be unrecoverable as a result of declines in natural gas prices.

For the year ended December 31, 2010, the estimated future cash flows expected in connection with several properties were compared to their carrying values and determined to be unrecoverable as a result of declines in natural gas prices. Of the $11.8 million, approximately $10.3 million related to the Nueces, Wishbone, San Idelfonso, Blancas Creek and Crabbs Prairie Fields in South Texas and the remaining $1.5 million related to approximately twenty other fields in South Texas, all individually immaterial.

General and Administrative. 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 2011 totaled $8.9 million,

of which $8.7 million was attributable to our predecessor. For 2010, general and administrative expenses were $6.1 million. Increased production volumes in 2011 drove general and administrative expenses lower on a per Mcfe basis from approximately $0.78 per Mcfe in 2010 to $0.59 per Mcfe in 2011.

Gain on Derivative Instruments. We and our predecessor recognized gains on commodity derivative instruments of $31.1 million in 2011, as compared to $10.3 million that our predecessor generated in 2010. For 2011, the $31.1 million gain was comprised of realized gains of $7.9 million and unrealized gains of $23.2 million. For 2010, the $10.3 million gain was comprised of realized gains of $7.3 million and unrealized gains of $3.0 million.

Gain on Sale of Properties. Our predecessor recognized a gain on sale of properties of $63.0 million during 2011 with no comparable gain recorded in 2010. 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 the predecessor paid a total of approximately $12.9 million in cash consideration at closing, net of adjustments. The preliminary 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 to accrued liabilities, and $0.6 million to deferred tax liabilities. After taking into consideration the net book value of $5.2 million for the Nueces Field properties exchanged to BP and the $12.9 million in cash consideration paid at closing, the predecessor recorded a $62.2 million gain relating to such transaction.

Our predecessor also recognized a gain of approximately $0.8 million during 2011 from the sale of working interests related to the deep rights under certain properties in Webb County in South Texas. The transactions did not involve the sale of any existing production or reserves.

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 totaled $7.3 million during 2011, of which $0.5 million was attributable to the Partnership’s revolving credit facility, which included unrealized losses on interest rate swaps of $0.3 million. Interest expense was $4.4 million in 2010. The increase was due primarily to additional debt incurred in conjunction with the acquisitions of oil and natural gas assets by our predecessor.

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

Our predecessor generated a net loss of $11.3 million during 2010 compared to net income of $1.1 million for the year ended December 31, 2009. Despite a $12.8 million increase in oil and natural gas sales revenues between the periods, net income decreased approximately $12.4 million primarily related to a $4.8 million increase in DD&A, an $8.3 million increase in impairment charges and a $7.9 million decrease in gains on the sale of properties.

Revenues. Our predecessor’s oil and natural gas sales revenues increased 52% from $24.5 million for the year ended December 31, 2009 to $37.3 million for the year ended December 31, 2010. Approximately $8.2 million of this increase was driven by increased production, which increased approximately 33% to 7,792 MMcfe for the year ended December 31, 2010. The remainder of the increase in revenues was due to higher oil and natural gas commodity prices received, which averaged $4.20 per Mcfe during 2009 and $4.79 per Mcfe during 2010. Other income revenues related to the predecessor properties increased from $0.3 million for the year ended December 31, 2009 to $1.4 million for the year ended December 31, 2010, primarily due to the settlement of litigation that occurred in 2010.

Lease Operating. Lease operating expenses increased from $11.2 million for the year ended December 31, 2009 to $14.0 million in 2010, primarily as a result of the increase in our predecessor’s production volumes described above. Lease operating expenses per Mcfe decreased period to period approximately 6% from $1.92 per Mcfe in 2009 to $1.79 per Mcfe in 2010, primarily related to the increase in production.

Exploration. Exploration expenses decreased from the $2.7 million incurred for the year ended December 31, 2009 to less than $0.1 million in 2010, primarily due to the reclassification of capitalized costs to expense in 2009 following the evaluation of exploratory wells previously drilled in 2008.

Production Taxes. Production taxes increased from $1.5 million in 2009 to $2.1 million in 2010, which is consistent with higher oil and natural gas commodity prices received during 2010 of $4.79 per Mcfe compared to $4.20 per Mcfe during 2009.

Depreciation, Depletion and Amortization. Our predecessor’s DD&A expense increased from approximately $15.2 million in 2009 to $20.1 million in 2010, primarily due to an increase in production from 5,847 MMcfe to 7,792 MMcfe.

Impairment of Proved Oil and Natural Gas Properties. Impairment of proved oil and natural gas properties totaled $3.5 million for 2009, as compared to $11.8 million for 2010. Due to a decline in future natural gas prices, the estimated future cash flows expected in connection with the Nueces Field was compared to the carrying value and was determined to be unrecoverable during 2009. For the year ended 2010, the estimated future cash flows expected in connection with several properties were compared to their carrying values and determined to be unrecoverable as a result of declines in future natural gas prices. Of the $11.8 million, approximately $10.3 million related to the Nueces, Wishbone, San Idelfonso, Blancas Creek and Crabbs Prairie Fields; the remaining $1.5 million related to approximately twenty other fields, all individually immaterial.

General and Administrative. Our predecessor’s general and administrative expenses totaled $4.8 million and $6.1 million for the years ended December 31, 2009 and 2010, respectively. General and administrative expenses include the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production. The change in general and administrative expenses during 2010 resulted primarily from an increase of approximately $0.5 million in payroll related costs and an increase of approximately $0.6 million in professional services fees paid.

Gain on Derivative Instruments. Our predecessor recognized gains on commodity derivative instruments of $10.8 million in 2009, as compared to $10.3 million generated in 2010. For 2009, the $10.8 million gain was comprised of realized gains of $17.6 million and unrealized losses of $6.8 million. For 2010, the $10.3 million gain was comprised of realized gains of $7.3 million and unrealized gains of $3.0 million.

Gain on Sale of Properties. During 2009, our predecessor recognized a gain of approximately $7.8 million on two separate sales of interests in the Nueces Mineral Company lease, located in South Texas and primarily undeveloped, for net proceeds of $11.7 million.

Interest Expense. Interest expense totaled $2.9 million in 2009 as compared to $4.4 million in 2010. This increase was due primarily to additional debt incurred in conjunction with acquisitions of certain oil and natural gas assets from Forest Oil in the second quarter of 2010.

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.

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. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to current credit conditions includes our revolving credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected crude oil, NGL and natural gas volumes through 2016 by entering into derivative financial instruments including floating for fixed crude oil, NGL and natural gas swaps. With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our targeted average net oil and natural gas production over a three-to-five year period at a given point in time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. See “— Commodity Derivative Contracts” within this Item 7 and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.” The current market conditions may also impact our ability to enter into future commodity derivative contracts. A significant reduction in commodity prices could reduce our operating margins and cash flow from operations.

Our partnership agreement requires that we distribute all of our available cash (as defined in our partnership agreement) to our unitholders and general partner. In making cash distributions, our general partner attempts to avoid large variations in the amount we distribute from quarter to quarter. To facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

We may borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. In addition, we hedge a significant portion of our production. We generally are required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and natural gas industry, we do not generally receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, we are required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions. Because we will distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production and as a result, we may not grow as quickly as other oil and natural gas entities or at all.

We continue to evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could result in losses.

We plan to reinvest a sufficient amount of our cash flow to fund our maintenance capital expenditures, and we plan to primarily use external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. Because our proved reserves and production decline continually over time and because we own a limited amount of undeveloped properties, we will need to make acquisitions to sustain our level of distributions to unitholders over time.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. Needed capital may not be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our revolving credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may be unable to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

As of December 31, 2011, our liquidity of $181.1 million consisted of $1.1 million of available cash, and $180.0 million of available borrowings under our revolving credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility. As of December 31, 2011, our revolving credit facility had borrowing capacity of $180.0 million ($300.0 million borrowing base less $120.0 million of outstanding borrowings). The borrowing base will be redetermined semi-annually, beginning on April 1, 2012, by the administrative agent of our revolving credit facility based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts.

A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands. As of December 31, 2011, we had no letters of credit outstanding.

Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 7 and Note 8 of the Notes to Consolidated and Predecessor Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data,” contained herein.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. We believe our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next twelve months.

As of December 31, 2011, we had a positive working capital balance of $23.6 million.

Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital is to maintain our production and asset base at a steady level over the long term to maintain our distributions per unit. We intend to pay for maintenance capital expenditures from operating cash flow.

Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The primary purpose of growth capital is to acquire producing assets that will increase our distributions per unit and secondarily increase the rate of development and production of our existing properties

in a manner which is expected to be accretive to our unitholders. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. We expect to primarily rely upon external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions.

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our revolving credit facility will exceed our planned capital expenditures and other cash requirements for 2012. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, generally. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures. See “— Outlook” for additional information regarding our capital spending program.

Revolving Credit Facility

Concurrently with the closing of our IPO, OLLC entered into a new senior secured revolving credit facility, which facility is guaranteed by us and all of our current and future subsidiaries. This revolving credit facility is a five-year, $1.0 billion revolving credit facility with an initial borrowing base of $300.0 million. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In the future, we may be unable to access sufficient capital under our revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to pledge additional properties as security for our revolving credit facility or repay any indebtedness in excess of the borrowing base. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility. Additionally, we will not be able to pay distributions to our unitholders in any quarter in which a borrowing base deficiency or an event of default occurred either before or after giving effect to such distribution or we are not in compliance with our revolving credit facility after giving effect to such distribution.

Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings under our revolving credit facility bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

Our revolving credit facility requires us to maintain a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is defined under our revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under our revolving credit facility, of not less than 1.0 to 1.0.

Additionally, our revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness.

Events of default under our revolving credit facility include the failure to make payments when due, breach of any covenants continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on the business of OLLC or us.

If we fail to perform our obligations under these or any other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness under our revolving credit facility, together with accrued interest, fees and other obligations under the credit agreement, could be declared immediately due and payable.

Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of oil and natural gas and our ability to maintain and increase production through acquisitions and exploitation and development projects.

Memorial Resource contributed derivative contracts to us at the closing of our IPO, and following such closing, we established additional hedges on a portion of our expected oil, NGL and natural gas volumes both before and subsequent to December 31, 2011. As of March 21, 2012, we have commodity derivative contracts for the years ending December 31, 2012, 2013, 2014, 2015 and 2016 covering approximately 83%, 78%, 68%, 67% and 67%, respectively, of our targeted average net production of natural gas, and we have total hedged volumes for the years ending December 31, 2012, 2013, 2014, 2015 and 2016, respectively, at NYMEX (Henry Hub) equivalent weighted-average hedge prices of $4.74, $4.63, $4.51, $4.50 and $4.67 per MMBtu. We have commodity derivative contracts for the years ending December 31, 2012, 2013, 2014, 2015 and 2016 covering approximately 85%, 77%, 76%, 76%, and 76% respectively, of our targeted average net production of crude oil, and have total hedged volumes for the years ending December 31, 2012, 2013, 2014, 2015, and 2016, respectively, at NYMEX (WTI) weighted-average hedge prices of $89.91, $88.89, $90.28, $91.36 and $91.34 per barrel. We also have commodity derivative contracts for the years ending December 31, 2012 and 2013 covering approximately 30% and 31% respectively, of our targeted average net production of NGLs, and have total hedged volumes for the years ending December 31, 2012 and 2013, respectively, at NYMEX weighted-average hedge prices of $72.22 and $73.11 per barrel.

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.

The following table reflects the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of March 21, 2012:


	2012			2013			2014		2015		2016
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu/d)		16,030			29,102			29,786		29,680		29,616
Weighted-average fixed price	$	4.60		$	4.54		$	4.51	$	4.50	$	4.67

Collar contracts:
Volume (MMBtu/d)		18,126			5,326			—		—		—
Weighted-average floor price	$	4.86		$	5.15		$	—	$	—	$	—
Weighted-average ceiling price	$	5.94		$	5.81		$	—	$	—	$	—

Put options:
Volume (MMBtu/d)		2,295			—			—		—		—
Weighted-average floor price	$	4.80		$	—		$	—	$	—	$	—

Total natural gas volumes hedged (MMBtu/d):		36,451			34,428			29,786		29,680		29,616

Basis swaps:
Volume (MMBtu/d)		33,168			32,579			—		—		—
Weighted-average spread	$	(0.12	)	$	(0.14	)	$	—	$	—	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbl/d)		92			60			110		215		214
Weighted-average fixed price	$	95.13		$	93.39		$	90.55	$	91.36	$	91.34

Collar contracts:
Volume (Bbl/d)		148			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):		240			216			215		215		214

NGL Derivative Contracts:
Fixed price swap contracts:
Volume (Bbl/d)		62			188			—		—		—
Weighted-average fixed price	$	66.37		$	73.11		$	—	$	—	$	—

Collar contracts:
Volume (Bbl/d)		125			—			—		—		—
Weighted-average floor price	$	75.16		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	93.57		$	—		$	—	$	—	$	—
Total NGL volumes hedged (Bbl/d):		187			188			—		—		—

See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk” for a summary of our derivative contracts as of December 31, 2011.

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. At December 31, 2011, we had the following fixed-for floating interest rate swap open positions:


Period Covered		Notional ($ in thousands)		Floating Rate		Fixed Rate
1/17/2012	1/16/2013	$	100,000		1 Month LIBOR		0.600	%
1/17/2013	12/14/2016	$	100,000		1 Month LIBOR		1.305	%

Counterparty Exposure

As of December 31, 2011, our open commodity derivative contracts were in a net receivable position. All of our commodity derivative contracts are with major financial institutions who are also lenders under our revolving credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss. Although we have entered into netting agreements under our derivative instruments with certain of our counterparties, below we have presented all asset and liability positions without netting. As of December 31, 2011, all of our counterparties have performed pursuant to their commodity derivative contracts.

The following table presents our gross asset and liability positions with our counterparties as of December 31, 2011:


	Gross
Assets		35,829
Liabilities		(3,869	)

Net		31,960

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 year ended December 31, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor for the period from January 1, 2011 to December 13, 2011 and the consolidated financial information of the Partnership for the period from December 14, 2011 to December 31, 2011. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated and Predecessor Combined Cash Flows included under “Item 8. Financial Statements and Supplementary Data” contained herein.


	For Year Ended December 31,
	2011		2010		2009
	(in thousands)
Net cash provided by operating activities	$	35,478	$	20,288	$	12,672
Net cash used in investing activities		158,505		116,687		24,947
Net cash provided by financing activities		118,461		96,756		15,989

Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010

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 year ended December 31, 2011 primarily due to an increase in production volumes as a result of our predecessor’s acquisition activities. Cash flows provided by operating activities were primarily used to fund our predecessor’s exploration and development expenditures.

Investing Activities. During 2011, our predecessor spent $138.2 million on several acquisitions, the largest of which was the purchase of oil and natural gas properties in East Texas from a third party for $120.8 million. Our predecessor incurred capital expenditures of $22.4 million in conjunction with the drilling of 4 gross wells in 2011, none of which were dry holes, for a success rate of 100%. Our predecessor’s acquisition and development expenditures were offset by proceeds from the sale of properties for $2.4 million.

During 2010, our predecessor spent $104.5 million on several acquisitions, the largest of which was the purchase of oil and natural gas properties from Forest Oil for $65.9 million. Our predecessor incurred capital expenditures of $13.1 million in conjunction with the drilling of 3 gross wells in 2010, none of which were dry holes, for a success rate of 100%. Our predecessor’s acquisition and development expenditures were partially offset by proceeds from the sale of properties for $1.4 million.

Financing Activities. On December 14, 2011, the Partnership completed its 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 our IPO, we distributed approximately $73.6 million as partial consideration to Memorial Resource in exchange for the net assets of our predecessor and repaid $198.3 million of our predecessor’s credit facilities concurrent with the closing of our IPO. This cash distribution was financed with approximately $130.0 million in borrowings under a new senior secured revolving credit facility and the net cash proceeds generated from our IPO. 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 at the IPO price, 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. Loan origination fees were $2.5 million related to this credit facility.

During 2011, net advances of $82.8 million under our predecessor’s revolving credit facilities and capital contributions of $48.9 million were used to fund our predecessor’s development and property acquisition program. During 2010, net advances of $53.5 million under our predecessor’s revolving credit facilities and capital contributions of $44.1 million were used to fund our predecessor’s development and property acquisition program. Loan origination fees incurred by our predecessor were $0.9 million during 2011 compared to $1.0 million during 2010.

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

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 year ended December 31, 2010, despite a decrease in net income, primarily due to an increase in production volumes as a result of our predecessor’s acquisition activities as well as their continued drilling success. Cash flows provided by operating activities were primarily used to fund our predecessor’s exploration and development expenditures.

Investing Activities. During 2010, our predecessor spent $104.5 million on several acquisitions, the largest of which was the purchase of oil and natural gas properties from Forest Oil for $65.9 million. Our predecessor incurred capital expenditures of $13.1 million in conjunction with the drilling of 3 gross wells in 2010, none of which were dry holes, for a success rate of 100%. Our predecessor’s acquisition and development expenditures were offset by proceeds from the sale of properties for $1.4 million.

During 2009, our predecessor spent $17.5 million on several acquisitions of oil and natural gas properties in South Texas. Our predecessor incurred capital expenditures of $19.0 million in conjunction with the drilling of 5 gross wells in 2010, one of which was a dry hole, for a success rate of 80%. Our predecessor’s acquisition and development expenditures were partially offset by proceeds from the sale of properties for $11.8 million.

Financing Activities. During 2010, net advances of $53.5 million under our predecessor’s revolving credit facilities and capital contributions of $44.1 million were used to fund our predecessor’s development and property acquisition program. During 2009, capital contributions of $17.3 million were partially offset by net repayments of $0.8 million under our predecessor’s revolving credit facilities. These capital contributions were used to fund our predecessor’s development and property acquisition program.

Capital Requirements

See “—Outlook” for additional information regarding our capital spending program for 2012.

In 2012, we intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4750 per unit per quarter on all common, subordinated and general partner units ($1.90 per unit on an annualized basis). Based on the number of common units, subordinated units and general partner units outstanding as of March 16, 2012 and the actual cash distribution paid on February 13, 2012, distributions to all of our unitholders at the minimum quarterly distribution rate in 2012 would total approximately $33.7 million.

We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisition of oil and natural gas properties in 2012 through a combination of cash from operations, borrowings under our revolving credit facility and the issuance of equity or debt securities.

Contractual Obligations

Our contractual obligations are limited in scope because Memorial Resource provides management, administrative and operating services to us under an omnibus agreement as discussed under “Item 13. Certain Relationships and Related Transactions, and Director Independence —Omnibus Agreement.” In the table below, we set forth our contractual obligations as of December 31, 2011. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.


	Payments Due by Period (in thousands)
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Revolving credit facility (1)	$	120,000	$	—	$	—	$	120,000	$	—
Estimated interest payments (2)		21,331		3,739		8,885		8,707		—
Asset retirement obligations (3)		13,614		—		1,094		811		11,709
Operating leases (4)		734		682		52		—		—

Total	$	155,679	$	4,421	$	10,031	$	129,518	$	11,709

(1)	Represents the scheduled future maturities of principal amount outstanding for the periods indicated. See Note 7 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this annual report for information regarding our revolving credit facility.

(2)

Estimated interest payments are based on the principal amount outstanding under our revolving credit facility at December 31, 2011. In calculating these amounts, we applied the weighted-average interest rate during 2011 associated with such debt. See Note 7 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this annual report for the weighted-average variable interest rate charged during 2011 under this credit facility. In addition, our estimate of payments for interest gives effect to interest rate swap agreements that were in place at December 31, 2011.

(3)

Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2011 balance sheet. See Note 6 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this annual report for additional information regarding our asset retirement obligations.

(4)	Primarily represents operating leases for certain equipment such as compressors and office space. See Note 12 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this annual report for information regarding our operating leases.

Off–Balance Sheet Arrangements

As of December 31, 2011, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this annual report.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to our natural gas production and the prevailing price for oil. Pricing for oil and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil and natural gas production depend on many factors outside of our control, such as the strength of the global economy.

To reduce the impact of fluctuations in oil and natural gas 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 oil and natural gas production through various transactions that fix the future prices received. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. We do not enter into derivative contracts for speculative trading purposes.

Swaps. In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.

Basis Swaps. These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. Our basis protection swaps typically have negative differentials to NYMEX. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and we pay the counterparty if the price differential is less than the stated terms of the contract.

Put Options. In a typical put option arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX quoted prices. Our current put options are exercised and settled in cash on a monthly basis only when the floor price exceeds the reference price, otherwise they expire unsettled.

Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the contract ceiling price. Our current collars are exercised in cash on a monthly basis only when the reference price is outside of floor and ceiling prices (the collar), otherwise they expire.

The following table summarizes our derivative contracts as of December 31, 2011 and the average prices at which the production will be hedged:


	2012			2013			2014		2015		2016
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu/d)		10,738			13,805			24,352		25,626		28,366
Weighted-average fixed price	$	4.91		$	4.54		$	4.44	$	4.44	$	4.70

Collar contracts:
Volume (MMBtu/d)		20,311			19,410			3,934		2,623		—
Weighted-average floor price	$	4.79		$	4.75		$	5.08	$	5.25	$	—
Weighted-average ceiling price	$	5.91		$	5.83		$	6.31	$	6.75	$	—

Put options:
Volume (MMBtu/d)		2,295			—			—		—		—
Weighted-average floor price	$	4.80		$	—		$	—	$	—	$	—

Total natural gas volumes hedged (MMBtu/d):		33,344			33,215			28,286		28,249		28,366
Basis swaps:
Volume (MMBtu/d)		33,168			32,579			—		—		—
Weighted-average spread	$	(0.12	)	$	(0.14	)	$	—	$	—	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbl/d)		59			50			74		—		—
Weighted-average fixed price	$	92.00		$	92.00		$	87.90	$	—	$	—

Collar contracts:
Volume (Bbl/d)		148			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):		207			206			179		—		—

NGL Derivative Contracts:
Collar contracts:
Volume (Bbl/d)		125			—			—		—		—
Weighted-average floor price	$	75.16		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	93.57		$	—		$	—	$	—	$	—

Total NGL volumes hedged (Bbl/d):		125			—			—		—		—

See “ Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources —Commodity Derivative Contract” for a summary of our derivative contracts that were in place as of March 21, 2012.

Interest Rate Risk

At December 31, 2011, we had $120 million of debt outstanding under our revolving credit facility, with a weighted average interest rate of LIBOR plus 2.0%, or 2.28%. 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. Following the closing of our IPO, we entered into the following interest rate swap arrangements:

•

$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%; and

•

$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%.

Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the weighted average interest rate, after giving effect to our interest rate swaps, would be approximately $0.3 million per year.

Counterparty and Customer Credit Risk

Joint interest billings receivable represent amounts receivable for lease operating expenses and other costs due from third party working interest owners in the wells that the Partnership operates. The receivable is recognized when the cost is incurred. We have limited ability to control participation in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. See “Item 1. Business” for further detail about our 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 oil and natural gas derivative contracts expose us to credit risk in the event of nonperformance by counterparties. As of December 31, 2011, our open commodity derivative contracts were in a net receivable position with a fair value of $32.2 million. Should one of the counterparties to our commodity derivative contracts not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss.

While we do not require our customers to post collateral and do not have a formal process in place to evaluate and assess the credit standing of our significant customers or the counterparties on its derivative contracts, we do evaluate the credit standing of our customers and such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating and latest financial information or, in the case of a customer with which we have receivables, reviewing its historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative contracts currently in place are lenders under our revolving credit facility, with investment grade ratings and we are likely to enter into any future derivative contracts with these or other lenders under our revolving credit facility that also carry investment grade ratings. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated and Predecessor Combined Financial Statements, together with the report of our independent registered public accounting firm begin on page F-1 of this annual report.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

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 annual 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 December 31, 2011.

Management’s Report on Internal Control Over Financial Reporting

This annual report is not required to include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.

Changes in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management

Memorial Production Partners GP LLC, our general partner, manages our operations and activities on our behalf. Our general partner is a wholly-owned subsidiary of Memorial Resource. All of our executive management personnel are employees of Memorial Resource and devote their time as needed to conduct our business and affairs.

Our general partner has a board of directors that oversees its management, operations and activities. The board of directors currently has six members. The board of directors has determined that Mr. Clarkson and Mr. Highum both satisfy the independence standards established by NASDAQ and SEC rules. Within one year of the date our common units were listed on NASDAQ, the board of directors of our general partner will have at least three independent directors. Because we are a limited partnership, we are not required to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee.

Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Memorial Resource appoints all members to the board of directors of our general partner.

Our general partner owes a fiduciary duty to our unitholders. However, our partnership agreement contains provisions that reduce and define the extent of that duty. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it. Except for limited circumstances under our partnership agreement and subject to its fiduciary duty to act in good faith, our general partner has exclusive management power over our business and affairs.

Board Leadership Structure and Role in Risk Oversight

Leadership of our general partner’s board of directors is vested in a Chairman of the board. John A. Weinzierl serves as the Chairman of the board of directors of our general partner and as President and Chief Executive Officer of our general partner. Our general partner’s board of directors has determined that the combined roles of Chairman and Chief Executive Officer allows the board of directors to take advantage of the leadership skills of Mr. Weinzierl and is appropriate because Mr. Weinzierl works closely with our management team on a daily basis and is in the most knowledgeable position to determine the timing for board meetings and propose agendas for meetings. However, any director can establish agenda items for a board meeting. Mr. Weinzierl’s in-depth knowledge of, and experience in, our business, history, structure and organization facilitates timely communications between our general partner’s management and the board of directors. Our general partner’s board of directors has also determined that having the Chief Executive Officer serve as a director enhances understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations and ultimately improves the ability of the board of directors to perform its oversight role. In addition, our general partner’s board of directors believes that maintaining the combined Chairman and Chief Executive Officer positions contributes to a consistent strategy and direction for us and our unitholders by alleviating potential ambiguities in the decision-making process.

The management of enterprise-level risk may be defined as the process of identifying, managing and monitoring events that present opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primary responsibility for enterprise-level risk management, while the board of directors has retained responsibility for oversight of management in that regard. Our executive officers offer an enterprise-level risk assessment to the board of directors at least once every year.

Directors and Executive Officers

The following table sets forth certain information regarding the current directors and executive officers of our general partner as of March 16, 2012.


Name	Age		Position with our General Partner
John A. Weinzierl		43	President, Chief Executive Officer, and Chairman
Andrew J. Cozby		45	Vice President and Chief Financial Officer
Larry R. Forney		54	Vice President, Operations and Asset Management
Patrick T. Nguyen		39	Chief Accounting Officer
Kyle N. Roane		32	General Counsel and Corporate Secretary
Gregory M. Robbins		33	Treasurer
Jonathan M. Clarkson		62	Director
Scott A. Gieselman		48	Director
Kenneth A. Hersh		49	Director
P. Michael Highum		61	Director
Tony R. Weber		49	Director

Our general partner’s directors hold office until the earlier of their respective death, resignation, removal or disqualification or until their respective successors have been elected and qualified. Officers serve at the discretion of the board of directors. In selecting and appointing directors to the board of directors, the owners of our general partner do not intend to apply a formal diversity policy or set of guidelines. However, when appointing new directors, the owners of our general partner will consider each individual director’s qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board of directors as a whole.

John A. Weinzierl has served as our general partner’s President, Chief Executive Officer and Chairman of the board of directors since April 2011. Prior to the completion of our IPO in December 2011, Mr. Weinzierl was a managing director and operating partner of NGP from December 2010. From July 1999 to December 2010, Mr. Weinzierl worked in various positions at NGP, where he became a managing director in December 2004. Mr. Weinzierl was appointed a venture partner of NGP in February 2012 and currently serves as a director for several of NGP’s private portfolio companies. From October 2006 until November 2011, Mr. Weinzierl was a director of Eagle Rock Energy G&P, LLC, the indirect general partner of Eagle Rock Energy Partners, L.P., a (i) natural gas gathering, processing and transportation company and (ii) developer of oil and natural gas properties, where he also served on the compensation committee. Mr. Weinzierl holds a B.S. in petroleum engineering and an M.B.A. from the University of Texas at Austin and is a registered professional engineer in Texas.

The board believes Mr. Weinzierl’s degree and experience in petroleum engineering, his M.B.A. education, as well as his investment and business expertise honed at NGP brings valuable strategic, managerial and analytical skills to the board and us.

Andrew J. Cozby has served as our general partner’s Vice President and Chief Financial Officer since February 2012. Previously, he served as our general partner’s Vice President of Finance from April 2011 to February 2012. From February 2011 to April 2011, Mr. Cozby served as Senior Vice President and Chief Financial Officer of Energy Maintenance Services (EMS Global). Prior to that, he was Chief Financial Officer of Greystone Oil & Gas LLP and Greystone Drilling LP from May 2006 to December 2010. From 2000 to May 2006, Mr. Cozby was Director of Finance for Enterprise Products Partners LP and held various corporate finance positions with its affiliates GulfTerra Energy Partners, LP and El Paso Energy Partners, LP. Prior to that, Mr. Cozby held positions with J.P. Morgan from 1998 to 2000. Mr. Cozby holds a B.B.A. in finance from the University of Texas and an M.B.A. in finance from the University of Houston. He is also a graduate of Texas Tech University (J.D.), the University of Houston (LL.M., energy and natural resources law) and Harvard Business School (advanced management program).

Larry R. Forney has served as our general partner’s Vice President of Operations and Asset Management since August 2011. From August 2008 to August 2011, Mr. Forney served as President of Mossback

Management LLC, a private entity providing contract operating and engineering consulting services, including managing all operations and related business functions for Hungarian Horizon Energy, Ltd and Central European Drilling, Ltd in Budapest, Hungary from July 2010 to August 2011. From July 2004 to July 2008, Mr. Forney served as Vice President of Operations for Greystone Oil & Gas LLP and Managing Director of Greystone Drilling LP. Mr. Forney served as Vice President of Operations for Greystone Petroleum LLC from 2002 until 2004. Mr. Forney was Vice President and Treasurer of Goldrus Producing Company from 1997 to 2002. From 1990 to 1997, Mr. Forney held various positions for the Kelley Oil companies, which culminated in his serving concurrently as Vice President of Operations for Kelley Oil Corporation and Vice President of Concorde Gas Marketing. Prior to 1990, Mr. Forney held various drilling, production and facility construction positions with Pacific Enterprises Oil Corporation and Kerr-McGee Corporation. Mr. Forney is a graduate of the University of Texas at Austin with a B.S. in petroleum engineering and a registered professional engineer in Texas.

Patrick T. Nguyen has served as our general partner’s Chief Accounting Officer since June 2011. Prior to joining our general partner, Mr. Nguyen was with Enterprise Products Partners LP from June 2007 to May 2011 as Director of Financial Accounting and Director of Accounts Receivable and Accounts Payable. From September 1996 to June 2007, he held positions in financial accounting and reporting within El Paso Corporation’s midstream segment, El Paso Field Services Company and its affiliates GulfTerra Energy Partners, LP and El Paso Energy Partners, LP. Prior to that, he worked at BHP Billiton as a joint venture and general ledger accountant. Mr. Nguyen holds a B.B.A. in Accounting and Taxation from the University of Houston and a CPA license in the state of Texas.

Kyle N. Roane has served as our general partner’s General Counsel and Corporate Secretary since February 2012. From 2005 to February 2012, Mr. Roane practiced corporate and securities law at Akin, Gump, Strauss, Hauer & Feld L.L.P. Mr. Roane holds a B.A. in political science and a G.D.B.A. in finance from Simon Fraser University and a J.D. from the University of Houston Law Center.

Gregory M. Robbins has served as our general partner’s Treasurer since June 2011. From October 2010 to April 2011, Mr. Robbins served as Vice President and Controller of Quality Electric Steel Castings, LP. Prior to that, he was a Vice President with Guggenheim Partners, LLC from April 2006 to September 2010. Mr. Robbins worked for Wells Fargo Energy Capital, LLC from 2004 to March 2006 and Comerica Bank, Inc. from 2002 to 2004. Mr. Robbins holds a B.B.A. in finance from Southwest Texas State and a M.S. in Finance from Texas A&M University.

Jonathan M. Clarkson has served as a member of the board of directors of our general partner since December 2011. Mr. Clarkson served as Chairman of the Houston Region of Texas Capital Bank from May 2009 until his retirement in December 2011. From 2003 to May 2009, he served as President and CEO of the Houston Region of Texas Capital Bank. From May 2001 to October 2002, Mr. Clarkson served as President, Chief Financial Officer and a director of Mission Resources Corp., an independent oil and gas exploration and production company. From 1999 through 2001, Mr. Clarkson served as President, Chief Operating Officer and a director of Bargo Energy Company, a private company engaged in the acquisition and exploitation of onshore oil and natural gas properties, which merged with Mission Resources in May 2001. From 1987 to 1999, Mr. Clarkson served as Executive Vice President and Chief Financial Officer for Ocean Energy Corp. and its predecessor company United Meridian Corporation. From October 2006 until December 2009, Mr. Clarkson served on the board of directors, was chairman of the audit committee, and was a member of the compensation committee of Edge Petroleum Corp., an oil and gas exploration and production company. Mr. Clarkson has served on the board of directors and the audit committee of Parker Drilling Company since March 2012. Since September 2010, Mr. Clarkson has served on the advisory board of Rivington Capital Advisors, LLC, an investment banking firm focused on upstream energy sector investments. Mr. Clarkson received a B.S. in economics from Southern Methodist University in 1972 and a M.B.A. in finance and accounting from the J.L. Kellogg School of Management at Northwestern University in 1975.

The board believes that Mr. Clarkson brings to the board his substantial prior financial and executive management expertise including his experience as a chief financial officer in the oil and gas industry and his valuable prior board experience and audit and compensation committee service.

Scott A. Gieselman has served as a member of the board of directors of our general partner since September 2011. Mr. Gieselman has been a managing director of NGP since April 2007. From 1988 to April 2007, Mr. Gieselman worked in various positions in the investment banking energy group of Goldman, Sachs & Co., where he became a partner in 2002. Mr. Gieselman received a B.S. from the Boston College Carroll School of Management in 1985 and a M.B.A. from the Boston College Carroll Graduate School of Management in 1988.

The board believes that Mr. Gieselman’s considerable financial and energy investment banking experience, as well as his experience on the boards of numerous private energy companies bring important and valuable skills to the board of directors.

Kenneth A. Hersh has served as a member of the board of directors of our general partner since its formation in April 2011. Mr. Hersh is the Chief Executive Officer of NGP Energy Capital Management and a managing partner of NGP and has served in those or similar capacities since 1989. He currently serves as a director of NGP Capital Resources Company, a business development company that focuses on the energy industry. Mr. Hersh served as a director of Resolute Energy Corporation from September 2009 to March 2012, as a director of Eagle Rock Energy G&P, LLC, the indirect general partner of Eagle Rock Energy Partners, L.P., from March 2006 until June 2011 and Energy Transfer Partners, L.L.C., the indirect general partner of Energy Transfer Partners, L.P., a natural gas gathering and processing and transportation and storage and retail propane company, from February 2004 through December 2009, and served as a director of LE GP, LLC, the general partner of Energy Transfer Equity, L.P., from October 2002 through December 2009. Mr. Hersh received a B.A. in Politics, magna cum laude, in 1985 from Princeton University. In 1989, he received his M.B.A. from Stanford University where he graduated as an Arjay Miller Scholar. Mr. Hersh currently serves on the Dean’s Council of the Harvard Kennedy School and on the Advisory Councils of the Graduate School of Business at Stanford University and The Bendheim Center for Finance at Princeton University. He is also a member of the World Economic Forum where he has been a featured speaker at its annual meeting held in Davos, Switzerland.

The board believes that Mr. Hersh brings extensive knowledge to the board and us through his experiences in the energy industry as an investor, involvement in complex energy-related transactions and his position as Chief Executive Officer of NGP Energy Capital Management and co-manager of NGP’s investment portfolio. Mr. Hersh also brings a wealth of industry-specific transactional skills, entrepreneurial ideas and a personal network of public and private capital sources that the board believes will bring us opportunities that we may not otherwise have.

P. Michael Highum has served as a member of the board of directors of our general partner since March 2012. Subsequent to his retirement in 2001, he has been primarily involved in managing his private investments. From 2002 to 2006, Mr. Highum served as an advisor to Fidelity Investments, where he helped establish and develop FIML Natural Resources LLC, an oil and gas exploration and production company. He co-founded HS & Associates in 1978, which was the predecessor to the NYSE-listed HS Resources, Inc., an independent oil and gas exploration and production company (later sold to Kerr McGee Corporation in 2001), where he served as President and Director. From 1995 to 2001, Mr. Highum served as a Director (and President in 1999) of the Colorado Oil and Gas Association. Prior to HS & Associates, Mr. Highum practiced corporate law in the San Francisco office of Pillsbury, Madison & Sutro, LLP. Mr. Highum received a B.A. from the University of California at Berkeley in 1973 and a J.D. from the University of California, Hastings College of Law in 1976.

The board believes that Mr. Highum’s considerable executive management and energy investment experience bring substantial investment management skills to the board of directors.

Tony R. Weber has served as a member of the board of directors of our general partner since September 2011. Mr. Weber currently serves as Managing Director and Chief Investment Coordinator for NGP. Prior to joining NGP in December 2003, Mr. Weber was the Chief Financial Officer of Merit Energy Company from April 1998 to December 2003. Prior to that, he was Senior Vice President and Manager of Union Bank of California’s Energy Division in Dallas, Texas from 1987 to 1998. In his role at NGP, Mr. Weber serves on

numerous private company boards as well as industry groups, IPAA Capital Markets Committee and Dallas Wildcat Committee. Mr. Weber earned a B.B.A. in Finance from Texas A&M University in 1984. He currently serves on the Dean’s Council of the Mays Business School and was a founding member of the Mays Business Fellows Program.

The board believes that Mr. Weber’s extensive corporate finance, banking and private equity experience bring substantial leadership skill and experience to the board of directors.

Composition of the Board of Directors

Our general partner’s board of directors consists of six members. The board of directors holds regular and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board of directors from time to time. Special meetings of the board of directors or meetings of any committee thereof may be held at the request of the Chairman of the board of directors or a majority of the board of directors (or a majority of the members of such committee) upon at least two days (if the meeting is to be held in person) or 24 hours (if the meeting is to be held telephonically) prior oral or written notice to the other members of the board or committee or upon such shorter notice as may be approved by the directors or members of such committee. A quorum for a regular or special meeting will exist when a majority of the members are participating in the meeting either in person or by telephone conference. Any action required or permitted to be taken at a board meeting may be taken without a meeting if such action is evidenced in writing and signed by all of the members of the board of directors.

Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of the board of directors of our general partner, all of our independent directors intend to meet in an executive session without participation by management or non-independent directors. Mr. Clarkson is expected to preside over these executive sessions.

Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board of directors, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: c/o Secretary, Memorial Production Partners LP, 1301 McKinney, Suite 2100, Houston, Texas 77010. Communications are distributed to the board of directors, committee of the board of directors, or director as appropriate, depending on the facts and circumstances outlined in the communication. Commercial solicitations or communications will not be forwarded.

Committees of the Board of Directors

The board of directors established an audit committee and from time to time, establishes a conflicts committee.

Because we are a limited partnership, the listing standards of the NASDAQ do not require that we or our general partner have a majority of independent directors or a nominating or compensation committee of the board of directors. We are, however, required to have an audit committee, a majority of whose members are required to be “independent” under NASDAQ standards as described below.

Audit Committee

The board of directors of our general partner has established an audit committee. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all

auditing services and related fees and the terms thereof, and pre-approves any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee. The charter for the audit committee is available within the “Corporate Governance” section of our website at http://investor.memorialpp.com/governance.cfm. The information contained on, or connected to, our website is not incorporated by reference into this annual report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Messrs. Clarkson, Highum and Weber currently serve on the audit committee, and Mr. Clarkson serves as the chairman. Both Mr. Clarkson and Mr. Highum meet the independence and experience standards established by NASDAQ and the Securities Exchange Act of 1934, as amended, or the Exchange Act. The board of directors of our general partner has determined that Mr. Clarkson is an “audit committee financial expert” as defined under SEC rules. In compliance with the requirements of NASDAQ Marketplace Rules, within one year of the closing of our IPO, the audit committee will consist of at least three directors, all of whom will meet the independence and experience standards established by the NASDAQ Marketplace Rules and the Exchange Act. The audit committee held no meetings in 2011.

Conflicts Committee

From time to time, the board of directors of our general partner will establish a conflicts committee to review specific matters that the board of directors believes may involve conflicts of interest and which it determines to submit to the conflicts committee for review. Under our partnership agreement, the conflicts committee has responsibility for (i) approving the amount of estimated maintenance capital expenditures deducted from operating surplus and (ii) the approval of the allocation of capital expenditures between maintenance capital expenditures, investment capital expenditures and growth capital expenditures. Other than these enumerated responsibilities, our general partner may, but is not required to, seek approval from the conflicts committee regarding a resolution of a conflict of interest with our general partner or affiliates. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Every member of the conflicts committee must not be an officer or employee of our general partner or its affiliates, must otherwise be independent of our general partner and its affiliates (including Memorial Resource and NGP), and must meet the independence standards established by the NASDAQ Marketplace Rules and the Exchange Act to serve on an audit committee of a board of directors. We intend for the conflicts committee to generally have at least two members. Because our partnership agreement only requires that the conflicts committee have at least one member, during any time that the committee only has one member, that single member of the conflicts committee will be able to approve resolutions of conflicts of interest. It is possible that a single-member committee may not function as effectively as a multiple-member committee and, if we pursue a transaction with an affiliate while the conflicts committee has only one member, our limited partners will be deemed to have approved that transaction through the approval of that single-member committee, in the same manner as would have occurred had the committee consisted of more directors. The conflicts committee held no meetings in 2011.

Meetings and Other Information

The board of directors of our general partner held one meeting in 2011.

Our partnership agreement provides that the general partner manages and operates us and that, unlike holders of common stock in a corporation, unitholders only have limited voting rights on matters affecting our business or governance. Accordingly, we do not hold annual meetings of unitholders.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act, to file reports of beneficial ownership and reports of changes in beneficial ownership of such securities with the SEC. Directors, officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of all Section 16(a) forms they file with the SEC.

Based solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of Memorial Production Partners GP LLC, we believe that during the year ended December 31, 2011 the officers and directors of Memorial Production Partners GP LLC and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a).

Corporate Governance

The board of directors of our general partner has adopted a Code of Ethics for Senior Financial Officers, or Code of Ethics, that applies to the chief executive officer, chief financial officer or vice president of finance, chief accounting officer, controller, treasurer and all other persons performing similar functions on behalf of our general partner and us. Amendments to or waivers from the Code of Ethics will be disclosed on our website. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and its affiliates and us.

We make available free of charge, within the “Corporate Governance” section of our website at http://investor.memorialpp.com/governance.cfm, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines and the Code of Business Conduct and Ethics. Requests for print copies may be directed to Investor Relations at ir@memorialpp.com or to Investor Relations, Memorial Production Partners LP, 1301 McKinney, Suite 2100, Houston, Texas 77010 or made by telephone at (713) 588-8350. The information contained on, or connected to, our website is not incorporated by reference into this annual report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Reimbursement of Expenses of Our General Partner

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates, including Memorial Resource, may be reimbursed.

Pursuant to the omnibus agreement with Memorial Resource, management, administrative and operational services are provided to our general partner and us to manage and operate our business. Our general partner reimburses Memorial Resource, on a monthly basis, for the allocable expenses it incurs in its performance under the omnibus agreement, and we reimburse our general partner for such payments it makes to Memorial Resource. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated to our general partner. We believe the expenses to be no more than those we would be required to pay if we received services from an unaffiliated third party. Memorial Resource has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion of its expenses to allocate to us. In turn, our partnership agreement provides that our general partner determines in good faith the expenses that are allocable to us. See “Item 13. Certain Relationships and Related Transactions and Director Independence—Omnibus Agreement.”

ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

General

All of our general partner’s executive officers and other personnel necessary for our business to function are employed and compensated by our general partner or Memorial Resource, in each case subject to reimbursement by us. Memorial Resource currently manages our operations and activities, and makes certain compensation decisions on our behalf, under the omnibus agreement. The compensation for all of our general partner’s executive officers is paid by Memorial Resource, and we reimburse Memorial Resource for costs and expenses incurred for our benefit or on our behalf pursuant to the terms of the omnibus agreement. See “Item 13. Certain Relationships and Related Transactions and Director Independence —Omnibus Agreement” for more information about the omnibus agreement.

Responsibility and authority for compensation-related decisions for executive officers and other personnel employed by our general partner resides with our general partner. Responsibility and authority for compensation-related decisions for executive officers and other personnel that are employed by Memorial Resource resides with Memorial Resource. Our general partner’s executive officers manage our business as part of the service provided by Memorial Resource under the omnibus agreement, and the compensation for all of our general partner’s executive officers is indirectly paid by our general partner through reimbursements to Memorial Resource. All determinations with respect to awards made under our long-term incentive plan to executive officers and other employees of our general partner and of Memorial Resource are made by the board of directors of our general partner, following the recommendation of Memorial Resource.

Each of our general partner’s named executive officers is also an executive officer of Memorial Resource, and we expect that our general partner’s named executive officers will devote a significant portion of their total business time to Memorial Resource and its operations. Compensation paid or awarded by us with respect to our general partner’s named executive officers reflects only the portion of Memorial Resource’s compensation expense allocated to us by Memorial Resource under the omnibus agreement. Memorial Resource has the ultimate decision-making authority with respect to the total compensation of its employees, including our general partner’s named executive officers, and (subject to the terms of the omnibus agreement) with respect to the portion of that compensation that is allocated to us. Any such compensation decision is not subject to any approval by the board of directors of our general partner.

Our general partner’s “named executive officers” for 2011 were:


Name		Principal Position
John A. Weinzierl		President, Chief Executive Officer, and Chairman
Andrew J. Cozby		Vice President and Chief Financial Officer
Larry R. Forney		Vice President, Operations and Asset Management
Patrick T. Nguyen		Chief Accounting Officer
Gregory M. Robbins		Treasurer

We and our general partner were formed in April 2011; therefore, we incurred no cost or liability with respect to compensation of our general partner’s named executive officers, nor did our general partner accrue any liabilities for incentive or retirement benefits for our named executive officers prior to that time. Other than the services our general partner’s executive officers provided to us in connection with our IPO, their activities in fiscal 2011 with respect to us were a minor consideration for Memorial Resource and the board of directors of our general partner in the determination of the compensation paid to such individuals.

Our Compensation Philosophy

Memorial Resource employs a compensation philosophy that emphasizes pay-for-performance (primarily, insofar as it relates to our partnership, the ability to increase sustainable quarterly distributions to unitholders)

based on a combination of our partnership’s performance and the individual’s impact on our partnership’s performance and placing the majority of each officer’s compensation at risk. We believe this pay-for-performance approach generally aligns the interests of executive officers who provide services to us with that of our unitholders, and at the same time enables us to maintain a lower level of base salary overhead in the event our operating and financial performance fails to meet expectations. Memorial Resource designs our general partner’s executive compensation to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders, and to reward success in reaching such goals.

Compensation Setting Process

In fiscal 2011, none of our general partner’s named executive officers devoted a significant portion of their time to our business. The portion of our general partner’s named executive officers’ salaries and bonuses incurred by Memorial Resource that was allocated to us, as reflected in the Summary Compensation Table below, was based on a reserve basis methodology for the period beginning on December 14, 2011, the date of the closing of our IPO, and ending on December 31, 2011.

As we develop as a publicly traded partnership, Memorial Resource will design a compensation program that emphasizes pay-for-performance. Memorial Resource may examine the compensation practices of our peer companies and may also review compensation information from the oil and gas industry generally to the extent we compete for executive talent from a broader group than our selected peer companies. As part of the compensation setting process, Memorial Resource may also review and participate in relevant compensation surveys and retain compensation consultants. Our general partner’s Chief Executive Officer will provide periodic recommendations to Memorial Resource regarding the compensation of our general partner’s other named executive officers.

Elements of Executive Compensation

As part of our general partner’s pay-for-performance approach to executive compensation, we expect that the future compensation of our general partner’s named executive officers will include a significant component of incentive compensation based on our performance. We expect that three primary elements of compensation will be used in our general partner’s executive compensation program—base salary, cash bonus and long-term equity incentive awards. Cash bonuses and equity incentives (as opposed to base salary) represent the performance driven elements of the compensation program. They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals’ cash bonuses will reflect their relative contribution to achieving or exceeding annual goals, and the determination of specific individuals’ long-term incentive awards will be based on their expected contribution in respect of longer term performance objectives. Incentive compensation in respect of services provided to us will not be tied in any material way to the performance of entities other than us and our subsidiaries. Specifically, any performance metrics will not be tied to the performance of Memorial Resource, the Funds or any other NGP affiliate.

Although we bear an allocated portion of the costs of compensation and benefits provided to the Memorial Resource employees who serve as our general partner’s named executive officers, we have no control over such costs, and we will not establish or direct the compensation policies or practices of Memorial Resource. Each of these executive officers continues to perform services for our general partner, as well as Memorial Resource and its affiliates.

Base Salary. We believe the base salaries for our general partner’s named executive officers are generally competitive within the master limited partnership market, but are moderate relative to base salaries paid by companies with which we compete for similar executive talent across the broad spectrum of the energy industry. We do not expect automatic annual adjustments to be made to base salary. Memorial Resource will review the

base salaries on an annual basis and may make adjustments as necessary to maintain a competitive executive compensation structure. As part of its review, Memorial Resource may examine the compensation of executive officers in similar positions with similar responsibilities at peer companies identified by Memorial Resource or the board of directors of our general partner or at companies within the oil and gas industry with which we generally compete for executive talent.

Bonus Awards. Annual bonus awards are discretionary. Certain of our general partner’s named executive officers received cash bonuses in December 2011 and a portion of these bonuses were allocated to us. We expect that annual bonuses will be determined based on financial and individual performance. We expect Memorial Resource to review bonus awards for our general partner’s named executive officers annually to determine award payments for the previous fiscal year, as well as to establish award opportunities for the current fiscal year. At the beginning of each fiscal year, we expect Memorial Resource to meet with each executive officer to discuss our performance goals for the year and what each executive officer is expected to contribute to help us achieve those performance goals. The determination of specific individuals’ cash bonuses will reflect their relative contribution to achieving or exceeding annual goals.

Long Term Incentive Compensation. Our general partner has adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan, or our LTIP, for employees, officers, consultants and directors of our general partner and any of its affiliates, including Memorial Resource, who perform services for us. Each of our general partner’s named executive officers is eligible to participate in our LTIP. Memorial Resource determines the overall amount of all long-term equity incentive compensation to be granted annually for its employees (including the officers and employees of our general partner). The portion of that compensation to be granted under our LTIP will be granted by our general partner’s board of directors following the recommendation of Memorial Resource. Our LTIP is administered by a plan administrator, which is currently the board of directors of our general partner.

Our LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under our LTIP is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. Our LTIP currently limits the number of common units that may be delivered pursuant to vested awards to 2,142,221 common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards.

On January 9, 2012, the board of directors of our general partner granted awards of restricted common units to our general partner’s named executive officers and independent director of our general partner as indicated in the following table:


Award Recipient	Number of Restricted Units
John A. Weinzierl		129,211
Andrew J. Cozby		21,053
Larry R. Forney		10,527
Patrick T. Nguyen		6,579
Gregory M. Robbins		6,579
Jonathan M. Clarkson		3,421

The awards were made pursuant to our LTIP and restricted unit agreements between our general partner and each award recipient. The awards are subject to restrictions on transferability and a substantial risk of forfeiture and are intended to retain and motivate members of our general partner’s management. Award recipients have all the rights of a unitholder in us with respect to the restricted units, including the right to receive distributions thereon if and when distributions are made by us to our unitholders (except with respect to the fourth quarter 2011 distribution that was paid on February 13, 2012). The restricted units vest and the forfeiture restrictions will lapse in substantially equal one-third increments on each of January 9, 2013, January 9, 2014 and January 9, 2015, so long as the award recipient remains in continuous service with our general partner and its affiliates.

If an award recipient’s service with our general partner or its affiliates is terminated prior to full vesting of the restricted units for any reason, then the award recipient will forfeit all unvested restricted units, except that, if an award recipient’s service is terminated either by our general partner (or an affiliate) without “cause” or by the award recipient for “good reason” (as such terms are defined in the restricted unit agreement) within one year following the occurrence of a change of control, all unvested restricted units will become immediately vested in full. If an award recipient’s service with our general partner or its affiliates is terminated by (i) our general partner with “cause” or (ii) by the award recipient’s resignation and engagement in “Competition” (as such term is defined in the restricted unit agreement) prior to full vesting of the restricted units, then our general partner has the right, but not the obligation, to repurchase the restricted units at a price per restricted unit equal to the lesser of (x) the fair market value of such restricted unit as of the date of the repurchase and (y) the price paid by the award recipient for such restricted unit.

On March 7, 2012, the board of directors of our general partner granted an award of 3,511 restricted common units to Mr. Highum pursuant to our LTIP and a restricted unit agreement between our general partner and Mr. Highum. The restricted units vest and the forfeiture restrictions will lapse in substantially equal one-third increments on each of March 7, 2013, March 7, 2014 and March 7, 2015, so long as Mr. Highum remains in continuous service with our general partner and its affiliates.

Severance and Change in Control Benefits. We do not provide any severance or change of control benefits to our general partner’s executive officers.

Other Benefits. Memorial Resource does not maintain a defined benefit pension plan for its executive officers, because it believes such plans primarily reward longevity rather than performance. Memorial Resource provides a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance. Memorial Resource employees who provide services to us under the omnibus agreement will be entitled to the same basic benefits.

Compensation Committee Report

The board of directors of our general partner does not have a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above. Based on this review and discussion, the board of directors of our general partner has approved the Compensation Discussion and Analysis for inclusion in this annual report.

The board of directors of Memorial Production Partners GP LLC

John A. Weinzierl

Jonathan M. Clarkson

Scott A. Gieselman

Kenneth A. Hersh

P. Michael Highum

Tony R. Weber

Employment Agreements

Neither Memorial Resource nor our general partner has entered, or currently intends to enter, into any employment agreements with any of our named executive officers.

Deductibility of Compensation

We believe that the compensation paid to our general partner’s named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership, and we do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Code. Accordingly, such limitations do not apply to compensation paid to our general partner’s named executive officers.

Relation of Compensation Policies and Practices to Risk Management

Memorial Resource’s compensation policies and practices are designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk-taking. Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessive risks to reach performance thresholds that qualify them for additional compensation.

From a risk management perspective, our policy is to conduct our commercial activities within pre-defined risk parameters that are closely monitored and are structured in a manner intended to control and minimize the potential for unwarranted risk-taking. We also routinely monitor and measure the execution and performance of our projects and acquisitions relative to expectations.

We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking unwarranted risk to achieve short-term, unsustainable results. Those elements include delaying the rewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our Code of Business Conduct and Ethics.

In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

Summary Compensation Table for 2011

The following table includes the compensation earned by our general partner’s named executive officers and allocated to us by Memorial Resource for the year ended December 31, 2011.


Name and Position	Year		Salary		Bonus		Total
John A. Weinzierl		2011	$	1,267	$	—	$	1,267
(President, Chief Executive Officer and Chairman)
Andrew J. Cozby		2011	$	3,168	$	21,823	$	24,991
(Vice President and Chief Financial Officer) (1)
Patrick T. Nguyen		2011	$	2,534	$	7,830	$	10,364
(Chief Accounting Officer)
Gregory M. Robbins		2011	$	2,534	$	8,023	$	10,557
(Treasurer)
Larry R. Forney		2011	$	3,168	$	11,040	$	14,208
(Vice President, Operations and Asset Management)

(1)	Mr. Cozby was appointed Chief Financial Officer in February 2012.

Grants of Plan-Based Awards

No grants of awards were made to our general partner’s named executive officers in 2011 under our long-term incentive plan.

Outstanding Equity Awards

There were no outstanding equity awards for our general partner’s named executive officers as of December 31, 2011.

Option Exercises and Stock Vested

No equity-based awards held by our general partner’s named executive officers vested or were exercised during 2011.

Pension Benefits

Currently, our general partner does not, and does not intend to, provide pension benefits to our general partner’s named executive officers. Memorial Resource may revisit this policy in the future.

Nonqualified Deferred Compensation

Currently, our general partner does not, and does not intend to, sponsor or adopt a nonqualified deferred compensation plan. Memorial Resource may revisit this policy in the future.

Potential Payments Upon Termination or Change in Control

Awards under our LTIP may vest and/or become exercisable, as applicable, upon a “change of control” of us or our general partner, as determined by the plan administrator. Under our LTIP, a “change of control” will be deemed to have occurred upon one or more of the following events (i) the directors of Memorial Resource appointed by the Funds or their affiliates do not constitute a majority of the board of directors of Memorial Resource; (ii) Memorial Resource, the Funds or any of its affiliates do not have the right to appoint or nominate a majority of the board of directors of our general partner; (iii) the members of our general partner approve and implement, in one or a series of transactions, a plan of complete liquidation of our general partner; (iv) the sale or other disposition by our general partner of all or substantially all of its assets in one or more transactions to any person or entity other than our general partner or an affiliate of our general partner or the Funds; or (v) a person or entity other than our general partner or an affiliate of our general partner or the Funds becomes the general partner of us. The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement. As of December 31, 2011, no awards were outstanding under our LTIP.

Director Compensation

Officers or employees of our general partner or its affiliates, including Memorial Resource, the Funds, and NGP, who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. No director compensation was paid in 2011. Each director who is not an officer or employee of our general partner or its affiliates receives compensation as a “non-employee director” for attending meetings of the board of directors, as well as committee meetings. For 2012, the following compensation has been approved for the non-employee directors:

•

an annual retainer of $65,000 for each director payable quarterly in arrears;

•

an annual equity grant under our LTIP of $65,000 of restricted units based on the price per common unit on the date of grant, which will vest equally over three years from the date of grant; and

•

an annual retainer of $7,500 for the chairman of the audit committee payable quarterly in arrears.

In addition, non-employee directors are reimbursed for all out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

Compensation Committee Interlocks and Insider Participation

As a limited partnership, we are not required by NASDAQ to establish a compensation committee. Although the board of directors of our general partner does not currently intend to establish a compensation committee, it may do so in the future.

100

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

As of March 16, 2012, the following table sets forth the beneficial ownership of our common and subordinated units that are owned by:

•

each person known by us to be a beneficial owner of more than 5% of our outstanding common units;

•

each director of our general partner;

•

each named executive officer of our general partner; and

•

all directors and named executive officers of our general partner as a group.


Name of Beneficial Owner (1)	Common Units Beneficially Owned (2)		Percentage of Common Units Beneficially Owned (3)			Subordinated Units Beneficially Owned		Percentage of Subordinated Units Beneficially Owned			Percentage of Total Common and Subordinated Units Beneficially Owned (1)
Memorial Resource (4)		7,061,294		41.93	%		5,360,912		100	%		55.95	%
Kenneth A. Hersh (5)		7,061,294		41.93	%		5,360,912		100	%		55.95	%
Jonathan M. Clarkson		10,921		*			—		—			*
Scott A. Gieselman		—		*			—		—			*
P. Michael Highum		3,511		*			—		—			*
Tony R. Weber		—		—			—		—			—
John A. Weinzierl (6)		234,474		1.39	%		—		—			1.06	%
Andrew J. Cozby		21,053		*			—		—			*
Larry R. Forney		10,527		*			—		—			*
Patrick T. Nguyen		7,079		*			—		—			*
Kyle N. Roane		—		—			—		—			—
Gregory M. Robbins		6,579		*			—		—			*
All named executive officers and directors as a group (eleven persons)		7,355,438		43.67	%		5,360,912		100	%		57.27	%

*	Less than 1.0%.

(1)	The address for all beneficial owners in this table is 1301 McKinney, Suite 2100, Houston, Texas 77010.

(2)	Includes common units purchased in the directed unit program at the closing of our IPO as well as restricted common units awards in January 2012.

(3)	Based on 16,838,664 common units and 5,360,912 subordinated units outstanding.

(4)

Memorial Resource is owned 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”), which also collectively directly own, through non-voting membership interests in our general partner, 50% of the economic interest in our incentive distribution rights. NGP VIII, NGP IX and NGP IX Offshore may be deemed to share voting and dispositive power over the reported securities; thus, each may also be deemed to be the beneficial owner of these securities. Each of NGP VIII, NGP IX and NGP IX Offshore disclaims beneficial ownership of the reported securities in excess of such entity’s respective pecuniary interest in the securities.

(5)

G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to beneficially own the units held by Memorial Resource that are attributable to NGP VIII, NGP IX and NGP IX Offshore by virtue of GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. (which is the general partner of NGP VIII) and GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the general partner of NGP IX and NGP IX Offshore). Kenneth A. Hersh, one of our general partner’s directors and an Authorized Member of each of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of those units. Mr. Hersh does not own directly any common units or subordinated units.

(6)	Includes 105,263 common units purchased in the directed unit program at the closing of our IPO by WCFB Interests, LP, a limited partnership which Mr. Weinzierl controls. Mr. Weinzierl disclaims beneficial ownership of the reported securities in excess of his pecuniary interest in such securities.

101

Memorial Production Partners GP LLC, our general partner, owns all of our incentive distribution rights and a 0.1% general partner interest in us. The following table sets forth the approximate beneficial ownership of equity interests in our general partner.


Name of Beneficial Owner	Class A Member Interest (1)			Class IDR Member Interest (1)
Memorial Resource (2)		100.0	%		—
Natural Gas Partners VIII, L.P.(3)(4)		—			50.3	%
Natural Gas Partners IX, L.P. (3)(4)		—			47.3	%
NGP IX Offshore Holdings, L.P. (3)(4)		—			2.4	%

(1)

Our general partner has two classes of member interests. Memorial Resource owns the voting Class A member interest, and will be entitled to 50% of any cash distributions made or common units issued to our general partner with respect to our general partner’s 0.1% general partner interest in us. NGP VIII, NGP IX and NGP IX Offshore own approximately 50.3%, 47.3% and 2.4%, respectively, of the non-voting Class IDR member interest in our general partner, which entitles them to an aggregate 50% of any cash distributions made or common units issued to our general partner.

(2)

Our general partner is controlled by Memorial Resource, which is controlled by NGP VIII, NGP IX and NGP IX Offshore. Mr. Hersh will share in distributions made by us with respect to interests held by our general partner in proportion to his pecuniary interests. Mr. Hersh disclaims beneficial ownership of the reported securities in excess of his pecuniary interest in such securities. In addition, our general partner’s other non-independent directors and certain of our general partner’s executive officers have indirect financial interests in Memorial Resource and its affiliates.

(3)

NGP VIII, NGP IX and NGP IX Offshore may be deemed to share voting and dispositive power over the reported interests of Memorial Resource; thus, each of NGP VIII, NGP IX and NGP IX Offshore may also be deemed to be the beneficial owner of these interests. Each of NGP VIII, NGP IX and NGP IX Offshore disclaims beneficial ownership of such reported interests in excess of such entity’s respective pecuniary interest in such interests. G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to beneficially own the interests owned by Memorial Resource attributable to NGP VIII, NGP IX and NGP IX Offshore and the interests held by NGP VIII, NGP IX and NGP IX Offshore by virtue of GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. (which is the general partner of NGP VIII) and GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the general partner of NGP IX and NGP IX Offshore). Kenneth A. Hersh, one of our general partner’s directors and an Authorized Member of each of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of the interests held by NGP VII, NGP IX and NGP IX Offshore. Mr. Hersh does not own directly any interests in our general partner.

(4)	The address for NGP VIII, NGP IX and NGP IX Offshore is 125 E. John Carpenter Fwy., Suite 600, Irving, Texas 75602.

Securities Authorized For Issuance Under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of December 31, 2011:

Plan Category

Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights

Weighted-average
exercise price of
outstanding options,
warrants and rights

Number of
securities remaining
available for future

issuance under equity
compensation plans

Equity compensation plans not approved by security holders (1):

Long-Term Incentive Plan

—

2,142,221

(1)	Our general partner adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan in December 2011 in connection with the completion of our IPO.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Memorial Resource controls our general partner and owns approximately 42% of our outstanding common units and all of our subordinated units. Memorial Resource owns 100% of the voting membership interests in our general partner, and the Funds own non-voting membership interests in our general partner that entitle them collectively to 50% of all cash distributions and common units received by our general partner in respect of our incentive distribution rights. As of March 16, 2012, our general partner owns a 0.1% general partner interest in us, evidenced by 22,222 general partner units, and all of our incentive distribution rights.

102

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with our formation and to be made in connection with our ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities before our IPO and, consequently, were not the result of arm’s-length negotiations.


*Formation Stage*

The consideration received by our general partner and Memorial Resource prior to or in connection with our IPO		• 7,061,294 common units; • 5,360,912 subordinated units; • 21,444 general partner units; • all of our incentive distribution rights; and • approximately $280 million in cash.
*Operational Stage*

Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 99.9% to our unitholders, including Memorial Resource as the holder of approximately 58.0% of our limited partner interests, pro rata and 0.1% to our general partner, assuming it makes any capital contributions necessary to maintain its 0.1% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 25.0% of the distributions above the highest target distribution level, including the general partner’s 0.1% general partner interest. Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of less than $0.1 million on its general partner units and Memorial Resource would receive an annual distribution of approximately $23.6 million on its common units and subordinated units.

Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner and its affiliates in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the amount of such expenses that are allocable to us.

103


Withdrawal or removal of our general partner		If our general partner is removed under circumstances where cause exists or withdraws and such withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and the incentive distribution rights for a cash payment equal to the fair market value of those interests. Under all other circumstances in which our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest in us and its incentive distribution rights for their fair market value or to convert such interests into common units.

*Liquidation Stage*

Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Purchase and Sale Agreement and Contribution, Conveyance and Assumption Agreements

On December 14, 2011, in connection with the closing of our IPO, we entered into a purchase and sale agreement and two contribution, conveyance and assumption agreements with Memorial Resource and certain of its subsidiaries that effected, among other things, the following transactions:

•

Memorial Resource caused certain of its subsidiaries to contribute a 100% membership interest in Columbus Energy LLC, a Delaware limited liability company, to us in exchange for the right to receive (i) 4,619,598 common units, (ii) 3,507,184 subordinated units and (iii) a distribution of approximately $132.6 million;

•

Memorial Resource caused one of its subsidiaries to sell certain oil and natural gas properties and related assets to us in exchange for the right to receive cash equal to approximately $71.0 million; and

•

Memorial Resource caused one of its subsidiaries to contribute certain oil and natural gas properties and related assets to ETX I LLC, a Delaware limited liability company (“ETX”), and then contribute a 100% membership interest in ETX to us in exchange for the right to receive (i) 2,441,696 Common Units, (ii) 1,853,728 Subordinated Units and (iii) a distribution of approximately $68.3 million.

Omnibus Agreement

On December 14, 2011, in connection with the closing of our IPO, we entered into an Omnibus Agreement (the “Omnibus Agreement”) with our general partner and Memorial Resource.

Under the Omnibus Agreement, none of the parties thereto nor any of their respective affiliates have any obligation to offer, or provide any opportunity to pursue, purchase or invest in, any business opportunity to any other party or their affiliates. Furthermore, the Omnibus Agreement does not restrict any of the parties thereto and their respective affiliates from competing with either Memorial Resource or our general partner and us.

Pursuant to the Omnibus Agreement, we are required to reimburse Memorial Resource for all expenses incurred by Memorial Resource (or payments made on our behalf) in conjunction with its provision of general

104

and administrative services to us, including, but not limited to, our public company expenses and an allocated portion of the salary and benefits of the executive officers of our general partner and other employees of Memorial Resource who perform services for us or on our behalf. We are also obligated to reimburse Memorial Resource for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage for the officers and directors of our general partner.

Pursuant to the Omnibus Agreement, Memorial Resource will indemnify our general partner and us against (i) title defects, (ii) income taxes attributable to pre-closing ownership or operation of the contributed assets described below, including any income tax liabilities related to the formation transactions occurring on or prior to the closing of our IPO, (iii) environmental claims, losses and expenses associated with the operation of our business prior to the closing of our IPO, subject to a maximum indemnification amount of $5,000,000, (iv) all liabilities other than covered environmental liabilities, relating to the operation of the contributed assets prior to the closing of our IPO that were not disclosed in the most recent pro forma balance sheet included in the prospectus for our IPO, or incurred in the ordinary course of business thereafter, subject to a maximum indemnification amount of $5,000,000, and (v) all losses arising as a result of the failure of Memorial Resource to obtain by closing of our IPO any consent, waiver or permit necessary for us to own and operate the assets contributed to us in connection with the closing of our IPO.

Memorial Resource’s indemnification obligation will (i) survive for three years after the closing of our IPO with respect to consents and title defects, (ii) survive for one year after the closing of our IPO with respect to environmental claims and other undisclosed pre-closing liabilities and (iii) survive for sixty days after the expiration of the applicable statute of limitations with respect to income taxes. All claims (other than income tax claims) are subject to a $50,000 per claim de minimus exception, environmental claims are subject to a $500,000 deductible, and claims relating to other pre-closing undisclosed liabilities, title or consents are subject to an aggregate $500,000 deductible.

Tax Sharing Agreement

On December 14, 2011, in connection with the closing of our IPO, we entered into a Tax Sharing Agreement (the “Tax Sharing Agreement”) with Memorial Resource pursuant to which we are required to reimburse Memorial Resource for our share of state and local income and other taxes borne by Memorial Resource as a result of our results being included in a combined or consolidated tax return filed by Memorial Resource or its affiliates with respect to periods after the closing of our IPO. Under the Tax Sharing Agreement, Memorial Resource may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we would nevertheless be required to reimburse Memorial Resource for the tax we would have owed had the attributes not been available or used for our benefit, even though Memorial Resource had no cash expense for that period.

Review, Approval or Ratification of Transactions with Related Persons

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that sets forth our policies for the review, approval and ratification of transactions with related persons. Pursuant to the Code of Business Conduct and Ethics, a director is expected to bring to the attention of the Chief Executive Officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with Memorial Resource’s and our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors, or the conflicts committee of our general partner’s board of directors. Our Code of Business Conduct and Ethics is available within the “Corporate Governance” section of our website at http://investor.memorialpp.com/governance.cfm.

105

Under the Code of Business Conduct and Ethics, any executive officer of our general partner is required to avoid conflicts of interest unless approved by the board of directors. The board of directors of our general partner has a conflicts committee comprised of at least one independent director. Our general partner may, but is not required to, seek the approval of the conflicts committee in connection with future acquisitions from (or other transactions with) Memorial Resource or any of its affiliates. In the case of any sale of equity or debt by us to Memorial Resource or any of its affiliates, we anticipate that our practice will be to obtain the approval of the conflicts committee for the transaction. The conflicts committee is entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner has sought the conflicts committee’s approval.

Memorial Resource and its affiliates is free to offer properties to us on terms it or they deem acceptable, and the board of directors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us by Memorial Resource or its affiliates. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production and reserve data, operating cost structure, current and projected cash flows, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas.

We expect that Memorial Resource and its affiliates will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed price for any assets it or they may offer to us in future periods. In addition to these factors, given that Memorial Resource is our largest unitholder and considering its and the Funds’ interest in our incentive distribution rights, it and they may consider the potential positive impact on their underlying investment in us by offering properties to us at attractive purchase prices. Likewise, it and they may consider the potential negative impact on their underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.

Director Independence

NASDAQ does not require a listed publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner. For a discussion of the independence of the board of directors of our general partner, please see “Item 10 — Directors, Executive Officers and Corporate Governance—Management.”

106

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The audit committee of the board of directors of our general partner selected KPMG LLP (“KMPG”), an independent registered public accounting firm, to audit our consolidated and predecessor combined financial statements for the year ended December 31, 2011. The audit committee’s charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to this annual report for the year ended December 31, 2011 were approved by the audit committee.

The following table summarizes the aggregate KPMG fees that were allocated to us and our predecessor for independent auditing, tax and related services for each of the last two fiscal years (dollars in thousands):


	2011		2010
Audit fees (1)	$	2,286	$	n/a
Audit-related fees (2)		n/a		n/a
Tax fees (3)		185		n/a
All other fees (4)		n/a		n/a

Total	$	2,471	$	n/a

(1)

Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. All of the audit fees related to our initial public offering. We accrued approximately $0.4 million for our 2011 annual audit.

(2)	Audit-related fees represent amounts billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews. No such services were rendered by KPMG during the years ended December 31, 2011 and 2010.

(3)	Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning.

(4)	All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above. No such services were rendered by KPMG during the years ended December 31, 2011 and 2010.

Audit Committee Approval of Audit and Non-audit Services

The audit committee of the board of directors of our general partner has adopted a pre-approval policy with respect to services which may be performed by KPMG. This policy lists specific audit-related services as well as any other services that KPMG is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee prior to engagement.

107

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

Our Consolidated and Predecessor Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” Page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(a)(3) 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).

4.1#	—	Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (Incorporated by reference to Exhibit 4.6 of the Partnership’s Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011).

10.1	—	Omnibus Agreement, dated as of December 14, 2011, by and among Memorial Production Partners LP, Memorial Production Partners GP LLC and Memorial Resource Development LLC (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

10.2	—	Tax Sharing Agreement, dated as of December 14, 2011, by and between Memorial Production Partners LP and Memorial Resource Development LLC (Incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

10.3	—	Credit Agreement, dated as of December 14, 2011, among Memorial Production Operating LLC, as borrower, Memorial Production Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, BNP Paribas, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (Incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

108


Exhibit Number		Description

10.4	—	Contribution, Conveyance and Assumption Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, BlueStone Natural Resource Holdings, LLC, BlueStone Natural Resources, LLC, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (Incorporated by reference to Exhibit 10.4 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

10.5	—	Purchase and Sale Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons Operating, LLC, Craton Energy Holdings III, LP, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (Incorporated by reference to Exhibit 10.5 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

10.6	—	Contribution, Conveyance and Assumption Agreement, dated as of December 14, 2011, by and among Memorial Resource Development LLC, WHT Energy Partners LLC, Memorial Production Partners GP LLC, Memorial Production Partners LP and Memorial Production Operating LLC (Incorporated by reference to Exhibit 10.6 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

10.7#	—	Memorial Production Partners GP LLC Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.7 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

21.1*	—	List of Subsidiaries of Memorial Production Partners LP.

23.1*	—	Consent of KPMG LLP.

23.2*	—	Consent of Netherland, Sewell & Associates, Inc.

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.

99.1*	—	Report of Netherland, Sewell & Associates, Inc.

*	Filed as an exhibit to this Annual Report on Form 10-K.

#	Management contract or compensatory plan or arrangement.

109

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: March 30, 2012	By:	/s/ Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Vice President and Chief Financial Officer of Memorial Production Partners GP LLC

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated.


Name	Title (Position with Memorial Production Partners GP LLC)	Date

/s/ John A. Weinzierl	President, Chief Executive Officer and Chairman (Principal Executive Officer)	March 30, 2012
John A. Weinzierl

/s/ Andrew J. Cozby	Vice President and Chief Financial Officer (Principal Financial Officer)	March 30, 2012
Andrew J. Cozby

/s/ Patrick T. Nguyen	Chief Accounting Officer (Principal Accounting Officer)	March 30, 2012
Patrick T. Nguyen	Chief Accounting Officer (Principal Accounting Officer)

/s/ Jonathan M. Clarkson	Director	March 30, 2012
Jonathan M. Clarkson

/s/ Scott A. Gieselman	Director	March 30, 2012
Scott A. Gieselman

/s/ Kenneth A. Hersh	Director	March 30, 2012
Kenneth A. Hersh

/s/ P. Michael Highum	Director	March 30, 2012
P. Michael Highum

/s/ Tony R. Weber	Director	March 30, 2012
Tony R. Weber

110

MEMORIAL PRODUCTION PARTNERS LP

INDEX TO FINANCIAL STATEMENTS


		Page No.
Report of Independent Registered Public Accounting Firm		F-2
Consolidated and Predecessor Combined Balance Sheets as of December 31, 2011 and 2010		F-3
Statements of Consolidated and Predecessor Combined Operations for the Years Ended December 31, 2011, 2010, and 2009		F-4
Statements of Consolidated and Predecessor Combined Cash Flows for the Years Ended December 31, 2011, 2010, and 2009		F-5
Statements of Consolidated and Predecessor Combined Equity for the Years Ended December 31, 2011, 2010, and 2009		F-6
Notes to Consolidated and Predecessor Combined Financial Statements
	Note 1 – Organization and Basis of Presentation	F-7
	Note 2 – Summary of Significant Accounting Policies	F-9
	Note 3 – Acquisitions and Divestitures	F-15
	Note 4 – Fair Value Measurements of Financial Instruments	F-18
	Note 5 – Risk Management and Derivative Instruments	F-20
	Note 6 – Asset Retirement Obligations	F-23
	Note 7 – Long Term Debt	F-23
	Note 8 – Equity & Distributions	F-24
	Note 9 – Earnings per Unit	F-29
	Note 10 – Equity-based Awards	F-29
	Note 11 – Related Party Transactions	F-30
	Note 12 – Commitments and Contingencies	F-31
	Note 13 – Defined Contribution Plan	F-32
	Note 14 – Subsequent Event	F-32
	Note 15 – Quarterly Financial Information (Unaudited)	F-33
	Note 16 – Supplemental Oil and Gas Information (Unaudited)	F-33

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Memorial Production Partners GP LLC and

Unitholders of Memorial Production Partners LP

We have audited the accompanying consolidated and predecessor combined balance sheets of Memorial Production Partners, L.P. (the “Partnership”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2011. These consolidated and predecessor combined financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States.) Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated and predecessor combined financial statements referred to above present fairly, in all material respects, the financial position of Memorial Production Partners LP as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated and predecessor combined financial statements, the balance sheet, and the related statements of operations, equity, and cash flows prior to December 14, 2011 have been prepared on a combined basis of accounting.

/s/ KPMG LLP

Dallas, Texas

March 30, 2012

F-2

MEMORIAL PRODUCTION PARTNERS LP

CONSOLIDATED AND PREDECESSOR COMBINED BALANCE SHEETS

(In thousands, except outstanding units)


	December 31,
	2011			2010
				(Predecessor)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,088		$	5,654
Accounts Receivable:
Oil and natural gas sales (Note 1)		—			6,175
Joint interest owners and other (Note 1)		—			3,848
Affiliates		2,955			—
Short-term derivative instruments		21,140			3,791
Prepaid expenses and other current assets		1,831			771

Total current assets		27,014			20,239
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		496,818			314,975
Other		—			2,553

		496,818			317,528
Accumulated depreciation, depletion and impairment		(96,156	)		(93,224	)

Oil and natural gas properties, net		400,662			224,304
Long-term derivative instruments		12,206			2,699
Other long-term assets		2,012			1,298

Total assets	$	441,894		$	248,540

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (Note 1)	$	—		$	8,482
Revenues payable (Note 1)		—			3,564
Accounts payable – affiliates		1,024			—
Accrued liabilities		2,032			3,874
Current portion of long-term debt		—			69
Short-term derivative instruments		346			109
Asset retirement obligations		—			25

Total current liabilities		3,402			16,123
Long-term debt		120,000			115,359
Asset retirement obligations		13,614			10,867
Long-term derivative instruments		1,040			109
Other long-term liabilities		670			281

Total liabilities		138,726			142,739
Commitments and contingencies (Note 12 )
Equity:
Partners’ equity:
Limited partners:
Common units (16,661,294 units outstanding at December 31, 2011)		241,034			—
Subordinated units (5,360,912 units outstanding at December 31, 2011)		61,708			—
General partner (22,044 units outstanding at December 31, 2011)		426			—

Total partners’ equity		303,168			—
Predecessor capital		—			105,801

Total equity		303,168			105,801

Total liabilities and equity	$	441,894		$	248,540

See Accompanying Notes to Consolidated and Predecessor Combined Financial Statements.

F-3

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND PREDECESSOR COMBINED OPERATIONS

(In thousands, except per unit amounts)


	For Year Ended December 31,
	2011			2010			2009
				(Predecessor)
Revenues:
Oil & natural gas sales	$	72,532		$	37,308		$	24,541
Other income		825			1,433			319

Total revenues		73,357			38,741			24,860

Costs and expenses:
Lease operating		22,507			13,974			11,207
Exploration		56			39			2,690
Production taxes		4,127			2,112			1,464
Depreciation, depletion, and amortization		24,341			20,066			15,226
Impairment of proved oil and natural gas properties		15,141			11,800			3,480
General and administrative		8,893			6,116			4,811
Accretion of asset retirement obligations		1,031			663			320
Gain on derivative instruments		(31,050	)		(10,264	)		(10,834	)
Gain on sale of properties		(63,024	)		(1	)		(7,851	)
Other, net		1,613			890			304

Total costs and expenses		(16,365	)		45,395			20,817

Operating income (loss)		89,722			(6,654	)		4,043
Interest expense		(7,268	)		(4,438	)		(2,937	)

Income (loss) before income taxes		82,454			(11,092	)		1,106
Income tax expense		(122	)		(225	)		—

Net income (loss)		82,332			(11,317	)		1,106
Net income (loss) attributable to predecessor		75,740			(11,317	)		1,106

Net income attributable to partners	$	6,592		$	—		$	—

Allocation of net income attributable to partners:
Limited partners	$	6,585		$	—		$	—

General partner	$	7		$	—		$	—

Earnings per unit: (see Note 9)
Basic and diluted earnings per unit	$	0.30		$	—		$	—

Weighted average limited partner units outstanding:
Basic and diluted		21,756			—			—

See Accompanying Notes to Consolidated and Predecessor Combined Financial Statements.

F-4

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND PREDECESSOR COMBINED CASH FLOWS

(In thousands)


	For Year Ended December 31,
	2011			2010			2009
				(Predecessor)
Cash flows from operating activities
Net income (loss)	$	82,332		$	(11,317	)	$	1,106
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		24,341			20,066			15,226
Impairment of proved oil and natural gas properties		15,141			11,800			3,480
Unrealized (gain) loss on derivatives		(22,463	)		(2,674	)		6,430
Premiums paid for derivatives		(2,847	)		—			—
Premiums received for derivatives		1,008			—			—
Deferred income tax expense		122			225			—
Amortization of loan origination costs		465			745			109
Accretion of asset retirement obligations		1,031			663			320
Gain on sale of properties		(63,024	)		(1	)		(7,851	)
Exploratory dry hole costs		56			39			2,690
Changes in operating assets and liabilities:
Accounts receivable		(6,400	)		(2,637	)		6,522
Accounts receivable – affiliates		(2,955	)		—			—
Prepaid expenses and other assets		(786	)		227			(729	)
Accounts payable		2,196			855			(12,597	)
Revenue payable		2,763			423			(1,171	)
Accrued liabilities		4,491			1,771			(842	)
Other		7			103			(21	)

Net cash provided by operating activities		35,478			20,288			12,672
Cash flows from investing activities:
Acquisition of oil and natural gas properties		(138,175	)		(104,542	)		(17,455	)
Additions to oil and gas properties		(22,381	)		(13,129	)		(19,034	)
Additions to other property and equipment		(327	)		(416	)		(210	)
Proceeds from the sale of oil and gas properties		2,378			1,400			11,752

Net cash used in investing activities		(158,505	)		(116,687	)		(24,947	)
Cash flows from financing activities:
Advances on revolving credit facility—Predecessor		85,918			115,106			11,948
Advances on revolving credit facility—Partnership		130,000			—			—
Payments on revolving credit facility—Predecessor		(201,346	)		(61,600	)		(12,749	)
Payments on revolving credit facility—Partnership		(10,000	)		—			—
Proceeds from borrowings of long-term debt		—			182			—
Repayment of borrowings of long-term debt		—			(44	)		(27	)
Loan origination fees—Predecessor		(934	)		(1,018	)		(489	)
Loan origination fees—Partnership		(2,544	)		—			—
Predecessor capital contributions		48,885			44,130			17,306
Proceeds from general partner contribution		419			—			—
Net cash proceeds from initial public offering (see Note 1)		146,460			—			—
Net cash proceeds from over-allotment option (see Note 1)		10,659			—			—
Distribution to Memorial Resource (see Note 1)		(73,557	)		—			—
Cash retained by Predecessor		(15,499	)		—			—

Net cash provided by financing activities		118,461			96,756			15,989
Net change in cash and cash equivalents		(4,566	)		357			3,714
Cash and cash equivalents, beginning of year		5,654			5,297			1,583

Cash and cash equivalents, end of year	$	1,088		$	5,654			5,297

Supplemental cash flows:
Cash paid for interest	$	5,278		$	4,309			2,677
Noncash investing and financing activities:
Purchase of fixed assets with note payable		—			—			117
Environmental remediation liability—net (see Note 12)		387			1,450			—
Fair value of assets acquired in excess of cash paid and net book value of properties transferred		68,945			—			—
Assumptions of asset retirement obligations relate to properties acquired		2,661			5,932			996

See Accompanying Notes to Consolidated and Predecessor Combined Financial Statements.

F-5

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND PREDECESSOR COMBINED EQUITY

(In thousands)


	Partner’s Equity
	Limited Partners						General Partner
	Common			Subordinated			General Partner		Predecessor			Total
Balance December 31, 2008	$	—		$	—		$	—	$	54,576		$	54,576
Net income		—			—			—		1,106			1,106
Predecessor capital contributions		—			—			—		17,306			17,306

Balance December 31, 2009		—			—			—		72,988			72,988
Net loss		—			—			—		(11,317	)		(11,317	)
Predecessor capital contributions		—			—			—		44,130			44,130

Balance December 31, 2010		—			—			—		105,801			105,801
Net income – January 1 to December 13		—			—			—		75,740			75,740
Predecessor capital contributions		—			—			—		48,885			48,885
Net assets retained by predecessor		—			—			—		(17,385	)		(17,385	)
Exchange of predecessor interests for units (Note 1)		121,101			91,940			—		(213,041	)		—
Deferred tax liability from initial public offering		(335	)		(111	)		—		—			(446	)
Net cash proceeds from initial public offering		146,460			—			—		—			146,460
Net cash proceeds from over-allotment option		10,659			—			—		—			10,659
Contributions from general partner		—			—			419		—			419
Distribution to Memorial Resource (Note 1)		(41,813	)		(31,744	)		—		—			(73,557	)
Net income – December 14 to December 31		4,962			1,623			7		—			6,592

Balance December 31, 2011	$	241,034		$	61,708		$	426	$	—		$	303,168

See Accompanying Notes to Consolidated and Predecessor Combined Financial Statements.

F-6

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO 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 Louisiana and Texas and consist of mature, legacy onshore oil and natural gas reservoirs. The Partnership’s properties consist of operated working interests in producing and undeveloped leasehold acreage and in identified producing wells and non-operated working interests in producing and undeveloped leasehold acreage.

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 GLP 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 securing revolving credit facility (see Note 7) and the net cash proceeds generated from our IPO. This dropdown transaction was

F-7

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

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. The Partnership acquired the following net assets of our predecessor:


Oil and natural gas properties, net	$	399,967
Short-term derivative instruments, net		15,779
Long-term derivative instruments, net		10,772
Asset retirement obligations		(13,560	)
Credit facilities—predecessor (2)		(198,267	)
Accrued liabilities		(1,650	)

Net assets (1)	$	213,041

(1)	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.

(2)

Although the Partnership did not legally assume the debt of its predecessor, for accounting and financial reporting purposes the $198.3 million that was repaid concurrent with the closing of our IPO on behalf of our predecessor has been netted against the net book value of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facility—predecessor.”

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 of these net proceeds were used to repay indebtedness under our revolving credit facility.

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 U.S. Securities and Exchange Commission (“SEC”).

BlueStone, a Delaware limited liability company, 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) have been included in these financial statements from that date forward. Prior to April 8, 2011, WHT did not have any oil and natural gas assets.

F-8

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

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 consolidated results of operations following the completion of our IPO (i.e., December 14, 2011 through December 31, 2011) are presented together with the combined results of operations pertaining to our predecessor. 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 all periods presented and the WHT Assets for the periods from the acquisition date of April 8, 2011 through December 31, 2011.

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.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and predecessor combined financial statements. The accompanying consolidated and predecessor combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments necessary for a fair presentation of the financial statements have been made. Certain amounts in the prior year financial statements have been reclassified to conform with the presentation in the current year financial statements.

Note 2. Summary of Significant Accounting Policies

Use of Estimates

The preparation of 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 consolidated and predecessor 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.

Principles of Consolidation and Combination

The predecessor combined financial statements include the accounts of BlueStone and its wholly owned subsidiaries as well as the accounts of Classic Carve-Out for the periods presented. The WHT Assets are

F-9

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

included in the predecessor combined financial statements from the acquisition date of April 8, 2011 forward. All material intercompany balances and transactions have been eliminated. Likewise, effective with the closing of our IPO, our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions.

Cash and Cash Equivalents

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

Concentrations of Credit Risk

Cash balances, accounts receivable and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Derivative financial instruments are generally executed with major financial institutions that expose our predecessor and us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We and our predecessor relied upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor have experienced any losses from such instruments.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2011 and 2010, respectively.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. However, if one or more of the our larger customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a detrimental effect on production volumes in general and on the ability to find substitute customers to purchase production volumes.

Oil and Natural Gas Properties

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

F-10

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. The timing of any write downs of unproven properties, if warranted, depends upon the nature, timing, and extent of planned exploration and development activities and their results.

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

The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended (in thousands):


	2011			2010			2009
Balance, January 1	$	2,013		$	821		$	1,468
Additions to capitalized exploratory well costs pending determination of proved reserves		701			2,013			821
Capitalized exploratory well costs asset exchange (1)		(2,714	)
Reclassification to proved oil and natural gas properties based on the determination of proved reserves		—			(821	)		—
Capitalized exploratory well costs charged to expense		—			—			(1,468	)

Balance, December 31	$	—		$	2,013		$	821

(1)	Our predecessor acquired interest in wells located in South Texas from BP America Production Company in exchange for acreage and cash. Capitalized exploratory well costs were part of this exchange transaction. See Note 3 for further information regarding this transaction.

Oil and Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and predecessor combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). In January 2010, the FASB updated its oil and gas estimation and disclosure requirements to align its requirements with the requirements of the modernized oil and gas reporting rules released by the SEC on December 31, 2008. These rules, which became effective during 2009, require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates for all periods presented were prepared by a third-party petroleum engineer.

F-11

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Other Property & Equipment

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

Impairments

Asset Retirement Obligations

Other Long-Term Assets

Other long-term assets consist of deposits and deferred financing costs associated with the credit facilities. Deferred financing costs are stated at cost, net of amortization, and are amortized over the terms of the credit facilities. Amortization expense for the years ended December 31, 2011, 2010, and 2009 was approximately $0.5 million, $0.7 million, and $0.1 million, respectively.

Revenue Recognition

Revenue from the sale of oil and natural gas and oil is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2011 or 2010.

F-12

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

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


	Years Ending December 31,
	2011			2010			2009
Major customers: (1)
Enterprise Texas Pipeline, LLC		20	%		31	%		32	%
Dominion Gas Ventures, LP		15	%		25	%		43	%
ConocoPhillips		13	%		11	%		(2	)

(1)	Collectively, these major customers purchased production pursuant to existing marketing agreements with terms that are currently on “evergreen” status and renew on a month-to-month basis until either party gives 30-day advance written notice of non-renewal.

(2)	This customer accounted for less than 10% of total revenue for the period indicated.

General and Administrative Expense

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 allocates general and administrative costs based on the relative size of our proved and probable reserves in comparison to Memorial Resource’s total 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. See Note 11 for additional information in regards to the omnibus agreement.

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.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statements of operations. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting treatment. There were no derivatives designated as hedges for financial accounting purposes at December 31, 2011 or 2010.

Changes in the fair value of derivative financial instruments that do not qualify for accounting treatment as hedges are recognized currently in the statements of operations.

Income Tax

We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. Likewise, our predecessor entities were not taxpaying entities for federal income tax purposes and their partners or members were responsible for federal income taxes on their share of our predecessor’s taxable income.

F-13

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

We, along with our predecessor entities, are subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin. Deferred taxes related to Texas margin tax arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Deferred tax liabilities as of December 31, 2011 were approximately $0.4 million and total tax expense for the year was approximately $0.1 million. Deferred tax liabilities and tax expense as of and for the year ended December 31, 2010 was approximately $0.2 million. There were no deferred taxes at December 31, 2009 and no tax expense recorded for the year ended December 31, 2009. There were no uncertain tax positions that required recognition in the financial statements at December 31, 2011 or 2010.

Earnings Per Unit

Our partnership agreement contains incentive distribution rights. Accordingly, the amount of net income or loss used in the determination of earnings per unit (“EPU”) for the period from December 14, 2011 to December 31, 2011 is reduced by the amount of available cash that will be distributed to the limited partners, the general partner and the holders of the incentive distribution rights for that corresponding period. The undistributed earnings, if any, are then allocated to the limited partners, the general partner and the holders of the incentive distribution rights in accordance with the terms of the partnership agreement. Basic and diluted EPU is determined by dividing net income or loss available to the limited partners, after deducting the amount allocated to the general partner and the holders of the incentive distribution rights, by the weighted average number of outstanding limited partner units during the period from December 14, 2011 to December 31, 2011. Basic and diluted EPU are equivalent, as all subordinated units participate in distributions. See Note 9 for additional information.

Equity Compensation

The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Awards subject to performance criteria vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 10 for further information.

New Accounting Pronouncements

Fair Value Measurements. 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. We will adopt this guidance on January 1, 2012 and apply its requirements prospectively at that time. We do not believe the adoption of this guidance will have a material impact on our financial statements.

Offsetting Disclosure Requirements. In December 2011, the FASB issued an accounting standard update intended to enhance current disclosure requirements on offsetting financial assets and liabilities. The new disclosure requirements will require the disclosure of both gross and net information about instruments and transactions eligible for offset in the balance sheet as well as instruments and transactions subject to an agreement similar to a master netting arrangement. Disclosure of collateral received and posted in connection with master netting agreements or similar arrangements is also required. The disclosures will be effective or annual and interim periods beginning on or after January 1, 2013, and must be applied retrospectively. We do not believe adoption of this new guidance will have a significant impact on our financial statements.

F-14

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 3. Acquisitions and Divestitures

The acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, 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.

2011 Acquisitions

Effective January 1, 2011, our predecessor acquired BP America Production Company’s (“BP”) interests in wells located in Duval, Jim Hogg, McMullen and Webb counties located in 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 and $20 million in cash, subject to certain closing adjustments. The transaction closed on May 31, 2011 and our predecessor paid a total of approximately $12.9 million in cash consideration at closing, net of adjustments.

The 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. After taking into consideration the net book value of the Nueces Field properties exchanged to BP of $5.2 million and the $12.9 million in cash consideration paid at closing, our predecessor recorded a $62.2 million gain during the year ended December 31, 2011.

On April 8, 2011, our predecessor acquired producing oil and natural gas properties in East Texas (the “Carthage Properties”) from a third party. Our predecessor estimated that as of April 8, 2011, the fair value of the Carthage Properties acquired was approximately $120.8 million, which our predecessor considered to be representative of the price paid by a typical market participant. The following table summarizes our predecessor’s consideration paid for the Carthage Properties and the fair value of the assets acquired and liabilities assumed as of April 8, 2011 (dollars in thousands):


*Consideration paid for Carthage Properties:*
Cash	$	118,268
Liabilities assumed		2,512

Total consideration	$	120,780

*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 years ended December 31, 2011 and 2010, on an unaudited pro forma basis, as if the BP and Carthage Properties acquisitions had occurred on January 1, 2010.

F-15

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

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.


	2011				2010
	Actual		Pro Forma		Actual			Pro Forma
	(In thousands)				(In thousands)
*BP and Carthage Properties:*
Revenues	$	73,357	$	86,115	$	38,741		$	82,307
Net income (loss)	$	82,332	$	24,252	$	(11,317	)	$	6,884

During the year ended December 31, 2011, approximately $8.3 million and $17.1 million of revenue and $2.3 million and $11.4 million of earnings were recorded in the statement of operations related to the BP and Carthage Properties acquisitions subsequent to their respective closing dates.

Effective July 1, 2011, our predecessor acquired producing oil and natural gas properties in Webb and Zapata counties located in South Texas. The net purchase price of $2.25 million was allocated to oil and natural gas properties. The acquisition closed on June 30, 2011.

Approximately $1.0 million of acquisition costs related to the 2011 acquisitions is included in other expense in the accompanying statements of operations for the year ended December 31, 2011.

2010 Acquisitions

Effective January 1, 2010, our predecessor acquired producing oil and natural gas properties in East Texas from Petrohawk Properties, LP for approximately $5.8 million. The net purchase price was allocated $5.8 million to proved oil and gas properties. The acquisition closed on May 28, 2010.

Effective March 1, 2010, our predecessor acquired oil and natural gas properties in East Texas from BP for approximately $8.2 million. The net purchase price was allocated to proved oil and gas properties. This acquisition closed on March 29, 2010.

Effective April 1, 2010, our predecessor acquired Forest Oil’s interests in wells located in Webb County, Texas (the “Forest Oil Properties”) for a net purchase price of approximately $65.9 million. The net purchase price was allocated to oil and gas properties. This acquisition of properties closed on June 30, 2010. Summarized below are the results of operations for the years ended December 31, 2010 and 2009, on an unaudited pro forma basis, as if this acquisition had occurred on January 1, 2009. The unaudited pro forma financial information was derived from the historical combined statement of operations of our predecessor and the statements of revenues and direct operating expenses for the Forest Oil Properties, which were derived from the historical accounting records of the seller. 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.


	2010						2009
	Actual			Pro Forma			Actual		Pro Forma
	(In thousands)						(In thousands)
*Forest Oil Properties:*
Revenues	$	38,741		$	47,409		$	24,860	$	41,131
Net income (loss)	$	(11,317	)	$	(5,506	)	$	1,106	$	11,631

F-16

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Effective May 1, 2010, the Predecessor acquired Merit Energy’s (“Merit”) interest in wells located in South Texas for a net purchase price of approximately $14.1 million. The net purchase price was allocated as follows (in thousands):


Oil and gas properties	$	15,397
Prepaid assets		450
Assumed liabilities		(1,728	)

Net purchase price	$	14,119

As part of the acquisition process, an environmental review was performed and it was determined that there was environmental damage to one of the acquired properties. As such, the parties agreed to reduce the purchase price by $550 thousand. Additionally, our predecessor and Merit entered into an escrow agreement whereby our predecessor agreed to pay for the initial $1.0 million of the remediation costs, with Merit paying for gross amounts incurred in excess of $1.0 million and up to $1.5 million. Our predecessor’s anticipated cost to remediate this area is $1.5 million. As of December 31, 2010, our predecessor recorded an accrued liability of $1.5 million for the anticipated costs to remediate this area. Merit funded an escrow account with the $0.5 million and that amount is included in the balance sheet as a prepaid asset. This acquisition closed on June 4, 2010. As of December 31, 2011, approximately $0.7 million of costs have been incurred and the approximately $0.8 million of remaining environmental accrued liability is recorded as a current liability in accrued liabilities.

Effective May 1, 2010, our predecessor acquired Zachry Exploration, LLC’s interest in Laredo area properties for a net purchase price of $6.5 million. The net purchase price was allocated to oil and gas properties. This acquisition closed on August 3, 2010.

Effective April 1, 2010, our predecessor acquired U.S. Enercorp, LTD’s interest in wells located in McMullen County, Texas for a net purchase price of approximately $2.6 million. The net purchase price was allocated to oil and gas properties. This acquisition closed on May 28, 2010.

Our predecessor also acquired interests in oil and gas properties in a number of individually insignificant acquisitions during 2010 which aggregated to a total of approximately $6.0 million. Approximately $0.9 million of acquisition costs related to the 2010 acquisitions is included in other expense in the accompanying statements of operations for the year ended December 31, 2010.

2009 Acquisitions

Effective February 1, 2009, our predecessor acquired Coronado Energy E&P Company, LLC’s interest in Laredo area properties for a net purchase price of approximately $13.0 million. The net purchase price was allocated to oil and gas properties. This acquisition closed on March 16, 2009.

Our predecessor also acquired interests in oil and gas properties in a number of individually insignificant acquisitions during 2009, which aggregated to a total of approximately $3.8 million. Approximately $0.3 million of acquisition costs related to the 2009 acquisitions is included in other expense in the accompanying statements of operations for the year ended December 31, 2009.

Divestitures

During August 2011, our predecessor sold working interests related to the deep rights under approximately 4,200 acres in Webb County located in South Texas and options related to an additional 9,000 acres of deep rights in Webb County. Total cash consideration received by our predecessor in August 2011 was approximately

F-17

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

$2.0 million, and a $0.8 million gain on the sale of properties was recognized for the year ended December 31, 2011 in the statement of operations. In November 2011, one of the options related to a portion of the 9,000 acres of deep rights was exercised for approximately $0.4 million of cash. No significant gain or loss was recognized related to this option exercise. The transactions did not involve the sale of any existing production.

On January 20, 2010, our predecessor sold its interests in the Saner wells for net proceeds of approximately $1.4 million. There was no significant gain or loss associated with this sale. In addition, during 2010, our predecessor received a settlement of approximately $1.2 million related to a property that our predecessor had not been given the opportunity to acquire despite a preferential right to acquire the property held by our predecessor. This settlement amount has been recorded in other income for the year ended December 31, 2010.

Effective January 8, 2009, our predecessor sold a portion of its interests in the Nueces Mineral Company lease (“NMC Lease”) for net proceeds of $2.7 million. Our predecessor sold additional interests in the NMC Lease effective May 1, 2009 for net proceeds of $9.0 million. Our predecessor recorded gains on these sales of approximately $7.8 million.

Note 4. Fair Value Measurements of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). 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 December 31, 2011 and 2010, all of the derivative instruments reflected on the accompanying balance sheet 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 December 31, 2011 and 2010. These assets and liabilities are not presented in the following tables.

F-18

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

The fair market values of the derivative financial instruments reflected in the balance sheets as of December 31, 2010 were based on quotes obtained from the counterparties to the agreements, whereas the fair market values of the derivative financial instruments reflected in the balance sheets as of 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 December 31, 2011 and 2010 for each of the fair value hierarchy levels:


	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	$	—	$	35,829	$	—	$	35,829

Liabilities :
Commodity derivatives	$	—	$	3,591	$	—	$	3,591
Interest rate derivatives		—		278		—		278

Total liabilities	$	—	$	3,869	$	—	$	3,869


	Fair Value Measurements at December 31, 2010 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	$	—	$	7,153	$	—	$	7,153

Liabilities :
Commodity derivatives	$	—	$	478		—		478
Interest rate derivatives		—		403		—		403

Total liabilities	$	—	$	881	$	—	$	881

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.

F-19

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 5. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These 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. Had our counterparties failed to perform under existing derivative contracts, the maximum loss at December 31, 2011 would be approximately $32.2 million.

Commodity Derivatives

A combination of commodity derivatives (e.g., floating-for-fixed swaps, collars, put options, and basis swaps) is used to manage exposure to commodity price volatility. At December 31, 2011, we had the following open commodity positions:

Natural Gas — Swaps

Period Covered

Index

Average Monthly
Volume (MMBtu)

Weighted Average
Fixed Price ($)

1/1/2012

12/31/2012

Houston Ship Channel

80,000

4.84

1/1/2012

12/31/2012

NGPL TXOK

33,000

6.31

1/1/2012

12/31/2012

NYMEX (Henry Hub)

154,498

4.42

1/1/2012

12/31/2012

TETCO STX

60,000

5.51

1/1/2013

12/31/2013

Houston Ship Channel

80,000

4.84

1/1/2013

12/31/2013

NGPL TXOK

21,000

6.58

1/1/2013

12/31/2013

NYMEX (Henry Hub)

280,052

4.18

1/1/2013

12/31/2013

TETCO STX

40,000

5.34

1/1/2014

12/31/2014

NYMEX (Henry Hub)

742,740

4.44

1/1/2015

12/31/2015

NYMEX (Henry Hub)

781,578

4.44

1/1/2016

12/31/2016

NYMEX (Henry Hub)

865,165

4.70

Natural Gas — Basis Swaps

Period Covered

Floating Index 1

Floating Index 2

Average Monthly
Volume (MMBtu)

Spread ($)

1/1/2012

12/31/2012

NYMEX(Henry Hub)

NGPL TXOK

22,899

(0.1050

)

1/1/2012

12/31/2012

NYMEX(Henry Hub)

TETCO STX

330,734

(0.1450

)

1/1/2013

12/31/2013

NYMEX(Henry Hub)

NGPL TXOK

31,644

(0.1050

)

1/1/2013

12/31/2013

NYMEX(Henry Hub)

TETCO STX

337,208

(0.1650

)

1/1/2013

12/31/2013

NYMEX(Henry Hub

Houston Ship Channel

37,080

(0.1075

)

F-20

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS


Natural Gas — Collars
Period Covered		Index	Average Monthly Volume (MMBtu)		Weighted Average Floor Price ($)		Weighted Average Ceiling Price ($)
1/1/2012	12/31/2012	Houston Ship Channel		140,000		4.28		5.65
1/1/2012	12/31/2012	NGPL TXOK		75,000		5.49		6.57
1/1/2012	12/31/2012	NYMEX (Henry Hub		204,500		4.98		5.74
1/1/2012	12/31/2012	TETCO STX		200,000		4.68		6.03
1/1/2013	12/31/2013	Houston Ship Channel		95,000		4.23		5.68
1/1/2013	12/31/2013	NGPL TXOK		69,000		4.87		6.15
1/1/2013	12/31/2013	NYMEX (Henry Hub		148,000		5.00		6.01
1/1/2013	12/31/2013	TETCO STX		280,000		4.76		5.70
1/1/2014	12/31/2014	NYMEX (Henry Hub		120,000		5.08		6.31
1/1/2015	12/31/2015	NYMEX (Henry Hub		80,000		5.25		6.75

Natural Gas — Put Options

Period Covered

Index

Average Monthly
Volume (MMBtu)

Strike Price ($)

1/1/2012

12/31/2012

TETCO STX

70,000

4.80

Oil — Collars

Period Covered

Index

Average Monthly
Volume (Bbls)

Weighted Average
Floor Price ($)

Weighted Average
Ceiling Price ($)

1/1/2012

12/31/2012

NYMEX WTI

3,900

89.23

118.64

1/1/2013

12/31/2013

NYMEX WTI

4,750

87.16

116.94

1/1/2014

12/31/2014

NYMEX WTI

3,200

90.00

117.72

Oil — Swaps

Period Covered

Index

Average Monthly
Volume (MMBtu)

Weighted Average
Fixed Price ($)

1/1/2012

12/31/2012

NYMEX WTI

1,790

92.00

1/1/2013

12/31/2013

NYMEX WTI

1,540

92.00

1/1/2014

12/31/2014

NYMEX WTI

2,250

87.90

Natural Gas Liquids (“NGL”) — Collars

Period Covered

Product

Index

Average Monthly
Volume (Bbls)

Weighted Average
Floor Price ($)

Weighted Average
Ceiling Price ($)

1/1/2012

12/31/2012

Propane

OPIS Mt. Belvieu

1,200

52.50

66.78

1/1/2012

12/31/2012

Normal Butane

OPIS Mt. Belvieu

600

71.40

86.10

1/1/2012

12/31/2012

Iso-Butane

OPIS Mt. Belvieu

400

71.40

89.04

1/1/2012

12/31/2012

Pentane

OPIS Mt. Belvieu

1,600

94.50

117.60

Interest Rate Swaps

Period Covered

Notional

($ in thousands)

Floating Rate

Fixed Rate

1/17/2012

1/16/2013

$100,000

1 Month LIBOR

0.600

1/17/2013

12/14/2016

$100,000

1 Month LIBOR

1.305

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. Our predecessor did not novate this interest rate swap to us since we did not assume any

F-21

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

of our predecessor’s debt at the closing of our IPO. 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.

The interest rate swaps are not designated as hedges for financial accounting purposes. All gains and losses, including unrealized gains and losses related to the change in the interest rate swaps fair value, have been recorded in interest expense, net in the statements of operations for all periods presented.

Balance Sheet Presentation

The following table summarizes 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 the net recorded fair value as reflected on the balance sheet at December 31:


		Asset Derivatives						Liability Derivatives
Type	Balance Sheet Location	2011			2010			2011			2010
		(In thousands)
Natural gas contracts	Short-term derivative instruments	$	21,001		$	4,120		$	44		$	79
Oil contracts	Short-term derivative instruments		83			—			250			81
NGL contracts	Short-term derivative instruments		166			—			—			—
Interest rate swaps	Short-term derivative instruments		—			—			162			153

Gross fair value			21,250			4,120			456			313
Netting arrangements	Short-term derivative instruments		(110	)		(329	)		(110	)		(204	)

Net recorded fair value	Short-term derivative instruments	$	21,140		$	3,791		$	346		$	109

Natural gas contracts	Long-term derivative instruments	$	14,147		$	3,033		$	3,034		$	209
Oil contracts	Long-term derivative instruments		432			—			263			109
NGL contracts	Long-term derivative instruments		—			—			—			—
Interest rate swaps	Long-term derivative instruments		—			—			116			250

Gross fair value			14,579			3,033			3,413			568
Netting arrangements	Long-term derivative instruments		(2,373	)		(334	)		(2,373	)		(459	)

Net recorded fair value	Long-term derivative instruments	$	12,206		$	2,699		$	1,040		$	109

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 years ending December 31, 2011, 2010 and 2009:


	Statements of Operations Location	Years Ended December 31,
	Statements of Operations Location	2011			2010			2009
		(In thousands)
Commodity derivative contracts (1)	Gain on derivatives	$	31,050		$	10,264		$	10,834
Interest rate swaps (2)	Interest expense		(1,261	)		(576	)		(165	)

(1)	Included in these amounts are net cash receipts of approximately $7.8, $7.3 and $17.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.

(2)	Included in the amounts are net cash payments of approximately $0.5, $0.3 and $0.5 million for the years ended December 31, 2011, 2010 and 2009, respectively.

F-22

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 6. Asset Retirement Obligations

The fair value of our asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties has been recognized. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets. The liability has been accreted to its present value as of December 31, 2011 and 2010. Our wells have been evaluated and abandonment dates extend through 2061.

The following table represents a reconciliation of the asset retirement obligations for the years ended December 31, 2011, 2010, and 2009:


	2011			2010			2009
	(In thousands)
Asset retirement obligations at beginning of year	$	10,892		$	3,806		$	3,342
Liabilities added from acquisitions or drilling		3,057			7,116			996
Liabilities removed upon sale of wells		(64	)		(19	)		(124	)
Accretion expense		1,031			663			320
Revision of estimates		(468	)		(674	)		(728	)
Liabilities retained by our predecessor		(834	)		—			—

Asset retirement obligations at end of year	$	13,614		$	10,892		$	3,806

Note 7. Long Term Debt

Revolving Credit Facility

Concurrently with the closing of our IPO on December 14, 2011, OLLC entered into a new senior secured revolving credit facility, which facility is guaranteed by us and all of our current and future subsidiaries. This revolving credit facility is a five-year, $1.0 billion revolving credit facility with an initial borrowing base of $300.0 million. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base.

Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of the our oil and natural gas properties, and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings under our revolving credit facility bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

F-23

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness.

Events of default under our revolving credit facility include the failure to make payments when due, breach of any covenants continuing beyond the cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on the business of OLLC or us.

As of December 31, 2011, we were in compliance with all of the financial and other covenants under our revolving credit facility. At December 31, 2011, we had $120.0 million outstanding under the facility. The effective weighted average interest rate for the period from December 14, 2011 through December 31, 2011 was 2.81%.

Predecessor

Our predecessor had debt outstanding under three separate revolving credit facilities, none of which was assumed by us in connection with our IPO. Although the Partnership did not legally assume the debt of its predecessor, for accounting and financial reporting purposes the $198.3 million that was repaid concurrent with the closing of our IPO on behalf of our Predecessor (see Note 1) has been netted against the net book value of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facility—predecessor.” At December 31, 2010, $80.2 million was outstanding under BlueStone’s $150.0 million revolving credit facility. BlueStone also had $0.4 million in letters of credit outstanding under its credit facility. The weighted average interest rate for the years ended December 31, 2011, 2010 and 2009 was approximately 3.17%, 3.45% and 4.88%, respectively. At December 31, 2010, BlueStone was in compliance with its debt covenants.

The Classic Carve-Out properties were burdened by debt incurred pursuant to a $150.0 million revolving credit facility extended to Classic. Of the $105.0 million outstanding under this facility at December 31, 2010, $35.1 million pertained to the Classic Carve-Out properties. The weighted average interest rate for the years ended December 31, 2011, 2010 and 2009 was 3.40%, 3.11% and 3.60%, respectively. At December 31, 2010 Classic was in compliance under existing debt covenants.

The WHT Assets were burdened by debt incurred pursuant to a $400.0 million revolving credit facility extended to WHT on April 8, 2011, of which $160.0 million pertained to the WHT assets. The borrowing base was $230.0 million, of which $92 million pertained to the WHT assets. The weighted average interest rate for the period from April 8, 2011 through the closing of our IPO was 2.79%.

Note 8. Equity and Distributions

Initial Public Offering of Memorial Production Partners LP

On December 14, 2011, we completed our IPO of 9,000,000 common units representing limited partner interests in the Partnership at $19.00 per common unit for total net proceeds of approximately $146.5 million. In connection with our IPO, 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 (see Note 1). The cash portion of this consideration was financed with approximately $130.0 million in borrowings under a new senior

F-24

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

securing revolving credit facility (see Note 7) and the net cash proceeds generated from our IPO. As previously noted above, Memorial Resource used $198.3 million of the $271.8 million cash distribution it received from us at the closing of our IPO to repay indebtedness under our predecessor’s revolving credit facilities.

On December 22, 2011, the underwriters exercised their over-allotment option to purchase an additional 600,000 common units issued by the Partnership under the IPO terms. Total net proceeds from the exercise of the underwriters’ over-allotment option, after deducting estimated offering costs, were $10.7 million.

Equity Outstanding

Upon completion of our IPO and the underwriters’ exercise of their over-allotment option, we had 16,661,294 common units, 5,360,912 subordinated units and 22,044 general partner units outstanding. Following our IPO and the underwriters’ exercise of their over-allotment option, Memorial Resource owned approximately 42.4% of the common units and 100% of the subordinated units. Memorial Resource owns all of the voting interests in our general partner, and the Funds own non-voting membership interests in our general partner that entitle them collectively to 50% of all cash distributions and common units received by our general partner in respect of the Partnership’s incentive distribution rights.

Common & Subordinated Units. The common units and the subordinated units are separate classes of limited partner interest in us and have limited voting rights as set forth in our partnership agreement. The holders of units are entitled to participate in partnership distributions as discussed further below under Cash Distribution Policy and exercise the rights or privileges available to limited partners under our partnership agreement.

Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement.

General Partner Interest. Our general partner owns a 0.1% interest in us. This interest entitles our general partner to receive distributions of available cash from operating surplus as discussed further below under “Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders, and general partner will receive. The general partner has the management rights as set forth in our partnership agreement.

Allocations of Net Income

Net income is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership during the period.

Cash Distribution Policy

Available Cash. Our partnership agreement requires that within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we distribute all of our available cash (as defined in our partnership agreement) to our general partner and unitholders of record on the applicable record date. Generally,

F-25

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

available cash refers to all cash on hand at the end of the quarter less cash reserves established by our general partner to: (i) operate our business (e.g., future capital expenditures, working capital and operating expenses); (ii) comply with applicable law, debt, and other agreements; and (iii) provide funds for distribution to our unitholders (including our general partner) for any one or more of the next four quarters. If our general partner so determines, available cash may include borrowings made after the end of the quarter.

General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 0.1% of all distributions of available cash that we make prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner also holds the incentive distribution rights, which entitle the holder to additional increasing percentages, up to a maximum of 24.9%, of the cash we distribute in excess of $0.59375 per common unit per quarter.

Minimum Quarterly Distribution. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages in the table below.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:


	Total Quarterly Distributions Target Amount	Marginal Percentage Interest in Distributions
	Total Quarterly Distributions Target Amount	Unitholders	General Partner
Minimum Quarterly Distribution	$0.4750	99.9%	0.1%
First Target Distribution	up to $0.54625	99.9%	0.1%
Second Target Distribution	above $0.54625 up to $0.59375	85.0%	15.0%
Thereafter	above $0.59375	75.0%	25.0%

F-26

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages in the table above.

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

•

the subordination period will end and each subordinated unit will immediately convert into one common unit;

•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•

F-27

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

units and any other partnership interests that are senior or equal in right of distribution to the subordinated units, in each case that were outstanding during such four quarter period on a fully diluted weighted average basis, and the corresponding distributions on the incentive distribution rights; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%, assuming it has maintained its 0.1% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election.

Cash Distributions to Unitholders

Subsequent Event. On January 26, 2012, the board of directors of our general partner 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 11).

Predecessor Capital

BlueStone. BlueStone is a wholly-owned subsidiary of BlueStone Natural Resources Holdings, LLC (“Holdings”), whose sole purpose is to provide financing for BlueStone. In February 2006, BlueStone, Holdings and Holdings’ members entered into a subscription and contribution agreement whereby all equity contributions made by Holdings’ members in exchange for equity units would be transferred directly to BlueStone. NGP VIII and certain members of BlueStone’s management committed equity contributions of $75.7 million and $9.0 million under this agreement and amendments thereto, respectively, all of which was contributed by December 31, 2009. In 2010, BlueStone received an equity contribution from members of Holdings of an additional $40.0 million, including equity contributions of $4.2 million from management. NGP VIII advanced certain members of management $4.2 million to fund their equity contributions in 2010 in exchange for notes payable issued by management. BlueStone did not receive any capital contributions during 2011.

Classic. In June 2006, the partners of Classic entered into a partnership agreement. The Classic partners agreed to contribute an aggregate $135.9 million under the partnership agreement and amendments thereto, including $35.7 million allocable to the Classic Carve-Out. NGP VIII and certain members of Classic’s management committed equity contributions of $123.0 million and $12.9 million, respectively, all of which had been contributed as of January 24, 2011. In 2010, Classic received capital contributions of $19.7 million, net of equity financing fees, from its partners, including $4.1 million allocable to Classic Carve-Out. In 2011, Classic received capital contributions of $21.9 million, net of equity financing fees, from its partners, including $4.8 million allocable to Classic Carve-Out.

WHT. In February 2011, WHT was formed by WildHorse and Tanos. NGP IX and NGP IX Offshore collectively funded 100% of the cash used by WildHorse and Tanos to fund their respective capital contributions to WHT. In 2011, WildHorse and Tanos each contributed $64.7 million to WHT, of which an aggregate $51.8 million was allocable to our predecessor.

F-28

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 9. Earnings per Unit

The following sets forth the calculation of earnings per unit, or EPU, for the period from December 14, 2011 to December 31, 2011 (in thousands, except per unit amounts):


Net income attributable to partners	$	6,585
Less: General partner’s 0.1% interest in net income		7

Limited partners’ interest in net income	$	6,592

Weighted average limited partner units outstanding:
Common units		16,395
Subordinated units		5,361

Total		21,756

Basic and diluted EPU	$	0.30

Note 10. Equity-based Awards

Long-Term Incentive Plan

In December 2011, the board of directors of our general partner (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 became effective upon filing of a registration statement on Form S-8 with the SEC on December 14, 2011. 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. No awards had been granted as of December 31, 2011.

Subsequent Event. 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. 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.

F-29

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 11. Related Party Transactions

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


	2011			2010
Accounts Receivable/(Payable) – Affiliates:
Memorial Resource	$	377			—
BlueStone		2,142		$	—
Classic		436			—
WHT		(1,024	)		—

Total	$	1,931		$	—

Accounts payable:

Certain directors of our predecessor entities	$	—		$	32

For the years ended December 31, 2011, 2010, and 2009, respectively, there was less than $0.2 million of related party transactions recognized in the accompanying statements of operations.

Partnership

We have entered into agreements with Memorial Resource and our general partner pursuant to which, among other things, we will make payments to Memorial Resource. These agreements include the following:

•

an omnibus agreement pursuant to which, among other things, Memorial Resource provides management, administrative and operating services for us and our general partner; and

•

a 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). It is possible that Memorial Resource or its applicable affiliate(s) may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. In such a situation, we would pay Memorial Resource or its applicable affiliate(s) the tax we would have owed had the tax attributes not been available or used for our benefit, even though Memorial Resource or its applicable affiliate(s) had no cash tax expense for that period. Currently, the Texas margin tax (which has a maximum effective tax rate of 0.7% of gross income apportioned to Texas) is the only tax that is included in a combined or consolidated tax return with Memorial Resource or its applicable affiliate(s).

In December 2011, Memorial Resource 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. We reimburse Memorial Resource approximately $0.1 million for the monthly management fees that it pays to its affiliates.

Our Predecessor

The majority partner of our predecessor, NGP VIII, is an affiliate of certain directors of the entities comprising our predecessor. For the periods ended December 31, 2011, 2010 and 2009, our predecessor expensed advisory and directors’ fees of approximately $0.2 million, $0.2 million, and $0.1 million, respectively, to NGP VIII. At December 31, 2010, less than $0.1 million related to these fees was recorded as a related party payable.

The WHT Assets are operated by WildHorse. Under the terms of a management agreement dated April 8, 2011, WildHorse assumed certain responsibilities for the management of WHT, including the day-to-day

F-30

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

operations of the company providing executive, administrative, land, financial, and accounting services and operating WHT’s properties. Under the terms of the agreement, WHT paid WildHorse an approximate $0.1 million monthly management fee, of which 40% was allocable to the WHT Assets. Additionally, WHT pays Tanos less than $0.1 million per month, of which 40% was allocable to the WHT Assets, for certain services that it provides WHT, primarily managing its exploration program. These amounts are payable monthly in advance on the first of each month. At the closing of our IPO, there were no outstanding management, operation and administration fees payable.

In addition to the management fees, both WildHorse and Tanos are entitled to recover from WHT certain expenditures made on its behalf that are not covered by the management fees described above. These amounts include certain payments for third-party professional services and other non-routine direct general and administrative expenses, costs incurred in the operation and development of the properties, and amounts paid to the other operators for WHT’s non-operated interests.

As the operator of the properties, WildHorse also markets WHT’s oil, gas and NGL production, collects the proceeds, pays the related production taxes and disburses amounts owed to royalty and other working interest owners. WildHorse also receives sales proceeds from the operators for the sale of non-operated production.

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.

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2011, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable.

The following table presents the activity of our environmental reserves for the periods presented:


	For Year Ended December 31,
	2011			2010		2009
	(In thousands)
Balance at beginning of period	$	1,450		$	—	$	—
Charged to costs and expenses		—			—		—
Acquisition-related additions		387			1,450		—
Payments		(671	)		—		—

Balance at end of period	$	1,166		$	1,450	$	—

F-31

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

At December 31, 2011 and 2010, $0.8 million and $1.5 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.

Operating Leases

We lease certain equipment and office space under operating leases. Amounts shown in the following table represent minimum lease payment obligations under our operating leases, the majority of which are compressor lease rentals. We recognized an immaterial amount of rent expense since our IPO, primarily for office space allocated to us from Memorial Resource.

Our predecessor leased equipment and office space under various operating leases. Our predecessor recorded rent expense of approximately $0.3 million, $0.3 million, and $0.2 million for the years ended December 31, 2011, 2010, and 2009, respectively.


	Payment or Settlement due by Period
Lease Obligations	Total		2012		2013		2014		2015		2016		Thereafter
	(In thousands)
Operating leases	$	734	$	682	$	48	$	4	$	—	$	—	$	—

Note 13. Defined Contribution Plan

Memorial Resource sponsors a defined contribution plan to substantially all employees who have attained 18 years of age. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Memorial Resource makes matching contributions of 100% of employee contributions that does not exceed 6% of compensation. Employees are immediately vested in these matching contributions. This plan became effective on January 1, 2012.

The companies comprising our predecessor also sponsored defined contribution plans as well for the benefit of substantially all their employees who attained 18 years of age. Our predecessor made matching contributions of up to 6% of an employee’s compensation and had the option to make additional discretionary contributions for eligible employees meeting certain plan requirements. Our predecessor made contributions to the plan of approximately $0.2 million, $0.2 million, and $0.2 million in 2011, 2010 and 2009, respectively.

Note 14. Subsequent Event

Definitive Agreement to Acquire Oil & Gas Producing Properties—Related Party

On March 7, 2012, we announced the entry into a definitive agreement to acquire certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource, for a purchase price of $18.3 million, subject to customary purchase price adjustments. The transaction is expected to close on about April 2, 2012 and will be financed with borrowings under our existing revolving credit facility. The transaction also includes the novation of 2012 through 2013 commodity derivative positions to the partnership. Terms of the transaction were 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. Memorial Resource will continue to operate 84% of the acquired properties and the remaining 16% will continue to be operated by third parties. Approximately 82% of the current net production of 2.3 MMcfe/d is natural gas and the remaining 18% is oil and NGLs. This acquisition will be accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method.

F-32

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Note 15. Quarterly Financial Information (Unaudited)

The following table presents selected quarterly financial data for the periods indicated:


	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
For the Year Ended December 31, 2011:
Revenues	$	11,693		$	20,421		$	22,400	$	18,843
Operating income (loss)		(948	)		66,139			16,354		8,177
Net income (loss)		(1,983	)		63,811			14,162		6,342
Net income (loss) attributable to predecessor		(1,983	)		63,811			14,162		(250	)
Net income attributable to partners		n/a			n/a			n/a		6,592
Earnings per unit		n/a			n/a			n/a		0.30
For the Year Ended December 31, 2010:
Revenues	$	7,946		$	8,181		$	11,218	$	11,396
Operating income (loss)		4,638			(3,334	)		3,206		(11,164	)
Net income (loss)		4,032			(4,556	)		1,629		(12,422	)
Net income (loss) attributable to predecessor		4,032			(4,556	)		1,629		(12,422	)
Net income attributable to partners		n/a			n/a			n/a		n/a
Earnings per unit		n/a			n/a			n/a		n/a

As discussed in Note 1, we closed our IPO on December 14, 2011; therefore, the quarterly financial information presented above for periods prior to December 14, 2011 is that of our predecessor. See Note 2 and 9 for additional information regarding earnings per unit.

Note 16. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.


	December 31,
	2011			2010			2009
	(In thousands)
Evaluated oil and natural gas properties	$	496,818		$	299,589		$	181,773
Unevaluated oil and natural gas properties		—			15,385			5,445
Accumulated depletion, depreciation, and amortization		(96,156	)		(92,814	)		(60,978	)

Total	$	400,662		$	222,160		$	126,240

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:


	Years Ended December 31,
	2011		2010		2009
	(In thousands)
Property acquisition costs, proved	$	138,175	$	104,542	$	17,455
Exploration and extension well costs		6,200		6,287		6,808
Development		16,181		6,842		12,226

Total	$	160,556	$	117,671	$	36,489

F-33

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Partnership’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible —from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations —prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Estimated proved reserves, including changes, presented in the tables below for the periods indicated were either prepared or audited by independent third-party petroleum engineers. All of the Partnership’s estimated proved reserves for the year ended December 31, 2011 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”). Our predecessor’s estimated proved reserves for the year ended December 31, 2010 and 2009 were either prepared or audited by NSAI and other independent third-party petroleum engineers. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:


	2011		2010		2009
Oil and NGL ($/Bbl):
West Texas Intermediate (Plains) posted spot (1)	$	92.71	$	75.96	$	57.65
Natural Gas ($/MMbtu):
Henry Hub spot (2)	$	4.118	$	4.376	$	3.866

(1)	The average West Texas Intermediate posted price was adjusted by lease for quality, transportation fees, and a regional price differential.

(2)	The average Henry Hub spot price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

F-34

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

The following tables set forth estimates of the net reserves as of December 31, 2011, 2010 and 2009, respectively:


	Year Ended December 31, 2011
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (Mmcfe)
Proved developed and undeveloped reserves:
Beginning of year		1,016			151,176			449			159,971
Extensions and discoveries		30			8,900			157			10,023
Purchase of minerals in place		1,030			136,345			4,146			167,399
Production		(83	)		(13,685	)		(156	)		(15,124	)
Reserves retained by our predecessor		(23	)		(3,198	)		—			(3,335	)
Revision of previous estimates		94			3,957			104			5,145

End of year		2,064			283,495			4,700			324,079

Proved developed reserves:
Beginning of year		904			123,529			206			130,196
End of year		1,715			227,451			3,290			257,481
Proved undeveloped reserves:
Beginning of year		112			27,647			243			29,775
End of year		349			56,044			1,410			66,598


	Year Ended December 31, 2010
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (Mmcfe)
Proved developed and undeveloped reserves:
Beginning of year		739			61,652			—			66,089
Extensions and discoveries		58			7,602			212			9,225
Purchase of minerals in place		259			78,046			—			79,599
Production		(45	)		(7,314	)		(34	)		(7,792	)
Sale of minerals in place		—			—			—			—
Revision of previous estimates		5			11,190			271			12,850

End of year		1,016			151,176			449			159,971

Proved developed reserves:
Beginning of year		687			47,809			—			51,934
End of year		904			123,529			206			130,196
Proved undeveloped reserves:
Beginning of year		52			13,843			—			14,155
End of year		112			27,647			243			29,775

F-35

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS


	Year Ended December 31, 2009
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)		Equivalent (Mmcfe)
Proved developed and undeveloped reserves:
Beginning of year		834			58,199			—		63,203
Extensions and discoveries		6			3,533			—		3,571
Purchase of minerals in place		32			8,002			—		8,195
Production		(94	)		(5,282	)		—		(5,847	)
Sale of minerals in place		(90	)		—			—		(538	)
Revision of previous estimates		51			(2,800	)		—		(2,495	)

End of year		739			61,652			—		66,089

Proved developed reserves:
Beginning of year		769			43,291			—		47,905
End of year		687			47,809			—		51,934
Proved undeveloped reserves:
Beginning of year		65			14,908			—		15,298
End of year		52			13,843			—		14,155

Noteworthy amounts included in the categories of proved reserve changes for the years 2011, 2010, and 2009 in the above tables include:

•

Our predecessor acquired 167.4 Bcfe in multiple acquisitions, the largest being the Carthage Properties, during the year ended December 31, 2011.

•

Our predecessor acquired 79.6 Bcfe in multiple acquisitions, the largest being the Forest Oil properties of 47.0 Bcfe, during the year ended December 31, 2010.

•

Our predecessor acquired 8.2 Bcfe during the year ended December 31, 2009 multiple acquisitions.

See Note 3 Acquisitions and Divestitures for additional information on acquisitions.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

F-36

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

The standardized measure of discounted future net cash flows is as follows:


	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Future cash inflows	$	1,577,233		$	780,477		$	295,659
Future production costs		(563,502	)		(291,486	)		(120,657	)
Future development costs		(125,334	)		(68,046	)		(31,180	)
Future income tax expense (1)		—			(5,463	)		(2,070	)

Future net cash flows for estimated timing of cash flows		888,397			415,482			141,752
10% annual discount for estimated timing of cash flows		(510,135	)		(231,667	)		(77,916	)

Standardized measure of discounted future net cash flows	$	378,262		$	183,815		$	63,836

(1)	We are subject to the Texas franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the year ended December 31, 2011.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2011:


	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Beginning of year	$	183,815		$	63,836		$	103,886
Sale of oil and natural gas produced, net of production costs		(44,864	)		(21,222	)		(11,870	)
Purchase of minerals in place		219,113			104,729			6,213
Sale of minerals in place		—			—			(612	)
Reserves retained by predecessor		(1,940	)		—			—
Extensions and discoveries		11,673			8,526			2,332
Changes in income taxes, net		—			(1,506	)		319
Changes in prices and costs		10,536			14,198			(44,997	)
Previously estimated development costs incurred		205			2,228			5,828
Net changes in future development costs		1,489			(4,947	)		1,253
Revisions of previous quantities		6,003			12,192			(4,118	)
Accretion of discount		18,382			6,481			10,517
Change in production rates and other		(26,150	)		(700	)		(4,915	)

End of year	$	378,262		$	183,815		$	63,836

F-37

Amplify Energy Corp - FORM 10-K - March 30, 2012

Attached files