FORM 10-K

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 x 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:

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

The aggregate market value of the common units held by non-affiliates was approximately $162.8 million on June 29, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, based on closing prices in the daily composite list for transactions on the NASDAQ Global Market on such date. As of February 28, 2013, the registrant had 28,931,966 common units, 5,360,912 subordinated units and 34,334 general partner units outstanding.

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.

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.

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.

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

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

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

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

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

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 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.

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:

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 include other “forward-looking” information. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

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.

We are a Delaware limited partnership formed in April 2011 by Memorial Resource to own, acquire and exploit 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. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. As of December 31, 2012:

On December 12, 2012, we acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, from Rise Energy Partners, LP for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. We refer to this transaction as the “Beta acquisition.” The Beta acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our December 12, 2012 public offering of common units (discussed below). 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. The acquired properties and assets, which we refer to as the “Beta properties,” primarily consist of a 51.75% working interest in three Pacific Outer Continental Shelf blocks covering the Beta Field, and are located in federal waters approximately 11 miles offshore the Port of Long Beach, California. Associated facilities include three conventional wellhead and production processing platforms, a 17.5-mile pipeline and an onshore tankage and metering facility. Two of the platforms are bridge connected and stand in approximately 260 feet of water, while the third platform stands in approximately 700 feet of water.

This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interests method, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to the Beta acquisition as if the Partnership owned REO from February 3, 2009 (inception) through the acquisition date. For information about the Partnership’s basis of presentation, see Note 1 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

In conjunction with the closing of the Beta acquisition, the board of directors of our general partner approved an increase in our distribution rate attributable to the fourth quarter of 2012 to $0.5075 per unit, representing an annualized distribution of $2.03 per unit. This represents a 6.8% increase over our initial annualized distribution of $1.90 per unit.

On December 12, 2012, we issued 10,500,000 common units representing limited partner interests in the Partnership to the public at an offering price of $17.00 per unit generating total net proceeds of $170.0 million after deducting underwriting discounts and offering expenses. The net proceeds from the offering, including our general partner’s proportionate capital contribution, were used to fund a portion of the purchase price of the Beta acquisition. On December 21, 2012, the underwriters purchased an additional 1,475,000 common units pursuant to their over-allotment option. We used the net proceeds of approximately $24.1 million from the sale of the additional common units, including our general partner’s proportionate capital contribution, to repay indebtedness under our revolving credit facility.

On December 3, 2012, we entered into a third amendment to our credit agreement, which among other things increased the borrowing base to $460.0 million upon closing of the Beta acquisition.

On May 14, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource for a final purchase price of $27.0 million. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2014 commodity derivative positions related to these properties. The transaction was approved by the board of directors of our general partner and by its conflicts committee. These properties are located primarily in the Joaquin and Carthage fields in Panola and Shelby counties in East Texas.

On April 2, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource for a final purchase price of $18.5 million. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2013 commodity derivative positions related to these properties. The transaction was approved by the board of directors of our general partner and by its conflicts committee. 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 operates 84% of the acquired properties and the remaining 16% is operated by third parties.

Our acquisitions of oil and gas properties from Memorial Resource in April and May 2012 were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource’s carrying value. For information about the Partnership’s basis of presentation, see Note 1 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

On September 28, 2012, we acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation, for a final net purchase price of $90.4 million. This transaction was financed with borrowings under our revolving credit facility. These properties are located in the East Henderson field of Rusk County, Texas. We operate substantially all of the acquired properties. This acquisition was accounted for as a business combination using the acquisition method of accounting.

On May 1, 2012, we acquired non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller for a final net purchase price of approximately $36.5 million after customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. Because this transaction was a joint acquisition with Memorial Resource, the transaction was approved by the board of directors of our general partner and by its conflicts committee. These properties are located primarily in Polk County, Texas and Lincoln Parish, Louisiana. Memorial Resource operates 75% of the acquired properties and the remaining 25% is operated by third parties. This acquisition was accounted for as a business combination using the acquisition method of accounting.

See Note 3 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for more information about these acquisitions.

Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, were engaged to prepare portions of our reserves estimates comprising approximately 97% of our estimated proved reserves (by volume) at December 31, 2012. The following table summarizes information about our proved oil and natural gas reserves by geographic region as of December 31, 2012 and our average net production for the three months ended December 31, 2012:

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:

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:

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 our formation transactions in connection with our initial public offering, the Funds contributed to Memorial Resource their respective ownership of five separate portfolio companies (including those comprising our predecessor at the time of our initial public offering), 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.

Memorial Resource is our largest unitholder as of February 28, 2013, holding 7,061,294 common units (approximately 24.4% of all outstanding common units) and 5,360,912 subordinated units (100% of all outstanding), and owns all of the voting interests in our general partner and 50% of the economic interest in our incentive distribution rights. Memorial Resource has pledged our common and subordinated units that it owns, as well as its ownership interest in our general partner, as security under its senior secured revolving credit facility in addition to certain other assets of Memorial Resource. 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 June 30, 2012, Memorial Resource had (i) total estimated proved reserves of over 1,235 Bcfe, primarily located in East Texas, North Louisiana and the Rockies and (ii) interests in over 579,570 gross (335,323 net) acres of 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 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/North Louisiana acreage, along with joint ownership in specific properties, will provide 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. For example, during 2012 we acquired two sets of properties from Memorial Resource, and we also completed an acquisition of properties via a joint bid with Memorial Resource. 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. 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.

Founded in 1988, NGP is a family of private equity investment funds, with cumulative committed capital of approximately $10.5 billion since inception, organized to make investments in the natural resources sector. NGP is part of the investment platform of NGP Energy Capital Management, a premier investment franchise in the natural resources industry, which together with its affiliates has managed approximately $13 billion in cumulative committed capital since inception. 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.

Approximately 58% of our estimated proved reserves as of December 31, 2012 and approximately 53% of our average daily net production for the three months ended December 31, 2012 were located in the East Texas/North Louisiana region. Our East Texas/Louisiana properties include wells and properties located in Navarro, Anderson, Wood, Upshur, Gregg, Harrison, Rusk, Panola, Leon, Polk, Smith, Tyler and Shelby Counties, Texas and De Soto and Lincoln Parishes, Louisiana. Those properties collectively contained 353 Bcfe of estimated net proved reserves as of December 31, 2012 based on our reserve report and generated average net production of 38.6 MMcfe/d for the three months ended December 31, 2012. Our East Texas/North Louisiana properties include properties in the Joaquin and Carthage fields in Panola and Shelby Counties, the Willow Springs field located in Gregg County, the East Henderson field located in Rusk County, and the Terryville field located in Lincoln Parish.

Based on our December 31, 2012 reserve report, the East Henderson field contains more than 15% of our total estimated reserves. The oil and natural gas properties in this field were acquired on September 28, 2012 from Goodrich Petroleum Corporation. The following table summarizes production volumes from this field from the date of acquisition through December 31, 2012:

Approximately 27% of our estimated proved reserves as of December 31, 2012 and approximately 35% of our average daily net production for the three months ended December 31, 2012 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 167 Bcfe of estimated net proved reserves as of December 31, 2012 based on our reserve report. Those properties collectively generated average net production of 24.9 MMcfe/d for the three months ended December 31, 2012.

Approximately 15% of our estimated proved reserves as of December 31, 2012 and approximately 13% of our average daily net production for the three months ended December 31, 2012 were located offshore Southern California. These properties, the Beta properties, consist of: (i) a 51.75% working interest and a 35.03% average net revenue interest in three Pacific Outer Continental Shelf blocks (P-0300, P-0301 and P-0306), referred to as the Beta unit, in the Beta Field located in federal waters approximately 11 miles offshore the Port of Long Beach, California; (ii) a 4.575% overriding royalty interest in the Beta unit; (iii) a 51.75% undivided interest in (a) two wellbore production platforms with permanent drilling equipment systems and (b) one production handling and processing platform; and (iv) a 51.75% controlling equity interest in a 17.5-mile pipeline and an onshore tankage and metering facility. Our Beta properties contained 15 MMBbls of estimated net proved reserves as of December 31, 2012 based on our reserve report. The Beta properties collectively generated average net production of 1,568 Bbls/d for the three months ended December 31, 2012.

The Beta properties include a 51.75% undivided interest in: two wellbore production platforms, referred to as the Ellen and Eureka platforms, with permanent drilling equipment systems and one production handling and processing platform, referred to as the Elly platform. The Elly platform, which is bridge connected to the Ellen platform, handles production and processing for the Ellen and Eureka platforms as well as sales connectivity for a third-party platform. The Ellen platform is located in block P-0300 in the Beta Field and currently has 80 well slots. The Eureka platform is located in block P-0301 in the Beta Field and currently has 60 well slots. We believe there are over 50 available well slots for additional production and injection wells for the Ellen and Eureka platforms. Royal Dutch Shell PLC installed the platforms in the 1980s, and production from the Ellen and Eureka platforms commenced in January 1981 and March 1985, respectively. The Beta unit was formed in 1983.

The Beta properties include a controlling interest in the San Pedro Bay Pipeline Company, which owns and operates a 16-inch diameter oil pipeline that extends approximately 17.5 miles from the Elly platform to the Beta pump station located onshore at the Port of Long Beach, California. The Ellen and Eureka platforms are the primary source of throughput for this pipeline as well as production received from a third-party platform also located in the Beta Field. Crude oil delivered to the Beta pump station is metered and received into a 10,000 Bbl storage tank. The pipeline includes two pipelines that connect to two sales outlets that connect to the THUMS header, operated by Crimson Pipeline LP, which can deliver the crude oil to over five refineries. All of the crude oil produced from the Ellen and Eureka platforms is currently being delivered to one refinery under a short-term “evergreen’ marketing agreement that renews on a month-to-month basis until either party gives 60-day advance written notice of non-renewal.

Internal Controls. Approximately 97% of our proved reserves were 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 and evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our revolving credit facility. 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.

Internal Engineers. Larry R. Forney and John D. Williams are the technical persons at Memorial Resource primarily responsible to liaison with and provide 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 and Chief Operating Officer since January 2013. Previously, he served as our general partner’s Vice President of Operations and Asset Management from August 2011 to January 2013. 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.

Mr. Williams has been practicing petroleum engineering at Memorial Resource since March 2012. Mr. Williams is a Registered Professional Engineer in the State of Texas with over 17 years of experience in the estimation and evaluation of reserves. From April 2005 to March 2012, he held various positions at Southwestern Energy Company, most recently as Reservoir Engineering Manager. From August 1998 to April 2005, he served in various capacities at Ryder Scott Company, which culminated in his serving as Vice President. Mr. Williams is a graduate of the University of Texas at Austin with a B.S. in petroleum engineering and with a M.S. in petroleum engineering.

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, 2012 presented in the NSAI report were overseen by Mr. Justin S. Hamilton; Mr. David E. Nice; Mr. Richard B. Talley, Jr.; Mr. Philip S. (Scott) Frost; Mr. Joseph Spellman; and Mr. J. Carter Henson, Jr.

Justin Hamilton has been practicing consulting petroleum engineering at NSAI since 2004. Mr. Hamilton is a Licensed 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 of experience in the estimation and evaluation of reserves. He graduated from Brigham Young University in 2000 with a B.S. in mechanical engineering and from the University of Texas in 2007 with a M.B.A.

David Nice has been practicing consulting petroleum geology at NSAI since 1998. Mr. Nice is a Licensed Professional Geoscientist in the State of Texas (License No. 346) and has over 26 years of practical experience in petroleum geosciences, with over 13 years of experience in the estimation and evaluation of reserves. He graduated from University of Wyoming in 1982 with a B.S. in geology and in 1985 with a M.S. in geology.

Richard Talley has been practicing consulting petroleum engineering at NSAI since 2004. Mr. Talley is a Licensed Professional Engineer in the State of Texas (License No. 102425) and in the State of Louisiana (License No. 36998) and has over 13 years of practical experience in petroleum engineering, with over 7 years of experience in the estimation and evaluation of reserves. He graduated from University of Oklahoma in 1998 with a B.S. in mechanical engineering and from Tulane University in 2001 with a M.B.A.

Scott Frost has been practicing consulting petroleum engineering at NSAI since 1984. Mr. Frost is a Licensed Professional Engineer in the State of Texas (License No. 88738) and has over 30 years of practical experience in petroleum engineering, with over 30 years of experience in the estimation and evaluation of reserves. He graduated from Vanderbilt University in 1979 with a B.E. in mechanical engineering and from Tulane University in 1984 with a M.B.A.

Joseph Spellman has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Spellman is a Licensed Professional Engineer in the State of Texas (License No. 73709) and has over 30 years of practical experience in petroleum engineering, with over 30 years of experience in the estimation and evaluation of reserves. He graduated from University of Wisconsin-Platteville in 1980 with a B.S. in civil engineering.

Carter Henson has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Henson is a Licensed Professional Engineer in the State of Texas (License No. 73964) and has over 30 years of practical experience in petroleum engineering, with over 24 years of experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a B.S. in mechanical engineering.

All six 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 six are proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

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, 2012, primarily based on our reserve report 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.

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.

None of our proved undeveloped reserves as of December 31, 2012 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 from our revolving credit facility), as well as our planned drilling and development programs, which include 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.”

For a description of the Partnership’s, our predecessor’s, and the previous owners’ combined 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.”

The following tables summarizes our average net production, average sales prices by product and average production costs by geographic region for the years ended December 31, 2012, 2011 and 2010, respectively:

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, 2012.

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2012, substantially all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2012 relating to our leasehold acreage.

The following table sets forth information as of December 31, 2012 relating to our undeveloped leasehold acreage.

Our drilling activities consist entirely of development wells. The following table sets forth information with respect to wells drilled and completed by us, our predecessor, or the previous owners 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.

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.

As of December 31, 2012, Memorial Resource operates 97% 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 onshore properties; independent contractors provide all the equipment and personnel associated with these activities. Our Beta platforms have permanent drilling systems in place. 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 — Related Party Agreements — Omnibus Agreement” for more information about the omnibus agreement.

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, 2012, most of our leases are held by production and do not require lease rental payments.

The following individual customers each accounted for 10% or more of total reported revenues 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.

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.

We enter into commodity derivative contracts with unaffiliated third parties, generally lenders under our revolving credit facility, 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, call spreads, 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.

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 and many of our competitors have access to capital at a lower cost than that available to us.

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 has been a part of the completion process for substantially all wells on our onshore producing properties, and the future development of substantially all of our onshore 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/North Louisiana holdings. As of December 31, 2012, substantially 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 onshore proved non-producing and proved undeveloped reserves. This represents 43% of our total estimated proved reserves with a total standardized measure of $146.7 million as of December 31, 2012.

All of our currently scheduled onshore drilling operations for 2013 are located in East Texas and North Louisiana and planned as horizontal wells that will benefit from hydraulic fracturing operations. The targeted reservoirs are conventional sand reservoirs, such as the Cotton Valley, as opposed to shale oil and gas resource plays. A typical hydraulic fracture stimulation treatment on one of our horizontal drill wells is pumped in 8 to 15 stages, and utilizes a total of 260,000 gallons of non-potable water and 300,000 pounds of sand or proppant per stage. Any hydraulic fracture stimulation work that may be conducted on one of our PDNP or vertical PUD reserve cases would be significantly smaller in comparison. A projected PDNP or vertical PUD treatment would be pumped utilizing a total of an estimated 30,000 to 200,000 gallons of non-potable water and 50,000 to 250,000 pounds of sand or proppant. Chemical additives to these treatments typically run less than one percent of the total fluid volume, with the balance being non-potable water. Our onshore properties are in legacy field areas that have been exposed to fracture stimulation operations for decades. The necessary volumes of treatment water in these areas are generally readily available. Our offshore California properties are not projected to undergo any hydraulic fracture stimulation treatments.

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.

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 flowback or produced 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 — Rules recently finalized regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.”

We routinely apply hydraulic fracturing techniques in many of our 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 SDWA Underground Injection Control Program, or UIC Program. On May 4, 2012, the EPA published a draft UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document is designed for use by employees of the EPA that draft the UIC permits and describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas and Louisiana, where we maintain acreage, the EPA is encouraging state programs to review and consider use of such draft guidance. The draft guidance underwent an extended public comment process, which concluded on August 23, 2012. The EPA is presently evaluating the public comments and will likely issue a final guidance document at a later date. 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 its Railroad Commission, or 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.

The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and issued a progress report in December 2012. A final draft report is expected to be released for public comment and peer review in 2014. The EPA’s study, depending on its degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. On May 4, 2012, the U.S. Department of Interior issued a draft rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water.

In August 2012, the EPA adopted new rules to establishing air emission controls for oil and natural gas production and natural gas processing operations. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule established a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. The rule requires owners and operators to either flare VOC emissions or use emissions reduction technologies, or green completions, which allow the emissions to be recaptured and treated. On or after January 1, 2015, all newly fractured wells will be required to use green completions. Certain compressors, dehydrators, and other equipment must also comply with the final rule immediately or up to three years and 60 days after publication of the final rule, depending on the construction date and/or nature of the unit. 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. Proposed rules are expected in 2013 for coalbed methane and 2014 for shale gas.

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.

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

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Commercial General Liability;

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Primary Umbrella / Excess Liability;

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Property;

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Workers’ Compensation;

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Employer’s Liability;

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Maritime Employer’s Liability;

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U.S. Longshore and Harbor Workers’;

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Control of Well;

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Loss of Production;

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Oil Pollution Act Liability;

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Pollution Legal Liability;

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Charterer’s Legal Liability;

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Non-Owned Aircraft Liability;

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Automobile Liability;

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Directors & Officers Liability;

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Employment Practices Liability;

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Crime; and

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Fiduciary.

Onshore Insurance Program. We maintain insurance coverage against potential losses that we believe is customary in the industry. As of December 31, 2012, we maintain commercial general liability insurance, automobile liability insurance and umbrella / excess liability insurance. Our commercial general liability insurance has limits of $1.0 million per occurrence and $2.0 million in the aggregate. Our automobile liability insurance has limits of $1.0 million per occurrence. There is a $1,000 deductible for auto liability insurance. Our excess liability limits for each occurrence and in the aggregate is a minimum of $25.0 million. 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 and for sudden and accidental pollution liability. Our umbrella / excess liability insurance is in addition to our general and automobile liability policy and may be triggered if the general or automobile liability insurance policy limits are exceeded. In addition, we maintain control of well insurance with per occurrence limits ranging from $10.0 million to $20.0 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.

As of December 31, 2012, 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 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 certain 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.

Offshore Insurance Program. We maintain insurance coverage against potential losses that we believe is customary in the industry. As of December 31, 2012, we maintain commercial general liability insurance, automobile liability insurance and umbrella / excess liability insurance that covers our Beta properties and the associated onshore tankage and metering facility. Our commercial general liability insurance has limits of $1.0 million per occurrence and $2.0 million in the aggregate with a $25,000 deductible for pollution clean-up. Our automobile liability insurance has limits of $1.0 million per occurrence and a $1,000 deductible. Our excess liability limits for each occurrence and in the aggregate is $200.0 million with a $25,000 deductible. Our general liability insurance covers us for, among other things, legal and contractual liabilities arising out of third party property damage and bodily injury and for sudden or accidental pollution liability. Our umbrella / excess liability insurance is in addition to our general and automobile liability policies and is triggered if the general or automobile liability insurance policy limits are exceeded. In addition, we maintain control of well insurance with per occurrence limits ranging from $5.0 million to $100.0 million with retentions ranging from $250,000 to $500,000. Our control of well policy insures us for blowout risks associated with drilling, completing and operating our wells, including pollution and clean up. Our oil pollution act liability policy has a limit of $35.0 million per incident. Our pollution legal liability insurance has limits of $10.0 million per pollution event and $20.0 million in the aggregate with a $50,000 deductible per pollution event. Our loss of production income policy currently insures us against loss up to $87.6 million due to a temporary interruption in the oil supply from our offshore facilities as a result of a physical loss or damage to our offshore facilities.

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, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. 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 owned or 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.

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.

Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters. On October 1, 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the Minerals Management Service), was replaced by the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement as part of a major reorganization. These two recently formed bureaus have broad authority to regulate our oil and gas operations associated with our Beta properties.

The Bureau of Ocean Energy Management, or BOEM, is responsible for managing environmentally and economically responsible development of the nation’s offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard and the EPA.

The Bureau of Safety and Environmental Enforcement, or BSEE, is responsible for safety and environmental oversight of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. BSEE has regulations requiring offshore production facilities and pipelines located on the Outer Continental Shelf, or OCS, to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization. BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. BSEE generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met.

The BOEM and BSEE have adopted regulations providing for enforcement actions, including civil penalties, and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta properties be suspended or terminated. Delays in the approval or refusal of plans and issuance of permits by the BOEM or BSEE because of staffing, economic, environmental or other reasons (or other actions taken by the BOEM or BSEE) could adversely affect our offshore operations. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations.

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 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. Responsible parties include (i) owners and operators of onshore facilities and pipelines and (ii) lessees or permittees of offshore facilities. The OPA establishes a liability limit for onshore facilities of $350 million. In addition, OPA requires parties responsible for offshore facilities to provide financial assurance in the amount of $35 million, which can be increased to $150 million in some circumstances, to cover potential OPA liabilities. 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. For example, the California Department of Fish and Game’s Office of Oil Spill Prevention and Response has adopted oil-spill prevention regulations that overlap with federal regulations.

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.

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.

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 August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule limits emissions of volatile organic compounds (a group of chemicals that contribute to the formation of ground-level ozone), sulfur dioxide, and other hazardous air pollutants from several types of processes and equipment used in the oil and gas industry. The rule includes NSPS standards for completions of hydraulically fractured wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The rule establishes a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators must either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. On or after January 1, 2015, all newly fractured wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning on August 16, 2012, which is the date the final rule was published in the Federal Register, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA’s final rule, as it may require changes to our operations, including the installation of new emissions control equipment.

The South Coast Air Quality Management District, or SCAQMD, is a political subdivision of the State of California and responsible for air pollution control within Orange County and designated portions of Los Angeles, Riverside, and San Bernardino Counties. Our Beta properties and associated facilities are subject to regulation by the SCAQMD.

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.

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. The U.S. Congress has previously considered legislation to comprehensively address global climate change. 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 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 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. 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. 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 is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries.

In addition, many states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. In California, for example Assembly Bill 32 required the California Air Resources Board, or CARB, to establish and adopt regulations to take effect and become legally enforceable by January 1, 2012 in order to achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020. In October 2011, the CARB adopted the final cap and trade regulation, including a delay in the start of the cap and trade rule’s compliance obligations until 2013. Because our operations associated with our Beta properties emit greenhouse gases, our operations in California may be subject to regulations issued under Assembly Bill 32. These regulations will increase our costs for those operations and adversely affect our operating results. The EPA has also adopted regulations imposing permitting and best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air pollutants” under the existing federal Clean Air Act. Passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect on our operations and the demand for oil and natural gas.

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.

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.

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.

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 ensure 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.

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.

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.

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:

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.

The Federal Energy Regulatory Commission, or the FERC, approves the construction of interstate gas pipelines and the rates and service conditions for the interstate transportation of gas, oil and other liquids by pipeline. Although the FERC does not regulate the production of gas, the FERC exercises regulatory authority over wholesale sales of gas in interstate commerce through the issuance of blanket marketing certificates that authorize the wholesale sale of gas at market rates and the imposition of a code of conduct on blanket marketing certificate holders that regulate certain affiliate interactions. The FERC does not regulate the sale of oil or petroleum products or the construction of oil or other liquids pipelines. The FERC also has oversight of the performance of wholesale natural gas markets, including the authority to facilitate price transparency and to prevent market manipulation. In furtherance of this authority, the FERC imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a minimum level. The agency’s actions are intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

The FERC and other federal agencies, the U.S. Congress or state legislative bodies and regulatory agencies may consider additional proposals or proceedings that might affect the gas or oil industries. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other gas producers with which we compete.

The Beta properties include a controlling interest in the San Pedro Bay Pipeline Company, which owns and operates an offshore crude pipeline. This pipeline is subject to regulation by the FERC under the Interstate Commerce Act, or ICA, and the Energy Policy Act of 1992. Tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, must be just and reasonable and non-discriminatory. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with the FERC and posted publicly. The FERC has established a formulaic methodology for petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. Effective July 1, 2011, the current index for the five-year period ending July 2016 is the producer price index for finished goods plus an adjustment factor of 2.65 percent. The San Pedro Bay Pipeline Company uses the indexing methodology to change its rates.

The Outer Continental Shelf Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. BOEM/BSEE has established formal and informal complaint procedures for shippers that believe that have been denied open and nondiscriminatory access to transportation on the OCS.

The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, or PHMSA, regulates all pipeline transportation in or affecting interstate or foreign commerce, including pipeline facilities on the OCS. The San Pedro Bay pipeline is subject to regulation by PHMSA.

The FERC with respect to the purchase or sale of natural gas or the purchase or the purchase or sale of transmission or transportation services subject to FERC jurisdiction, the Federal Trade Commission with respect to petroleum and petroleum products, and the Commodity Futures Trading Commission with respect to commodity and futures markets, operating under various statutes have each adopted anti-market manipulation regulations, which prohibit, among other things, fraud and price manipulation in the respective markets. These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

On August 22, 2012, the SEC adopted rules mandated by Section 1504 of the Dodd-Frank Act, requiring entities who file reports with the SEC and commercially develop oil, natural gas or liquids (“resource extraction issuers”) to disclose certain payments made to the U.S. government or foreign governments. The rules provide guidance on the types of payments and information about payments that must be disclosed. The rules require a resource extraction issuer to disclose the information annually by filing a new form with the SEC (Form SD) no later than 150 days after the end of its fiscal year. A resource extraction issuer is required to comply with the new rules for fiscal years ending after September 30, 2013. As a result, in 2014, the Partnership must provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals, and the type and total amount of payments made to each government. The first report is due May 30, 2014. Presently, we do not believe that compliance with the new rules will have a material adverse impact on us.

In October 2012, the U.S. Chamber of Commerce, American Petroleum Institute, Independent Petroleum Association of America, and National Foreign Trade Council filed a lawsuit against the SEC in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners argued that the Rule is “arbitrary and capricious” within the meaning of the Administrative Procedure Act and that the Rule and statute violate the First Amendment. Briefs have been submitted. Oral arguments are not yet scheduled.

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.

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 — Related Party Agreements — Omnibus Agreement.”

As of December 31, 2012, Memorial Resource had 309 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.

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

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. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

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.”

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:

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 current distribution rate 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 level necessary to generate cash sufficient to make distributions to our unitholders of our current rate or at all.

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, 2012, 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 $1.91 per MMBtu. From January 1, 2012 to December 31, 2012, the NYMEX-WTI oil future price ranged from a high of $109.77 per Bbl to a low of $77.69 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $3.90 per MMBtu to a low of $1.91 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 or ICE, that are used for calculating hedge positions. The prices we receive for our production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, our California oil typically has a lower gravity, and a portion has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil requires more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. 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.

We intend to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six 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. 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 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 report had been $10.00 less per Bbl for oil and $1.00 less per MMBtu for natural gas, then the standardized measure of our estimated proved reserves as of December 31, 2012, excluding the effects of our commodity derivative contracts, would have decreased by $262 million, from $832 million to $570 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:

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. Furthermore, the Beta properties are offshore Southern California. Development and production of oil and natural gas in offshore waters has inherent and historically higher risk than similar activities onshore.

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, that 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:

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.

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:

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.

The Beta properties are located in an area where we have not historically conducted operations, which exposes us to additional risk.

The Beta properties are located offshore Southern California. Because we do not have extensive experience in this geographic region, we are less able to use past operational results to help predict future results. Our lack of experience may result in our not being able to fully execute our expected production and drilling programs in this region, and the return on our investment in the Beta properties may not meet our expectations. As a result, our business, results of operations, financial condition and ability to pay distributions to our unitholders may be affected.

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

Our properties are located in Texas, Louisiana and offshore Southern California. An adverse development in the oil and natural gas business of any of these geographic areas, such as in our ability to attract and retain field personnel or in our ability to comply with local regulations, 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 two individual customers that each accounted for 10% or more of total reported revenues for the year ended December 31, 2012. To the extent 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 — Operations — Marketing and Major Customers.”

Additionally, a failure by 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. These sales depend 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 purchasers 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.

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, and many of our competitors have access to capital at a lower cost than that available to us. 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 revolving 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 revolving 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 revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving 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 operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are a variety of operating risks inherent in our oil and natural gas properties and other assets, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses. The location of our oil and natural gas properties and other assets near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. Our offshore operations are subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than our other oil and natural gas activities. We are vulnerable to the risks associated with operating offshore California, including risks relating to:

In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our offshore operations are conducted in environmentally sensitive areas, including areas with significant residential populations. An accidental oil spill or release on or related to offshore properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and damages could be material to our business, financial condition or results of operations and could subject us to criminal and civil penalties. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.

Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and we cannot be sure the insurance coverage we do obtain will contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

Our business depends in part on pipelines, gathering systems and processing facilities owned by us or 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. For example, our ability to produce and sell oil from the Beta properties will depend on the availability of the pipeline infrastructure between platforms as well as the San Pedro Bay pipeline for delivery of that oil to shore, and any unavailability of that pipeline infrastructure or pipeline could cause us to shut in all or a portion of the production from the Beta properties for the length of such unavailability. 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 with only 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, 2012, based on proved reserve volumes, we operated 68%, Memorial Resource operated 29% and third parties operated 3% of the wells and properties in which we have interests. As a result, the success and timing of drilling and development activities on such properties, depend upon a number of factors, including:

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.

Where we are operator of the wells located on our properties, our operations will be generally governed by operating agreements if any third party has interests in these properties, which agreements typically require the operator to conduct operations in a good and workmanlike manner. For the wells located on our properties that Memorial Resource or a third party is the operator, the operator will generally not be a fiduciary with respect to us or our unitholders. As an owner of working interests in properties not operated by us, we will generally have a cause of action for damages arising from a breach of the operator’s duty.

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 administered by governmental authorities vested with broad authority relating to the exploration for, and the development, production and transportation of, oil and natural gas, as well as environmental and safety matters. 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, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. See “Item 1. Business — Environmental, Health and Safety Matters and Regulations” 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.

Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters. Federal offshore leases are administered by Bureau of Ocean Energy Management, or BOEM. Holders of federal offshore leases are required to comply with detailed BOEM regulations, Bureau of Safety and Environmental Enforcement, or BSEE, regulations and the Outer Continental Shelf Lands Act (OCSLA), which are subject to interpretation and change. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard and the EPA. BSEE has regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. BSEE generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta properties be suspended or terminated. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations.

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.

In addition, in December 2009, 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. 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. 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 is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries.

In addition, many states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. In California, for example, Assembly Bill 32 required the California Air Resources Board, or CARB, to establish and adopt regulations to take effect and become legally enforceable by January 1, 2012 in order to achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020. In October 2011, the CARB adopted the final cap and trade regulation, including a delay in the start of the cap and trade rule’s compliance obligations until 2013. Because our operations associated with our Beta properties emit greenhouse gases, our operations in California may be subject to regulations issued under Assembly Bill 32. These regulations will increase our costs for those operations and adversely affect our operating results. The EPA has also adopted regulations imposing permitting and best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air pollutants” under the existing federal Clean Air Act. Passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect on our operations and the demand for oil and natural gas.

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, Health and Safety Matters and Regulations” 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, or the Dodd-Frank 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 Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank 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. Although many of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC has issued a large number of rules to implement the Dodd-Frank Act, including a rule establishing an “end-user” exception to mandatory clearing, referred to herein as the “End-User Exception,” and a rule imposing position limits, referred to herein as the Position Limit Rule.

We qualify as a “non-financial entity” for purposes of the End-User Exception and, as such, we will be eligible for and expect to utilize such exception and, as a result, our hedging activity will not be subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End-User Exception. The Position Limit Rule was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia on September 28, 2012. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that a position limit rule is ultimately effected, 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 Dodd-Frank 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 Dodd-Frank 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 Dodd-Frank 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’s, or SDWA, Underground Injection Control Program, or UIC Program. On May 4, 2012, the EPA published a draft UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document is designed for use by employees of the EPA that draft the UIC permits and describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas and Louisiana, where we maintain acreage, the EPA is encouraging state programs to review and consider use of such draft guidance. The draft guidance underwent an extended public comment process, which concluded on August 23, 2012. The EPA is presently evaluating the public comments and will likely issue a final guidance document at a later date. 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.

The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and issued a progress report in December 2012. A final draft report is expected to be released for public comment and peer review in 2014. The EPA’s study, depending on its degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. Also, on May 4, 2012, the U.S. Department of Interior issued a draft rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water.

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. Proposed rules are expected in 2013 for coalbed methane and 2014 for shale gas.

Rules recently finalized regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the NSPS and NESHAP programs. The EPA’s final rule includes NSPS standards for completions of hydraulically fractured wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The new rules became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule establishes a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators must either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. On or after January 1, 2015, all newly fractured wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning on August 16, 2012, which is the date the final rule was published in the Federal Register, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA’s final rule, as it may require changes to our operations, including the installation of new emissions control equipment.

We are required to maintain reserve funds to provide for the payment of our proportionate share of decommissioning costs associated with the Beta properties. The estimates of decommissioning costs are inherently imprecise and subject to change due to changing cost estimates, oil and natural gas prices and other factors. If actual decommissioning costs exceed such estimates, or we are required to provide a significant amount of collateral in cash or other security as a result of a revision to such estimates, our financial condition, results of operations and cash flows may be materially adversely affected.

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.

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. Memorial Resource owns 100% of the voting membership interests in our general partner and all of our subordinated units. As of February 28, 2013, Memorial Resource owns an approximate aggregate 24.4% of our outstanding common units. 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:

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 performs 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 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 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 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 natural 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 senior 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 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:

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 24.4% 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 the conflicts committee of the board of directors of our general partner 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:

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 February 28, 2013, Memorial Resource owns our general partner, approximately 24.4% of our outstanding common units, and all of our subordinated units, which together constitutes approximately 36.2% 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.

A default under Memorial Resource’s credit facility could result in a change of ownership or control of our general partner or us, which would be an event of default under our revolving credit facility.

Memorial Resource has pledged all of its common units and subordinated units in us, as well as its ownership interest in our general partner, as security under its senior secured revolving credit facility. That credit facility contains customary and other events of default relating to defaults of Memorial Resource. As a result, our ownership is subject to change if Memorial Resource were to default under its credit facility and Memorial Resource’s lenders exercise their rights over the pledged collateral, even if we do not have any borrowings outstanding under that credit facility. A change of control would constitute an event of default under our revolving credit facility and could affect the market price of our common units.

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 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.

Memorial Resource may sell common units, which sales could have an adverse impact on the trading price of the common units.

As of February 28, 2013, Memorial Resource owns approximately 24.4% of our outstanding common units and all of our subordinated units, which convert into common units at the end of the subordination period. Sales by Memorial Resource of a substantial number of our common units, including common units issued upon the conversion of the subordinated units, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain further capital through additional offerings of equity securities.

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 February 28, 2013, Memorial Resource owns approximately 24.4% 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:

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:

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 Global Market. 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.

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 for federal income tax purposes, 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.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement 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 U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes.

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.

Legislation has been proposed that 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 prorate our items of income, gain, loss and deduction 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 IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

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 the subject of a securities loan (e.g., a loan 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 there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, 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 of their units 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 currently own property and conduct business in Texas, Louisiana, and California. Louisiana and California currently impose 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.

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.

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, 2012.

Our common units are listed and traded on the NASDAQ Global Market under the symbol “MEMP.” Our common units began trading on December 9, 2011 at an initial public offering price of $19.00 per common unit. As of February 28, 2013, there were approximately 34 holders of record of our common units.

As reported by the NASDAQ Global Market, the following table shows the low and high sales prices per common unit and the cash distributions declared per common unit for the periods indicated:

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.

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.

See “Item 11. Executive Compensation — Compensation Discussion and Analysis — Elements of Executive Compensation” for additional information concerning grants of restricted common units under our long-term incentive plan.

Our partnership agreement requires that, within 45 days after the end of each quarter, 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:

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 25.0% of the cash we distribute in excess of $0.54625 per common unit per quarter. The maximum distribution of 25.0% includes distributions paid to our general partner on its 0.1% general partner interest and assumes that our general partner maintains its general partner interest at 0.1%.

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, which amount is defined in our partnership agreement as the minimum quarterly distribution, 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:

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

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:

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:

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 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:

Our general partner’s 0.1% interest in us was represented by 34,317 general partner units at December 31, 2012. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest.

During the year ended December 31, 2012, there were multiple awards of restricted common units that were granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) to executive officers and independent directors of our general partner and other Memorial Resource employees. In conjunction with the issuance of these restricted common units, we issued 178 general partner units and 108 general partner units on January 9, 2012 and October 30, 2012, respectively, to our general partner to maintain its 0.1% interest in us, for which the capital contribution received from our general partner was less than $0.1 million. The issuance of these general partner units was exempt from registration under Section 4(a)(2) of the Securities Act.

In connection with our underwritten public offering of common units in December 2012, we issued 11,987 general partner units to our general partner on December 21, 2012 to maintain its 0.1% interest in us, for which we received a capital contribution of approximately $0.2 million from our general partner. The issuance of these general partner units was exempt from registration under Section 4(a)(2) of the Securities Act.

See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

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, 2012, 2011, 2010, 2009 and 2008 have been derived from our consolidated financial statements and our predecessor and/or the previous owners’ combined financial statements. The combined financial statements of our predecessor are those of BlueStone and the Classic Carve-Out through December 13, 2011 and the WHT Assets for periods after April 8, 2011 through December 13, 2011. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates and the consolidated financial statements of REO from February 3, 2009 (inception) through December 11, 2012. The combined selected financial data of our predecessor and/or the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated those assets separately during those periods.

Comparability of the information reflected in selected financial data. The comparability of the results of operations among the periods presented below is impacted by the following acquisitions:

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.

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

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. The processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds also affects the differential. 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 ICE Brent futures price is a widely used global price benchmark for oil. Refiner’s posted prices for California Midway-Sunset deliveries in Southern California is a regional index. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price or California Midway-Sunset price as a result of quality and location differentials. Quality differentials 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 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).

The oil produced from our onshore properties is a combination of sweet and sour oil, varying by location. This oil is sold at the NYMEX-WTI price, which is adjusted for quality and transportation differential, depending primarily on location and purchaser.

The oil produced from our Beta properties is sour oil. Volumes produced from our Beta properties are currently based on refiner’s posted prices for California Midway-Sunset deliveries in Southern California, which is adjusted primarily for quality and a negotiated market differential. Since 2010, production from our Beta properties has traded at a premium to the NYMEX-WTI price and has more closely tracked the ICE Brent price. We believe this trend will continue for the foreseeable future and on February 1, 2013 executed a basis swap trade that guarantees a price differential to the ICE Brent price covering the remainder of 2013. That basis hedge has not always been available and may not be available going forward or at a price that is economical.

Price Volatility. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. The following table shows the low and high commodity future index prices for the periods indicated:

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 maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point in 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.

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. 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. Texas also 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.

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. During the year ended December 31, 2012, Memorial Resource allocated its 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. In January 2013, Memorial Resource began to allocate its general and administrative costs based on our relative production in comparison to Memorial Resource’s production, which they believe will more accurately reflect the cost incurred to provide services to us. 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 — Related Party Agreements —Omnibus Agreement.”

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):

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, research analysts and rating agencies, to assess:

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.

In 2013, 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.

In 2013, our capital spending program is expected to be approximately $61 to $71 million excluding acquisitions. We anticipate spending approximately 61% in East Texas / North Louisiana, 35% in California and 4% in South Texas, primarily on drilling, recompletions and capital workovers based on the maximum range of our capital spending program. We anticipate spending capital in seventeen or more horizontal Cotton Valley new drills in various fields in East Texas and North Louisiana. We also anticipate spending capital to upgrade our California facilities and drill six additional operated wells from our Beta platforms. We expect the balance of our capital budget will primarily be spent on recompletions and capital workovers in our South and East Texas areas. Without considering potential acquisitions, we expect our aggregate production in 2013 to be approximately 28-30 Bcfe based on internal models.

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 2013 commodity prices include: slow economic growth in the U.S. economy; continuing economic struggles in certain European Union nations’ economies; the Japanese recession; 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.

The U.S. Energy Information Administration, or EIA, expects oil markets to loosen in 2013 and 2014 as increasing global supply more than offsets higher global consumption. The EIA projects the Brent crude oil spot price will fall from an average of $112 per Bbl in 2012 to annual averages of $109 per Bbl and $101 per Bbl in 2013 and 2014, respectively. After averaging $94 in 2012, the WTI price is projected to average $93 per Bbl in 2013 and $92 per Bbl in 2014. By 2014, several pipeline projects from the Mid-continent to the Gulf Coast refining centers are expected to come on line, reducing the cost of transporting crude oil to refiners and narrowing the price difference between WTI and Brent.

The EIA expects U.S. natural gas consumption in 2013 and 2014 to remain relatively stable when compared to 2012. Because of a warm winter last year, 2012 residential and commercial consumption was low, and the hot summer (as well as relatively low natural gas prices) led to record-high use of natural gas for power generation. Forecasts for closer-to-normal temperatures in 2013 and 2014 will lead to increases in natural gas used for residential and commercial space heating and declines in natural gas used for power generation. Despite projected declines in electric power consumption from 2012 levels, consumption of natural gas for electric power generation remains high by historical standards and reflects a structural shift toward using more natural gas for power generation. The EIA currently expects continued growing U.S. natural gas production, driven largely by onshore production in shale areas. Natural gas spot prices averaged $3.33 per MMBtu at the Henry Hub in January 2013, relatively unchanged from December 2012, despite colder weather in January. Through 2014, the EIA expects prices will gradually rise but still remain relatively low. EIA expects the Henry Hub price will average $3.53 per MMBtu in 2013 (compared to $2.75 per MMBtu in 2012) and $3.84 per MMBtu in 2014.

Commodity hedging remains an important part of our strategy to reduce cash flow volatility. Our 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. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information.

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.

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.

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 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 for a vast majority of our proved reserves 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, 2012 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, 2012 would have decreased by approximately $262 million, from $832 million to $570 million.

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, higher operating and development costs, or lower commodity prices. The estimated undiscounted 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.

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 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, 2012 or 2011.

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 credit facilities. Every derivative instrument 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 as we have not elected hedge accounting for any of our derivative positions.

The results of operations for the years ended December 31, 2012, 2011 and 2010 have been derived from both our consolidated financial statements subsequent to the closing of our initial public offering and our predecessor’s and/or previous owners’ combined financial statements. The combined financial statements of our predecessor are those of BlueStone and the Classic Carve-Out through December 13, 2011 and the WHT Assets for periods after April 8, 2011 through December 13, 2011. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates and the consolidated financial statements of REO from February 3, 2009 (inception) through December 11, 2012. The results of operations attributable to our predecessor and/or previous owners 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 Combined Historical Financial Results

The comparability of the results of operations among the periods presented is impacted by the following significant acquisitions:

As a result of the factors listed above, the combined 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.

Net income was $29.9 million for the year ended December 31, 2012, of which $29.7 million was attributable to the previous owners. Net income was $117.6 million for the year ended December 31, 2011, of which $75.7 million was attributable to our predecessor and $35.4 million was attributable to the previous owners. Our predecessor recorded an aggregate gain on the sale of properties of $63.0 million during 2011 with no comparable gain recorded during 2012.

Revenues. Oil, natural gas and NGL revenues for 2012 totaled $139.0 million, a decrease of $5.8 million compared with 2011. Production increased 3,424 MMcfe (approximately 16%) and the average realized sales price (excluding realized gain on derivatives) decreased $1.19 per Mcfe. The favorable volume variance contributed to a $19.4 million increase in revenues, whereas the unfavorable pricing variance contributed to a $25.2 million decrease in revenues.

Lease Operating. Lease operating expenses for 2012 were $44.9 million compared to $42.0 million for 2011, a $2.9 million year-to-year increase. Lease operating expenses increased primarily due to costs associated with properties acquired by both the Partnership from third parties in May and September of 2012 and our predecessor in April and May of 2011. On a per Mcfe basis, lease operating expenses decreased to $1.83 for 2012 from $1.98 for 2011.

Production and Ad Valorem Taxes. Production and ad valorem taxes for 2012 totaled $7.0 million, an increase of $2.2 million compared with 2011. The increase was largely due to a $2.0 million increase in ad valorem taxes primarily due to higher assessed values as a result of increased production levels. Ad valorem taxes are property taxes generally assessed and levied at the local level. The value of the discounted cash flow estimated from future production in the upcoming year is the appraisal methodology used in Texas. There is no production and ad valorem tax assessed for our Beta properties. Production taxes were 2.8% and 2.5% as a percentage of oil and natural gas revenue in 2012 and 2011, respectively.

Depreciation, Depletion and Amortization. DD&A expense for 2012 was $37.9 million compared to $35.2 million for 2011, a $2.7 million year-to-year increase primarily due to increased production volumes related to acquisitions in 2011 and 2012. DD&A expense per Mcfe was $1.54 for 2012 compared to $1.66 for 2011. Increased production volumes caused DD&A expense to increase by $5.2 million, while the 7% change in the DD&A rate between periods caused DD&A expense to decrease by $2.5 million. An increase in proved reserve volumes more than offset the impact of increases to the depletable cost base.

Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes.

Impairment of Proved Oil and Natural Gas Properties. No impairments to proved oil and natural gas properties were recognized during 2012. During 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. All impairments recognized during 2011 were attributable to our predecessor.

General and Administrative. Our general and administrative expenses include the costs of administrative employees and related benefits, management fees paid to Memorial Resource, professional fees and other costs not directly associated with field operations. General and administrative expenses for 2012 were $15.6 million, of which $4.3 million was attributable to our predecessor and the previous owners. General and administrative expenses for 2012 included $1.4 million of non-cash unit-based compensation expense and $3.3 million of acquisition-related costs. General and administrative expenses for 2011 totaled $14.3 million, of which $14.1 million was attributable to our predecessor and the previous owners.

On a per Mcfe basis, general and administrative expenses were $0.63 in 2012 compared to $0.67 in 2011 due to increased production volumes.

Gain on Derivative Instruments. Net gains on commodity derivative instruments of $13.1 million were recognized during 2012, of which $29.2 million was a realized gain and $16.1 million was an unrealized loss. Net gains on commodity derivative instruments of $34.8 million were recognized during 2011, of which $6.8 million was a realized gain and $28.0 million was an unrealized gain.

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

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 2012. 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.

Net Interest Expense. Net 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. Net interest expense totaled $11.3 million during 2012, of which $10.4 million was attributable to the Partnership’s revolving credit facility, including unrealized losses on interest rate swaps of approximately $3.5 million and amortization of deferred financing fees of approximately $0.6 million. Unamortized deferred financing costs associated with the revolving credit facility of the previous owners were approximately $0.4 million at December 31, 2011. The unamortized deferred financing costs associated with this revolving credit facility were written-off at the time their debt was repaid and terminated in December 2012. During 2012 our average outstanding borrowings were $204.3 million. Net interest expense totaled $7.0 million during 2011, of which $6.5 million was attributable to our predecessor and the previous owners. Only $0.5 million was attributable to the Partnership’s revolving credit facility, including unrealized losses on interest rate swaps of $0.3 million.

Net income was $117.6 million for the year ended December 31, 2011, of which $75.7 million was attributable to our predecessor and $35.4 million was attributable to the previous owners. 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. The previous owners recorded net income of $13.0 million for the year ended December 31, 2010, none of which was attributable to the Partnership. Revenues generated for 2011 were $147.0 million compared to $92.1 million for 2010, a $54.9 million year-to-year increase. Our predecessor recorded an aggregate gain on the sale of properties of $63.0 million during 2011 with no comparable gain recorded during 2010. Gains on commodity derivative instruments of $34.8 million were recognized during 2011 compared to gains on commodity derivative instruments of $7.7 million recognized in 2010.

Revenues. Oil, natural gas and NGL revenues for 2011 totaled $144.8 million, an increase of $55.5 million compared with 2010. Production increased 7,752 MMcfe (approximately 58%) and the average realized sales price (excluding realized gain on derivatives) increased $0.17 per Mcfe. The favorable volume and pricing variance contributed to a $51.7 million and $3.8 million increase in revenues, respectively. Production volumes increase 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.

Lease Operating. Lease operating expenses for 2011 were $42.0 million compared to $32.5 million for 2010, a $9.5 million year-to-year increase. 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. On a per Mcfe basis, lease operating expenses decreased to $1.98 for 2011 from $2.43 for 2010.

Production and Ad Valorem Taxes. Production and ad valorem taxes for 2011 totaled $4.8 million, an increase of $2.0 million compared with 2010. The increase in production and ad valorem taxes was largely due to higher onshore oil, natural gas and NGL revenues during 2011. Higher assessed values as a result of higher commodity prices were also a contributing factor. Production taxes were 2.5% and 2.8% as a percentage of oil and natural gas revenue in 2011 and 2010, respectively.

Depreciation, Depletion and Amortization. DD&A expense for 2011 was $35.2 million compared to $29.7 million for 2010, a $5.5 million year-to-year increase primarily due to increased production volumes related to acquisitions in 2010 and 2011. DD&A expense per Mcfe was $1.66 for 2011 compared to $2.22 for 2010. Increased production volumes caused DD&A expense to increase by $17.2 million, while the 25% change in the DD&A rate between periods caused DD&A expense to decrease by $11.7 million. An increase in proved reserve volumes more than offset the impact of increases to the depletable cost base.

Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable cost base changes, then the DD&A rate moves in the same direction. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes.

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 initial public offering 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 $14.3 million, of which $14.1 million was attributable to our predecessor and the previous owners. For 2010, general and administrative expenses were $10.5 million. General and administrative expenses were $0.67 per Mcfe in 2011 compared to $0.79 per Mcfe in 2010 due to increased production volumes.

Gain on Derivative Instruments. Net gains on commodity derivative instruments of $34.8 million were recognized during 2011, of which $6.8 million was a realized gain and $28.0 million was an unrealized gain. Net gains on commodity derivative instruments of $7.7 million were recognized during 2010, of which $7.1 million was a realized gain and $0.6 million was an unrealized gain.

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.

Net Interest Expense. Net interest expense is comprised of interest income, interest on credit facilities, amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Net interest expense totaled $7.0 million during 2011, of which $6.5 million was attributable to our predecessor and the previous owners. Only $0.5 million was attributable to the Partnership’s revolving credit facility including unrealized losses on interest rate swaps of $0.3 million. Net interest expense was $3.4 million in 2010, all of which was attributable to our predecessor and the previous owners. The increase was due primarily to additional debt incurred in conjunction with the acquisitions of oil and natural gas assets by our predecessor.

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. 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 2018 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 estimated production from total proved reserves over a three-to-six 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 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 “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) each quarter 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 securities, 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, 2012, our liquidity of $96.6 million consisted of $7.6 million of available cash and $89.0 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 revolving credit facility. As of December 31, 2012, the borrowing base under our revolving credit facility was $460.0 million and we had $371.0 million of outstanding borrowings. The borrowing base under our revolving credit facility 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 our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. The next borrowing base redetermination is scheduled for April 2013.

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, 2012, 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 credit facility borrowings and debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 8 and Note 10 of the Notes to Consolidated and 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, 2012, we had a positive working capital balance of $31.4 million.

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 securities, 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 2013. 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.

OLLC entered into a $1.0 billion multi-year revolving credit facility at the closing of our initial public offering that matures in December 2016 and is guaranteed by us and all of our current and future subsidiaries. The revolving credit facility had an initial borrowing base of $300.0 million. On December 3, 2012, we entered into a third amendment to our credit agreement, which among other things increased the borrowing base to $460.0 million upon closing of the Beta acquisition. 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. The next borrowing base redetermination is scheduled for April 2013; however, we may seek an interim redetermination if the need arises. 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 Alternative Base Rate defined as 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 or, for the periods ending on March 31, 2013, June 30, 2013, and September 30, 2013, a ratio of Annualized Consolidated EBITDAX to Annualized Consolidated Net Interest Expense (as each term is defined under our revolving credit facility), which we refer to in either case 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 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.

As of December 31, 2012, we were in compliance with all of the financial and other covenants under our revolving credit facility. At December 31, 2012, we had $371.0 million outstanding under our revolving credit facility.

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.

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 estimated production from total proved reserves over a three-to-six year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price hedges exceeding a certain percentage of production.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of December 31, 2012, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.” As of December 31, 2012, the fair value of our open derivative contracts was a net receivable of $14.9 million. All of our derivative contracts are with major financial institutions who are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

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, 2012, we had the following fixed-for-floating interest rate swap open positions whereby we receive the floating rate and pay the fixed rate:

As of December 31, 2012, the fair value of our open derivative contracts was a net receivable of $14.9 million. All of our derivative contracts are with major financial institutions who are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for each of the years in the two-year period ended December 31, 2012 is presented on a combined basis, consisting of the consolidated financial information of the Partnership and the combined financial information of our predecessor and the previous owners. The cash flows for the twelve months ended December 31, 2010 is presented on a combined basis, consisting of the combined financial information of our predecessor and the previous owners. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated and Combined Cash Flows included under “Item 8. Financial Statements and Supplementary Data” contained herein.

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 during 2012 primarily due to an increase in production volumes as a result of properties acquired by the Partnership from third parties in May and September 2012 and our predecessor’s acquisition activities in 2011. We used cash flows provided by operating activities primarily to fund distributions to our partners and additions to oil and gas properties. Our predecessor and the previous owners primarily used cash flows provided by operating activities to fund its exploration and development expenditures.

Investing Activities. Cash used in investing activities during 2012 was $165.8 million, of which $126.9 million was used to acquire oil and natural gas properties and $33.9 million was used for additions to oil and gas properties. See “— Significant Current Developments” for additional information regarding our acquisitions of oil and natural gas properties from third parties. During 2012, we participated in the drilling and/or completion of 9 new wells in South Texas and East Texas/North Louisiana with a success rate of 100%. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. Additions to restricted investments were $4.6 million. See Note 7 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our restricted investments.

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. An additional $47.7 million was used for additions to oil and gas properties. Our predecessor participated in the drilling of 6 gross wells in 2011 with 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. Additions to restricted investments associated with the Beta properties were $5.3 million.

Financing Activities. On December 12, 2012, we issued 10,500,000 common units representing limited partner interests in the Partnership to the public at an offering price of $17.00 per unit generating total net proceeds of $170.0 million after deducting underwriting discounts and offering related expenses. The net proceeds from the offering, including our general partner’s proportionate capital contribution, were used to fund a portion of the purchase price of the Beta acquisition. We distributed approximately $242.2 million as partial consideration to Rise Energy Partners, LP and repaid $28.5 million of indebtedness under the previous owners’ credit facility. The Partnership granted the underwriters a 30-day option to purchase up to an additional 1,575,000 common units at the public offering price, less the underwriting discount, to cover over-allotments. On December 21, 2012, the underwriters exercised their over-allotment option by purchasing an additional 1,475,000 common units, which generated an additional $24.1 million of net proceeds. These net proceeds were used to repay indebtedness under our revolving credit facility.

Distributions to partners for 2012 were $34.4 million, of which Memorial Resource received $19.2 million. We distributed $45.5 million to Memorial Resource in connection with our acquisitions of oil and gas properties from them in April and May 2012. See “— Significant Current Developments” included under “Item 1. Business” for additional information. We also had net borrowings of $251.0 million that were used primarily to fund the acquisitions of oil and gas properties. Also during 2012, we incurred loan origination fees of approximately $1.4 million.

On December 14, 2011, the Partnership completed its initial public offering 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 initial public offering, 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 initial public offering. 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 initial public offering. 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, 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 revolving credit facility.

During 2011, our predecessor and the previous owners had net advances of $117.8 million under their revolving credit facilities. Capital contributions of $57.8 million were used to fund the development and property acquisition program of both our predecessor and the previous owners. The previous owners also made distributions of $65.0 million. Loan origination fees incurred by our predecessor and the previous owners were approximately $1.4 million during 2011.

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash flows provided by operating activities increased during 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. An additional $47.7 was used for additions to oil and gas properties. Our predecessor’s acquisition and development expenditures were partially offset by proceeds from the sale of properties for $2.4 million. Additions to restricted investments associated with the Beta properties were $5.3 million.

During 2010, our predecessor spent $119.5 million on several acquisitions, the largest of which was the purchase of oil and natural gas properties from Forest Oil for $65.9 million. An additional $21.8 million was used for additions to oil and gas properties. Our predecessor’s acquisition and development expenditures were partially offset by proceeds from the sale of properties for $1.4 million. Additions to restricted investments associated with the Beta properties were $3.4 million.

Financing Activities. Total net cash proceeds generated from the Partnership’s December 2011 initial public offering, including the exercise of the underwriters’ over-allotment option, were approximately $157.2 million. During December 2011, there were net advances of $120.0 million under the Partnership’s senior secured revolving credit facility. These incoming funds were used to repay $198.3 million of our predecessor’s credit facilities and distribute $73.6 million to Memorial Resource in exchange for the net assets of our predecessor. Loan origination fees were $2.5 million related to the Partnership’s revolving credit facility.

Our predecessor and the previous owners had net advances of $117.8 million under their revolving credit facilities during 2011. Our predecessor had net advances of $53.5 million under its revolving credit facilities during 2010. Capital contributions of $57.8 million were used to fund the development and property acquisition program of both our predecessor and the previous owners during 2011. Capital contributions of $62.0 million were used to fund the development and property acquisition program of both our predecessor and the previous owners during 2010. The previous owners made distributions of $65.0 million during 2011 compared to $4.4 million during 2010. Loan origination fees incurred by our predecessor and the previous owners were approximately $1.4 million during 2011 compared to $1.6 million during 2010.

See “— Outlook” for additional information regarding our capital spending program for 2013.

In 2013, 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). On February 13, 2013, we paid a $17.4 million cash distribution for the fourth quarter 2012 to our unitholders and our general partner. This distribution represented an annualized amount of $2.03 per unit. Assuming no further changes in the distribution rate and the number of common units, subordinated units and general partner units currently outstanding, the aggregate distribution paid to all of our unitholders in 2013 would total approximately $69.7 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 2013 through a combination of cash from operations, borrowings under our revolving credit facility and the issuance of equity or debt securities.

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 — Related Party Agreements — Omnibus Agreement.” In the table below, we set forth our contractual obligations as of December 31, 2012. 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.

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

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.

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 either NYMEX for natural gas or ICE Brent for oil from a specified delivery point. Our basis protection swaps typically have negative differentials to either NYMEX or ICE. 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.

Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX, ICE, or regional 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, 2012 and the average prices at which the production will be hedged:

In February 2013, the Partnership executed additional oil and NGL derivative contracts. The following table summarizes our derivative contracts after the execution of these additional derivative contracts and the average prices at which the production will be hedged:

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

The change in hedged volumes between the current and preceding fiscal years is primarily due third party acquisitions consummated during 2012.

At December 31, 2012, we had $371.0 million of debt outstanding under our revolving credit facility, with a weighted average interest rate of LIBOR plus 2.50%, or 2.72%. 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.

At December 31, 2012, we had the following fixed-for-floating interest rate swap open positions whereby we receive the floating rate and pay the fixed rate:

Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the variable component of our weighted average interest rate, after giving effect to our interest rate swaps, would be less than $0.1 million per year.

At December 31, 2011, we had the following fixed-for-floating interest rate swap open positions whereby we receive the floating rate and pay the fixed rate:

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 derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. Each of the counterparties to our derivative contracts is a lender in our credit agreement. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $20.0 million against amounts outstanding under our revolving credit facility at December 31, 2012.

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 our 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.

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

As required by Rules 13a-15(b) and 15d-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 Rules 13a-15(e) and 15d-15(e) and 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, 2012.

The Partnership’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Under the supervision and with the participation of the Partnership’s management, including the principal executive officer and principal financial officer of our general partner, the Partnership assessed the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this assessment, the Partnership’s management, including our general partner’s principal executive and financial officers, concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2012 based on the criteria set forth under the COSO Framework.

Based on guidelines established by the SEC, management’s assessment of the effectiveness of the Partnership’s internal control over financial reporting excluded certain operating interests in producing and non-producing oil and gas properties offshore Southern California that were acquired in December 2012 from a related party. This common control acquisition, which was accounted for in a manner similar to a pooling of interests, collectively represented approximately 23% of the Partnership’s total assets as of December 31, 2012 and approximately 43% of the Partnership’s total revenue for the year ended December 31, 2012. For additional information regarding the Beta acquisition, see Note 13 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

KPMG LLP, the independent registered public accounting firm who audited the Partnership’s consolidated and combined financial statements included under “Item 8. Financial Statements and Supplementary Data” in this annual report, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2012. The report, which expresses an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2012, is contained herein under the heading “Report of Independent Registered Public Accounting Firm.”

No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

We have audited Memorial Production Partners LP’s and subsidiaries (the Partnership) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report on Internal Control over Financial Reporting in Item 9A of Form 10-K. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Memorial Production Partners maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As described in the accompanying Management’s Report on Internal Control Over Financial Reporting, management has excluded from its assessment of internal control over financial reporting as of December 31, 2012 certain operating interests in producing and non-producing oil and gas properties offshore Southern California that were acquired in December 2012 from a related party (the Beta acquisition). We have also excluded the Beta acquisition from our audit of internal control over financial reporting. The Beta acquisition represented approximately 23% of the Partnership’s total assets as of December 31, 2012 and approximately 43% of the Partnership’s total revenue for the year ended December 31, 2012.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated and combined balance sheets of Memorial Production Partners LP and subsidiaries as of December 31, 2012 and 2011, and the related consolidated and combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated March 5, 2013 expressed an unqualified opinion thereon and includes an explanatory paragraph noting the Partnership’s consolidated results have been combined with the results pertaining to its predecessor.

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 seven members. The board of directors has determined that Messrs. Clarkson, Highum and Innamorati satisfy the independence standards established by NASDAQ and SEC rules. 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.

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.

The following table sets forth certain information regarding the current directors and executive officers of our general partner as of February 28, 2013.

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 initial public offering 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 from February 2012 to February 2013. 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 School of Law (J.D.), the University of Houston Law Center (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 and Chief Operating Officer since January 2013. Previously, he served as our general partner’s Vice President of Operations and Asset Management from August 2011 to January 2013. 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 Vice President of Corporate Development since January 2013. Previously, he served as our general partner’s Treasurer from June 2011 to April 2012 and Director of Corporate Development from April 2012 to January 2013. 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 has served in the capacity of Chief Financial Officer for Matrix Oil Corporation since May 2012. 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, since March 2012, and the corporate governance committee, since October 2012, of Parker Drilling Company. 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.

Robert A. Innamorati has served as a member of the board of directors of our general partner since August 2012. Mr. Innamorati has served as President of Robert A. Innamorati & Co. Inc., a private investment and advisory firm, since 1995. He previously served as President of a privately-owned diversified investment company with assets in excess of $1.5 billion from 2007 until 2012. Mr. Innamorati also held positions with Banc One Capital Corporation, Drexel Burnham Lambert & Co. Inc. and Blyth Eastman Dillon & Co., Inc. He previously served for six years as a special agent with the United States Secret Service in Washington, D.C. and two years in the United States Marine Corps Reserves. Mr. Innamorati served as a board member of The Texas Rangers Baseball Club until February 2013, where he served as chairman of the compensation committee and as a member of the finance committee. Mr. Innamorati has also served as a board member for several private companies. Mr. Innamorati received a B.S. in Finance from the McIntire School of Commerce and an MBA from the Darden Graduate School of Business Administration, both at the University of Virginia. He also graduated from the U.S. Treasury Department Law Enforcement Officer’s and U.S. Secret Service Schools.

The board believes that Mr. Innamorati’s extensive corporate finance, banking and private equity experience bring substantial leadership skill and experience 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 Senior 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.

Our general partner’s board of directors consists of seven 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.

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.

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, whose members are required to be “independent” under NASDAQ standards as described below.

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 Innamorati currently serve on the audit committee, and Mr. Clarkson serves as the chairman. Messrs. Clarkson, Highum and Innamorati 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. The audit committee held five meetings in 2012.

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 may determine the resolution of the conflict of interest. Any matters approved by the conflicts committee will be deemed to be 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 17 meetings in 2012.

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) 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, 2012 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).

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. We intend to post on our website all waivers of or amendments to the Code of Ethics that are required to be disclosed by applicable law. 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.

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 — Related Party Agreements — Omnibus Agreement.”

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 — Related Party Agreements — 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 reside 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 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.

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.

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. Memorial Resource has designed a compensation program that emphasizes pay-for-performance. Our general partner’s Chief Executive Officer provides periodic recommendations to Memorial Resource regarding the compensation of our general partner’s other named executive officers.

In the future as part of the compensation setting process, Memorial Resource may: (i) examine the compensation practices of our peer companies, (ii) 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, (iii) review and participate in relevant compensation surveys and (iv) retain compensation consultants.

There are three primary elements of compensation that are 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 for 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 reviews 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 and determined based on financial and individual performance. Memorial Resource reviews bonus awards for our general partner’s named executive officers annually to determine award payments for the current fiscal year, as well as to establish award opportunities for the next fiscal year. At the end of each fiscal year, Memorial Resource meets with each executive officer to discuss our performance goals for the upcoming fiscal 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 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 allows for the grant 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.

During the year ended December 31, 2012, our general partner’s named executive officers and independent directors were granted awards of restricted common units as indicated in the following table:

On January 9, 2013, our general partner’s 2012 named executive officers and independent directors were granted additional awards of restricted common units as indicated in the following table:

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 the first, second, and third anniversaries of the date of grant, 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.

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.

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.

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.

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.

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.

The following table includes the compensation earned by our general partner’s named executive officers and allocated to us by Memorial Resource for the years ended December 31, 2012 and 2011.

The following supplemental table presents the components of “All Other Compensation” for each named executive officer for the year ended December 31, 2012:

The following table sets forth certain information with respect to grants of plan-based awards to our named executive officers in 2012.

The following table sets forth certain information with respect to outstanding equity awards at December 31, 2012.

No equity-based awards held by our general partner’s named executive officers vested or were exercised during 2012.

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.

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.

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 their 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.

The following table quantifies our best estimates as to the amounts that each of our named executive officers would be entitled to receive upon a change of control, as applicable, assuming that such event occurred on December 31, 2012 and using our closing common unit price on such date of $17.84. The precise amount that each of our named executive officers would receive cannot be determined with any certainty until a change of control has occurred. Therefore, such amounts should be considered “forward-looking statements.”

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. 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. The following table presents information regarding compensation paid to the independent directors of our general partner during the year ended December 31, 2012.

For 2013, the following compensation has been approved for the non-employee directors:

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.

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.

As of February 28, 2013, the following table sets forth the beneficial ownership of our common and subordinated units that are owned by:

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.

The following table summarizes information about our equity compensation plans as of December 31, 2012:

Memorial Resource controls our general partner and owns approximately 24% 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. Memorial Resource has pledged our common and subordinated units that it owns, as well as its ownership interest in our general partner, as security under its senior secured revolving credit facility in addition to certain other assets of Memorial Resource. As of February 28, 2013, our general partner owns a 0.1% general partner interest in us, evidenced by 34,334 general partner units, and all of our incentive distribution rights.

The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with our formation and, pursuant to arrangements entered into in connection with our initial public offering, 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 initial public offering and, consequently, were not the result of arm’s-length negotiations.

Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC

Memorial Production Partners GP LLC, our general partner and a wholly-owned subsidiary of Memorial Resource, owns a 0.1% general partner interest in us. Under our general partner’s amended and restated limited liability company agreement, our general partner has the following two classes of membership interests:

Subject to certain conditions, a member may transfer, pledge or assign all or any portion of its membership interest in our general partner at any time.

We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.

On December 14, 2011, in connection with the closing of our initial public offering, we entered into an omnibus agreement with our general partner and Memorial Resource.

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 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 and (ii) income taxes attributable to pre-closing ownership or operation of the assets we acquired in connection with our initial public offering, including any income tax liabilities related to such acquisition occurring on or prior to the closing of our initial public offering.

Memorial Resource’s indemnification obligation will survive (i) for three years after the closing of our initial public offering with respect to title defects and (ii) for sixty days after the expiration of the applicable statute of limitations with respect to income taxes. All title claims are subject to a $25,000 per claim de minimus exception and an aggregate $2,000,000 deductible.

Pursuant to the omnibus agreement, we must indemnify Memorial Resource for any liabilities incurred by Memorial Resource attributable to the operating and administrative services provided to us under the omnibus agreement, other than liabilities resulting from Memorial Resource’s bad faith, fraud, gross negligence or willful misconduct. In addition, Memorial Resource must indemnify us for any liability we incur as a result of Memorial Resource’s bad faith or willful misconduct in providing operating and administrative services under the omnibus agreement. Memorial Resource may terminate the omnibus agreement in the event that it ceases to be an affiliate of us and may also terminate the omnibus agreement in the event of our material breach of the agreement, including failure to pay amounts due thereunder in accordance with its terms.

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.

On December 14, 2011, in connection with the closing of our initial public offering, we entered into a 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 initial public offering. 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.

April Acquisition. On April 2, 2012, we acquired certain oil and natural gas producing properties, located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas, from an operating subsidiary of Memorial Resource for a final purchase price of $18.5 million. This transaction, which also included the novation to us of 2012 through 2013 commodity derivative positions, was financed with borrowings under our revolving credit facility.

Memorial Resource, the parent of the seller in that transaction, is owned by the Funds, and each of Messrs. Hersh, Weber, Gieselman and Weinzierl have indirect economic interests in the Funds that entitle them to a portion of the profits generated by the Funds in excess of certain return thresholds. The transaction was approved by the board of directors of our general partner and by its conflicts committee, which is comprised entirely of independent directors.

May Acquisition. On May 14, 2012, we acquired certain oil and natural gas producing properties, located primarily in the Cotton Valley and Travis Peak fields in Panola and Shelby counties in East Texas, from an operating subsidiary of Memorial Resource for a final purchase price of $27.0 million. This transaction, which also included the novation to us of 2012 through 2014 commodity derivative positions, was financed with borrowings under our revolving credit facility.

Beta Acquisition. On December 12, 2012, we acquired all of the outstanding equity interests in REO and its subsidiaries, which collectively own certain operating interests in producing and non-producing oil and gas properties offshore Southern California from Rise Energy Partners, LP for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. This transaction, which also included the novation to us of 2013 through 2015 commodity derivative positions, was funded with borrowings under our revolving credit facility and the net proceeds from our December 12, 2012 public offering of common units. In connection with the Beta acquisition, Memorial Resource entered into a management agreement with its wholly-owned subsidiary pursuant to which Memorial Resource agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with our subsidiary, Rise Energy Beta, LLC, related to the Beta properties in exchange for an annual management fee. Pursuant to such management agreement and in connection with such operating agreements, Memorial Resource will receive approximately $0.4 million from Rise Energy Beta, LLC annually.

The seller in the Beta transaction is owned by two of the Funds, and each of Messrs. Hersh, Weber, Gieselman and Weinzierl have indirect economic interests in those Funds that entitle them to a portion of the profits generated by those Funds in excess of certain return thresholds. The transaction was approved by the board of directors of our general partner and by its conflicts committee, which is comprised entirely of independent directors.

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.

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 currently has a conflicts committee comprised of three independent directors. 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.

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.”

The audit committee of the board of directors of our general partner selected KPMG LLP (“KPMG”), an independent registered public accounting firm, to audit our consolidated and combined financial statements for the year ended December 31, 2012. 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, 2012 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):

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.

Our Consolidated and Combined 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.

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.

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.

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.

We have audited the accompanying consolidated and combined balance sheets of Memorial Production Partners LP and subsidiaries (the Partnership) as of December 31, 2012 and 2011, and the related consolidated and combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated and combined financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated and combined 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, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Memorial Production Partners LP and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Memorial Production Partners LP’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 5, 2013 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

As discussed in Note 1 to the consolidated and combined financial statements, the balance sheets, and the related statements of operations, equity, and cash flows have been prepared on a combined basis of accounting.

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

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 assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana, and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells (often referred to as wellbore assignments).

The Partnership was formed in April 2011 to own and acquire oil and natural gas properties in North America and completed its initial public offering (“IPO”) on December 14, 2011 (see Note 10). The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, Memorial Production Partners GP LLC, which is a wholly owned subsidiary of Memorial Resource Development LLC (“Memorial Resource”). Our general partner is responsible for managing all of the Partnership’s operations and activities.

Memorial Resource is a Delaware limited liability company owned and formed by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. Memorial Resource provides management, administrative, and operations personnel to us and our general partner under an omnibus agreement (see Note 13). 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.

References to “our predecessor” for accounting and financial reporting purposes refers collectively to: (i) BlueStone Natural Resources Holdings, LLC (“Bluestone”) and its wholly-owned subsidiaries in addition to certain carved-out oil and natural gas properties (“Classic Carve-Out”) owned by Classic Hydrocarbons Holdings, L.P. (“Classic”) for all periods prior to the closing of our IPO and (ii) certain oil and natural gas properties owned by WHT Energy Partners LLC (“WHT”) for periods after April 8, 2011 through the closing of our IPO.

References to “the previous owners” for accounting and financial reporting purposes refers collectively to: (i) certain oil and natural gas properties the Partnership acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates and (ii) Rise Energy Operating, LLC and its wholly-owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through date of acquisition.

Both the previous owners and our predecessor operated oil and natural gas properties as one business segment: the acquisition, exploration, development and production of oil and natural gas. Performance was evaluated based on one business segment as there were not different economic environments within the operation of the oil and natural gas properties.

In connection with our IPO, the Funds contributed to Memorial Resource their respective ownership of five separate portfolio companies (including those comprising our predecessor) and we acquired substantially all of the oil and natural gas properties and related assets owned by BlueStone, certain carved-out oil and natural gas properties and related assets owned by Classic and a 40% undivided interest in certain oil and natural gas properties and related assets (the “WHT Assets”) controlled by WHT. 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 borrowings under a senior securing revolving credit facility (see Note 8) and the net cash proceeds generated from our IPO. This dropdown transaction was accounted for as a combination of entities under common control; therefore, the Partnership accounted for the acquisition at historical cost in a manner similar to the pooling of interest method.

The Partnership acquired certain oil and natural gas producing properties from Memorial Resource in April and May 2012. The Partnership acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California in December 2012 from Rise Energy Partners, LP (“Rise”). We refer to this transaction as the “Beta acquisition.” Rise is primarily owned by two of the Funds. Each of these acquisitions was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired was recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisitions as if the Partnership owned the assets for periods after common control commenced through their respective acquisition dates. See Note 13 for additional information.

Our consolidated results of operations following the completion of our IPO are presented together with the combined results of operations pertaining to our predecessor and the previous owners. The combined financial statements were derived from the historical accounting records of our predecessor and the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented. Our predecessor’s combined financial statements reflect the financial statements of BlueStone and Classic Carve-Out through the closing of our IPO and the WHT Assets for periods after April 8, 2011 through December 13, 2011. The previous owners combined financial statements reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates on a combined basis for all periods presented and the consolidated financial statements of REO for all periods presented. The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of REO, is presented as noncontrolling interest in the financial statements.

The Classic Carve-Out amounts included in the accompanying financial statements include allocations for various expenses. Certain expenses incurred by Classic were indirectly attributable to the Classic Carve-Out as Classic owned 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 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 combined financial statements. The accompanying consolidated and 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 to the presentation in the current year financial statements.

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

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

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. Likewise, the combined financial statements include the accounts of BlueStone and the Classic Carve-Out through the closing of our IPO, the WHT Assets for periods after April 8, 2011 through December 13, 2011,certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates on a combined basis, and the consolidated financial statements of REO for all periods presented. All material intercompany balances and transactions have been eliminated.

Recast financial statements filed with the United States Securities and Exchange Commission (“SEC”) on November 20, 2012 through a Form 8-K filing and reported herein have been further recast to include the financial position and results attributable to the consolidated financial statements of REO acquired from Rise in December 2012 for all historical periods presented.

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

Cash balances, accounts receivable, restricted investments 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. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose 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 rely 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, 2012 and 2011, respectively.

If we were to lose any one of our customers, the loss could temporarily delay production and the 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 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 exploration, development and production activities are accounted for 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.

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):

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to prepare portions of our reserves estimates comprising approximately 97% of our estimated proved reserves (by volume) at December 31, 2012.

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.

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense—net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. At December 31, 2012, these restricted investments consisted of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method. Amortization expense for the years ended December 31, 2012, 2011, and 2010 was approximately $1.0 million, $0.9 million, and $1.0 million, respectively. Amortization of debt issuance costs for the year ended December 31, 2012 included a $0.4 million write-off of debt issuance costs as a result of repaying and terminating REO’s credit facility in December 2012.

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 as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

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

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. During the year ended December 31, 2012, Memorial Resource allocated 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 13 for additional information in regards to the omnibus agreement.

General and administrative expenses associated with our predecessor and the previous owners included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production.

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 is recorded on 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 as we have not elected hedge accounting for any of our derivative positions.

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. Certain of our consolidated subsidiaries are taxed as corporations and subject to federal income taxes. We are also 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 arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis.

We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized. There were no uncertain tax positions that required recognition in the financial statements at December 31, 2012 or 2011.

Basic and diluted earnings per unit (“EPU”) is determined by dividing net income or loss available to the limited partners by the weighted average number of outstanding limited partner units during the period. Net income or loss available to the limited partners is determined by applying the two-class method. The two-class method of computing EPU is an earnings allocation formula that determines EPU based on distributions declared. The amount of net income or loss used in the determination of EPU is reduced (or increased) by the amount of available cash that has been or will be distributed to the limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the partnership agreement. The total earnings allocated to the limited partners is determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participate in distributions. See Note 11 for additional information.

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. We currently have no awards subject to performance criteria; however, such awards 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 12 for further information.

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

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 adopted this guidance on January 1, 2012 prospectively and it did not 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. In January 2013, the FASB issued an accounting standard update to clarify the scope of offsetting disclosure requirements. The new disclosure requirements will require the disclosure of both gross and net information about derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions eligible for offset on the balance sheet or subject to a master netting arrangement or similar agreement. 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.

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

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

Our acquisitions of oil and gas properties from Memorial Resource in April and May 2012, as further discussed in Note 13, were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at Memorial Resource’s carrying value. Likewise, our acquisition of REO from Rise in December 2012, as further discussed in Note 13, was also accounted for as a transaction between entities under common control.

Third Party. On May 1, 2012, we acquired non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller (“Undisclosed Seller Acquisition”) for a final net purchase price of approximately $36.5 million after customary post-closing adjustments. The effective date of this transaction was January 1, 2012. This transaction was financed with borrowings under our revolving credit facility. Because this transaction was a joint acquisition with Memorial Resource, the transaction was approved by the board of directors of our general partner (the “Board”) and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. During the year ended December 31, 2012, approximately $4.8 million of revenue and $1.2 million of earnings were recorded in the statement of operations related to the Undisclosed Seller Acquisition subsequent to the closing date.

On September 28, 2012, we acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation (“Goodrich Acquisition”), for a final net purchase price of $90.4 million after customary post-closing adjustments. The effective date of this transaction was July 1, 2012. This transaction was financed with borrowings under our revolving credit facility. These properties are located in the East Henderson field of Rusk County, Texas. During the year ended December 31, 2012, approximately $4.6 million of revenue and $2.0 million of earnings were recorded in the statement of operations related to the Goodrich Acquisition subsequent to the closing date.

The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands).

The following unaudited pro forma combined results of operations are provided for the twelve month periods ended December 31, 2012 and 2011 as though the third-party acquisitions had been completed on January 1, 2011. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership, our predecessor, and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

Acquisition-related costs. Approximately $3.3 million of acquisition-related costs are included in general and administrative expense in the accompanying statements of operations for the year ended December 31, 2012. This amount includes acquisition-related costs for both related party and third party transactions.

Effective January 1, 2011, our predecessor acquired BP’s 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 $20.0 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 the fair value of the assets acquired and liabilities assumed as of April 8, 2011 (in thousands):

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. The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor and the previous owners, 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.

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.

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 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 previous owners as well as 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.

Effective May 1, 2010, our 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):

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 approximately $0.5 million. 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 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 on the balance sheet as a prepaid asset. This acquisition closed on June 4, 2010. As of December 31, 2012, approximately $1.0 million of costs have been incurred and the approximately $0.5 million of remaining environmental accrued liability is recorded as a current liability in accrued liabilities.

Effective September 1, 2010, the previous owners acquired certain oil and gas properties in various counties in East Texas from a third party. This acquisition closed on December 16, 2010. The purchase price allocation resulted in the acquisition date fair value of $15.4 million allocated to proved oil and gas properties and $0.4 million allocated to asset retirement obligations. The Partnership purchased these properties from Memorial Resource on April 2, 2012. See Note 13 for information about the Partnership’s acquisitions of oil and gas properties from Memorial Resource in April 2012 and Note 1 for information regarding basis of presentation.

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.

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 $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.

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. At December 31, 2012 and 2011, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

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

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, 2012 and December 31, 2011. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables.

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

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:

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. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $20.0 million against amounts outstanding under our revolving credit facility at December 31, 2012. See Note 8 for additional information in regards to our revolving credit facility.

A combination of commodity derivatives (e.g., floating-for-fixed swaps, collars, call spreads and basis swaps) is used to manage exposure to commodity price volatility. We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub and regional indices such as NGPL TXOK, TETCO STX, and Houston Ship Channel in proximity to the Partnership’s areas of production. We also enter into oil derivative contracts indexed to NYMEX WTI, Inter-Continental Exchange (“ICE”) Brent and California Midway-Sunset. Our NGL derivative contracts are indexed to OPIS Mont Belvieu. At December 31, 2012, we had the following open commodity positions:

Partnership. Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. At December 31, 2012, we had the following fixed-for-floating interest rate swap open positions whereby we receive the floating rate and pay the fixed rate:

Predecessor. Periodically, our predecessor entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. During the year ended December 31, 2011, our predecessor had the following fixed-for-floating interest rate swap open positions whereby our predecessor received the floating rate and paid the fixed rate:

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 on the balance sheet and the net recorded fair value as reflected on the balance sheet at December 31:

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, 2012, 2011 and 2010:

The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment of wells and related facilities. The following table represents a reconciliation of the asset retirement obligations for the years ended December 31, 2012, 2011, and 2010:

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

The revolving credit facility, which OLLC entered into at the closing of our IPO, is guaranteed by us and all of our current and future subsidiaries and had an initial borrowing base of $300.0 million. On December 3, 2012, we entered into a third amendment to our credit agreement, which among other things: (i) increased the borrowing base to $460.0 million upon closing of the Beta acquisition and (ii) provided us with the ability, if necessary, to incur certain second lien indebtedness. 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. The next borrowing base redetermination is scheduled for April 2013.

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 Alternative Base Rate defined as 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.

The effective weighted average interest rate for the year ended December 31, 2012 was 2.74%. The effective weighted average interest rate includes the impact of the commitment fee and excludes the impact of interest rate hedging activity. The effective weighted average interest rate for the period from December 14, 2011 through December 31, 2011 was 2.81%.

During the year ended December 31, 2012, we incurred additional financing costs in connection with borrowing base redeterminations. These additional costs have been deferred and will be amortized over the life of our revolving credit facility. Unamortized deferred financing costs associated with our revolving credit facility were at the dates indicated:

During the year ended December 31, 2012, the revolving credit facility was primarily used to fund the acquisitions of oil and gas properties from both related parties and third parties. See Note 3 and 13 for additional information regarding these acquisitions.

During the year ended December 31, 2012, borrowings and repayments under our revolving credit facility were $293.0 million and $42.0 million, respectively.

BlueStone had a $150.0 million revolving credit facility. The weighted average interest rate for the years ended December 31, 2011 and 2010 was approximately 3.17% and 3.45%, respectively.

The Classic Carve-Out properties were burdened by debt incurred pursuant to a $150.0 million revolving credit facility extended to Classic. The weighted average interest rate for the years ended December 31, 2011 and 2010 was 3.40% and 3.11%, respectively.

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 $92.0 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%.

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 was 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.”

REO had consolidated debt of $35.0 million outstanding under a $150.0 million revolving credit facility at December 31, 2011. The weighted average interest rate for the years ended December 31, 2012 and 2011 was approximately 3.40% and 3.03%, respectively.

For accounting and financial reporting purposes, the $28.5 million that was repaid concurrently with the closing of the Beta acquisition on behalf of REO was 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.” Unamortized deferred financing costs associated with this revolving credit facility were approximately $0.4 million at December 31, 2011. The unamortized deferred financing costs associated with this revolving credit facility were written-off at the time the debt was repaid and terminated.

A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:

The following summarizes the significant components of deferred tax assets and (liabilities):

Tax carryforwards available for use on future income tax returns at December 31, 2012, were as follows:

On December 12, 2012, we issued 10,500,000 common units representing limited partner interests in the Partnership to the public at an offering price of $17.00 per unit generating total net cash proceeds of $170.0 million after deducting underwriting discounts and offering expenses. Concurrent with the closing of this equity offering, the Partnership distributed cash to Rise and repaid all amounts outstanding under REO’s credit facility as consideration for the Beta acquisition as further discussed under Note 8 and 13. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, partially funded the Beta acquisition.

On December 21, 2012, the underwriters purchased an additional 1,475,000 common units pursuant to their over-allotment option. We used the net proceeds of approximately $24.1 million from the sale of the additional common units, including our general partner’s proportionate capital contribution, to repay indebtedness under our revolving credit facility.

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 the closing of the IPO, the Partnership distributed a combination of cash, common units, and 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 net cash proceeds generated from our IPO partially funded the cash portion of this consideration.

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 underwriting discounts, were $10.7 million. Of this amount, $10.0 million of these net proceeds were used to repay indebtedness under our revolving credit facility.

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

Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 12 for additional information regarding restricted common units that were granted during the year ended December 31, 2012.

As of December 31, 2012, Memorial Resource owned approximately 24.4% of the common units and 100% of the subordinated units. Memorial Resource owns all of the voting interests in our general partner and 50% of the economic interest in our incentive distribution rights. The Funds collectively directly own, through non-voting membership interests in our general partner, 50% of the remaining economic interest in our 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 Distribution Policy “ 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.

Net income (loss) attributable to the Partnership is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control prior to their acquisition date is allocated to the previous owners. For periods prior to our IPO, net income (loss) was attributable to both our predecessor and the previous owners.

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, 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 25.0%, of the cash we distribute in excess of $0.54625 per common unit per quarter. The maximum distribution of 25.0% includes distributions paid to our general partner on its 0.1% general partner interest and assumes that our general partner maintains its general partner interest at 0.1%.

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:

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

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:

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:

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.

The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts):

BlueStone. In February 2006, BlueStone, BlueStone Natural Resources Holdings, LLC (“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, NGP VIII and certain members of Classic’s management 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 Resources, LLC (“WildHorse”) and Tanos Energy, LLC (“Tanos”). In connection with our IPO, NGP IX and NGP IX Offshore contributed to Memorial Resource their respective ownership in 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.

REO. REO, a wholly-owned subsidiary of Rise, was formed in February 2009. The following table summarizes capital contributions received by REO and cash distributions paid by REO with respect to the year indicated (dollars in millions):

The noncontrolling shareholder in the SPBPC made capital contributions of $1.2 million during the year ended December 31, 2010.

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

In December 2011, the Board adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for employees, officers, consultants and directors of the general partner and any of its affiliates, including Memorial Resource, who perform services for the Partnership. The LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a committee thereof. During the year ended December 31, 2012, there were multiple awards of restricted common units that were granted under the LTIP to executive officers and independent directors of our general partners and other Memorial Resource employees.

The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions in which one-third of each award vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in the partnership with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by the Partnership to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

The aggregate fair value of the restricted common units awarded to our general partner’s executive officers and other Memorial Resource employees, which are accounted for as equity-classified awards, was $5.0 million based on the market price per unit on the date of grant. This amount net of forfeitures will be recognized as compensation cost on a straight-line basis over the requisite service period. These awards were granted in recognition of services performed in connection with the completion of our IPO and/or to provide incentive to help drive the Partnership’s future success and to share in the economic benefits of that success. The compensation costs associated with these awards are recorded as direct general and administrative expenses. During the year ended December 31, 2012, we recognized approximately $1.4 million of compensation expense associated with these awards.

The fair value of the restricted unit awards granted to the independent directors of our general partner are also recognized as compensation cost on a straight-line basis over the requisite service period. The compensation costs associated with these awards are recorded as direct general and administrative expenses. During the year ended December 31, 2012, we recognized less than $0.1 million of compensation expense associated with these awards.

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

The unrecognized compensation cost associated with restricted common unit awards was an aggregate $3.7 million at December 31, 2012. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.37 years.

Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to partners as presented on our statements of consolidated and combined cash flows. During the year ended December 31, 2012, the restricted common unitholders received a distribution of approximately $0.2 million. The restricted common unitholders received a distribution of approximately $0.1 million on February 13, 2013 with respect to the quarterly cash distribution for the fourth quarter of 2012 that the Board declared in January 2013.

Subsequent Event. On January 9, 2013, our general partner’s executive officers and independent directors were granted additional awards of restricted common units. The aggregate number of restricted units granted on such date was 16,627.

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

For the year ended December 31, 2012, approximately $2.6 million of related party transactions attributable to the Partnership are reflected as costs and expenses in the accompanying statements of operations. The vast majority of these costs and expenses were payments under our omnibus agreement (as discussed below) and management fees paid to affiliates for operating our assets.

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 and 2010, our predecessor expensed advisory and directors’ fees of approximately $0.2 million and $0.2 million, respectively, to NGP VIII.

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 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.

An affiliate of REO collected a management fee for providing administrative services to REO. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. REO incurred and paid management fees of $1.6 million, $1.7 million and $0.9 million for the years ended December 31, 2012, 2011, and 2010, respectively. These management fees are presented as a component of general and administrative costs and expenses in the accompanying statements of operations.

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:

In connection with our omnibus agreement, we recognized $1.8 million of expense during the year ended December 31, 2012.

Memorial Resource entered into separate agreements with affiliates on our behalf relating to the management, operation and administration of the properties acquired by us on December 14, 2011. Effective May 1, 2012, we record less than $0.1 million monthly for the management fees that Memorial Resource pays to its affiliates and recorded approximately $0.1 million prior to this date.

In connection with the closing of our IPO on December 14, 2011, the Partnership acquired the following net assets of our predecessor:

Acquisition of Oil & Gas Producing Properties from Memorial Resource Subsequent to our IPO

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

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

On December 12, 2012, we acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, from Rise for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. The Beta acquisition was funded with borrowings under our existing credit facility and the net proceeds generated from our December 12, 2012 public offering of common units (including our general partner’s proportionate capital contribution). The effective date for this transaction was September 1, 2012. Terms of the transaction were approved by the Board and by its conflicts committee. The acquired properties, which we refer to as the Beta properties, primarily consist of a 51.75% working interest in three Pacific Outer Continental Shelf blocks covering the Beta Field, and are located in federal waters approximately eleven miles offshore the Port of Long Beach, California. Associated facilities include three conventional wellhead and production processing platforms, a 17.5-mile pipeline and an onshore tankage and metering facility. Two of the platforms are bridge connected and stand in approximately 260 feet of water, while the third platform stands in approximately 700 feet of water. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

On December 12, 2012, in connection with the Beta acquisition, the Partnership contributed to Memorial Resource the entity that employs those who operate and support the Beta properties in exchange for approximately $3.0 million. The net book value of the assets contributed to Memorial Resource was as follows (in thousands):

On July 13, 2012, Memorial Resource entered into a new senior secured revolving credit facility which is guaranteed by our general partner. The credit facility was amended in November 2012. The amended revolving credit facility is a four-year, $120.0 million credit facility with a borrowing base of $120.0 million subject to redetermination. Memorial Resource has pledged 7,061,294 of our common units and 5,360,912 of our subordinated units as security under the credit facility in addition to certain other assets of Memorial Resource.

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, 2012, 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:

At December 31, 2012 and 2011, $0.5 million and $0.8 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.

REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2012, the gross account balance included in restricted investments was approximately $2.0 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $1.2 million at December 31, 2012.

REO assumed an obligation with the BOEM in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met.

In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make additional quarterly payments to the trust account attributable to its net working interest of approximately $0.6 million beginning on June 30, 2010 until the payments and accrued interest attributable to REO equal $78.7 million by December 31, 2016. The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):

In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. As of December 31, 2012, the maximum remaining obligation net to REO’s interest was approximately $17.0 million.

The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2012 (in thousands):

We have leases for offshore Southern California pipeline right-of-way use and office space. We also incur surface rentals related to our business operations. Our predecessor and the previous owners also leased equipment and office space under various operating leases and incurred surface rentals related to their operations.

For the year ended December 31, 2012, we recognized $1.0 million of rent expense. We recognized an immaterial amount of allocated rent expense from the closing our IPO through December 31, 2011, primarily for office space. Our predecessor and the previous owners leased equipment and office space under various operating leases. Our predecessor and the previous owners recorded rent expense of approximately $0.6 million, $0.9 million, and $0.6 million for the years ended December 31, 2012, 2011, and 2010, respectively.

Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year:

Memorial Resource sponsors a defined contribution plan for the benefit of 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. Memorial Resource made contributions to the plan of approximately $0.4 million for the year ended December 31, 2012. Pursuant to our omnibus agreement with Memorial Resource, a portion of this amount was allocated to the Partnership and recognized as an expense.

Effective January 1, 2012, REO assumed sponsorship of a separate defined contribution plan. This plan specifically benefits substantially all those employed by the Memorial Resource subsidiary that operates and supports the Beta properties that have attained 21 years of age. Eligible employees are permitted to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Employer matching contributions of 100% of employee contributions that does not exceed 6% of compensation are made to the plan as well. The employer matching contributions associated with this plan were subject to a three-year graded vesting schedule through February 28, 2012. Effective March 1, 2012, the plan was amended to offer immediate vesting of employer matching contributions. The plan received employer contributions of approximately $0.5 million, $0.5 million, and $0.3 million in 2012, 2011, and 2010, respectively. Approximately $0.3 million, $0.3 million, and $0.1 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for the years ended December 31, 2012, 2011, and 2010, respectively.

Our predecessor also sponsored defined contribution plans for the benefit of substantially all their employees who attained 18 years of age. Matching contributions of up to 6% of an employee’s compensation were made and additional discretionary contributions for eligible employees meeting certain plan requirements was also an option under these plans. Employer contributions of approximately $0.2 million and $0.2 million were made to these other plans in 2011 and 2010, respectively.

The following table presents selected quarterly financial data for the periods indicated. Earnings per unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per unit may not necessarily equal the total for the year.

As discussed in Note 1, we closed our IPO on December 14, 2011. We acquired additional oil and gas properties from Memorial Resource subsequent to our IPO in April and May 2012 and closed the Beta Acquisition in December 2012. The quarterly financial information presented above has been retrospectively revised for common control transactions that the Partnership has consummated in 2012. See Note 2 and 11 for additional information regarding earnings per unit.

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.

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:

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.

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.

NSAI was engaged to prepare portions of our reserves estimates comprising approximately 97% of our estimated proved reserves (by volume) at December 31, 2012. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The weighted-average benchmark 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:

The following tables set forth estimates of the net reserves as of December 31, 2012, 2011 and 2010, respectively:

Noteworthy amounts included in the categories of proved reserve changes for the years 2012, 2011, and 2010 in the above tables include:

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.

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, 2012:

The Partnership anticipates filing a registration statement on Form S-3 with the SEC to register, among other securities, debt securities. The subsidiaries of the Partnership (the “Subsidiaries”) will be co-registrants with the Partnership, and the registration statement will register guarantees of debt securities by one or more of the Subsidiaries (other than Memorial Production Finance Corporation, which may act as co-issuer of such debt securities). The Subsidiaries are 100 percent owned by the Partnership and any guarantees by the Subsidiaries will be full and unconditional. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Partnership, such guarantees will constitute joint and several obligations.


Delaware		90-0726667
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1301 McKinney, Suite 2100, Houston, TX		77010
(Address of principal executive offices)		(Zip Code)


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


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


		Page
	PART I
Item 1.	Business.		9
Item 1A.	Risk Factors.		40
Item 1B.	Unresolved Staff Comments.		70
Item 2.	Properties.		70
Item 3.	Legal Proceedings.		70
Item 4.	Mine Safety Disclosures.		70

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.		71
Item 6.	Selected Financial Data.		75
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		77
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.		100
Item 8.	Financial Statements and Supplementary Data.		104
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.		104
Item 9A.	Controls and Procedures.		104
Item 9B.	Other Information.		106

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.		107
Item 11.	Executive Compensation.		115
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.		124
Item 13.	Certain Relationships and Related Transactions, and Director Independence.		126
Item 14.	Principal Accountant Fees and Services.		131

	PART IV
Item 15.	Exhibits and Financial Statement Schedules.		133
	Signatures		136


	Estimated Net Proved Reserves													Average Net Production					Average Reserve-to- Production Ratio (3)		Producing Wells
Region	Bcfe (1)		% Oil and NGL			% Natural Gas			% Proved Developed			Standardized Measure (2) (in millions)		MMcfe/d		% of Total			Average Reserve-to- Production Ratio (3)		Gross		Net
																			(Years)
South Texas		166.9		16	%		84	%		86	%	$	97.8		24.9		34	%		18.4		516		408
East Texas/North Louisiana		353.5		33	%		67	%		44	%		314.9		38.6		53	%		25.1		1,100		295
California		88.4		100	%		0	%		69	%		419.0		9.4		13	%		25.8		55		28

Total		608.8		38	%		62	%		59	%	$	831.7		72.9		100	%		22.9		1,671		731


Production Volumes:
Oil (MBbls)			18
NGLs (MBbls)			32
Natural gas (MMcf)			710

Total (MMcfe)			1,007

Average net production (MMcfe/d)			10.6


Estimated Proved Reserves
Oil (MBbls)		19,516
NGLs (MBbls)		19,051
Natural gas (MMcf)		377,368

Total (MMcfe) (1)		608,771

Proved developed (MMcfe)		360,622
Proved undeveloped (MMcfe)		248,149
Proved developed reserves as a percentage of total proved reserves		59	%
Standardized measure (in thousands) (2)	$	831,665
Oil and Natural Gas Prices (3)
Oil – NYMEX WTI per Bbl	$	91.22
Natural gas – NYMEX Henry Hub per MMBtu	$	2.757


	Year Ended December 31, 2012
	East Texas / North Louisiana		South Texas		California		Total
Production Volumes:
Oil (MBbls)		133		27		574		734
NGLs (MBbls)		359		—		—		359
Natural gas (MMcf)		8,358		9,662		—		18,020

Total (MMcfe)		11,311		9,824		3,444		24,579

Average net production (MMcfe/d)		31.0		26.8		9.4		67.2

Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	94.79	$	91.09	$	102.96	$	101.04
NGL(per Bbl)		35.95		—		—		35.99
Natural gas (per Mcf)		2.51		3.20		—		2.88

Total (Mcfe)	$	4.11	$	3.40	$	17.16	$	5.65

Average unit costs per Mcfe:
Lease operating expense	$	1.19	$	1.30	$	5.49	$	1.83


	Year Ended December 31, 2011
	East Texas / North Louisiana		South Texas		California		Total
Production Volumes:
Oil (MBbls)		73		24		591		688
NGLs (MBbls)		181		1		—		182
Natural gas (MMcf)		6,883		9,053		—		15,936

Total (MMcfe)		8,405		9,203		3,547		21,155

Average net production (MMcfe/d)		23.1		25.2		9.7		58.0

Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	92.62	$	87.81	$	102.74	$	101.15
NGL (per Bbl)		51.46		82.93		—		51.70
Natural gas (per Mcf)		3.73		4.43		—		4.13

Total (Mcfe)	$	4.96	$	4.60	$	17.12	$	6.84

Average unit costs per Mcfe:
Lease operating expense	$	1.08	$	1.67	$	4.93	$	1.98


	Year Ended December 31, 2010
	East Texas / North Louisiana		South Texas		California		Total
Production Volumes:
Oil (MBbls)		48		14		578		639
NGLs (MBbls)		68		1		—		69
Natural gas (MMcf)		4,012		5,139		—		9,151

Total (MMcfe)		4,708		5,288		3,467		13,403

Average net production (MMcfe)		12.9		14.3		9.5		36.7

Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	75.65	$	74.84	$	72.52	$	72.85
NGL(per Bbl)		40.18		69.93		—		40.95
Natural gas (per Mcf)		3.99		4.65		—		4.36

Total (Mcfe)	$	4.96	$	4.60	$	12.09	$	6.67

Average unit costs per Mcfe:
Lease operating expense	$	1.15	$	1.81	$	5.09	$	2.43


	Oil				Natural Gas
	Gross		Net		Gross		Net
Operated (1)		64		34		1,123		663
Non-operated		—		—		484		34

Total		64		34		1,607		697

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


	Developed Acreage (1)
Region	Gross (2)		Net (3)
South Texas		82,400		72,745
East Texas/North Louisiana		103,498		35,656
California		17,280		8,942

Total		203,178		117,343

(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.


	Undeveloped Acreage
Region	Gross (1)		Net (2)
South Texas		—		—
East Texas/North Louisiana		1,208		168
California		—		—

Total		1,208		168

(1) 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. (2) 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.


	Year Ended December 31,
	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Development wells:
Productive		9.0		2.8		6.0		5.1		4.0		3.7
Dry		—		—		—		—		—		—
Exploratory wells:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total wells:
Productive		9.0		2.8		6.0		5.1		4.0		3.7
Dry		—		—		—		—		—		—

Total		9.0		2.8		6.0		5.1		4.0		3.7


	Years Ending December 31,
	2012			2011			2010
Major customers: (1)
Phillips 66		27	%		(2	)		(2	)
ConocoPhillips (2)		20	%		42	%		52	%
Dominion Gas Ventures, LP		(3	)		13	%		18	%
Enterprise Texas Pipeline, LLC		(3	)		11	%		13	%
(1) Collectively, these major customers purchased production pursuant to existing marketing agreements with terms that are currently on “evergreen” status. Evergreen contracts automatically renew on a month-to-month basis until either party gives 30 or 60 days advance written notice of non-renewal. (2) Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. (3) Accounted for less than 10% of total revenue for the period indicated.


	Common Unit Price Range				Cash Distributions (2)
	High		Low		Cash Distributions (2)
2012
4th Quarter	$	20.75	$	16.50	$	0.5075
3rd Quarter	$	19.14	$	16.40	$	0.4950
2nd Quarter	$	18.79	$	15.71	$	0.4800
1st Quarter	$	19.05	$	16.59	$	0.4800
2011
4th Quarter (1)	$	19.09	$	17.51	$	0.0929


	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	above $0.4750 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	%


	For Year Ended December 31,
	2012			2011			2010			2009			2008
	($ in thousands, except per unit data)
										(Unaudited)			(Unaudited)
Statement of Operations Data:
Revenues:
Oil & natural gas sales	$	138,980		$	144,801		$	89,338		$	32,032		$	56,418
Pipeline tariff income		1,468			1,379			1,332			—			—
Other income		223			825			1,433			319			622

Total revenues		140,671			147,005			92,103			32,351			57,040

Costs and expenses:
Lease operating		44,905			41,966			32,513			12,191			9,239
Pipeline operating		2,114			2,526			1,896			—			—
Exploration		452			332			161			2,690			374
Production and ad valorem taxes		7,046			4,790			2,838			2,032			3,604
Depreciation, depletion, and amortization		37,885			35,218			29,697			19,011			13,835
Impairment of proved oil and natural gas properties		—			15,141			11,800			3,480			18,564
General and administrative		15,569			14,278			10,544			5.845			4,400
Accretion of asset retirement obligations		3,577			3,418			2,924			326			226
(Gain) loss on commodity derivative instruments		(13,100	)		(34,766	)		(7,679	)		(11,121	)		(9,815	)
Gain on sale of properties		(192	)		(63,024	)		(1	)		(7,851	)		(7,395	)
Other, net		734			1,908			1,195			448			50

Total costs and expenses		98,990			21,787			85,888			27,051			33,082

Operating income		41,681			125,218			6,215			5,300			23,958
Other income (expense):
Interest expense, net		(11,339	)		(6,987	)		(3,441	)		(2,937	)		(3,138	)
Amortization of investment premium		(194	)		(606	)		(907	)		—			—

Total other income (expense)		(11,533	)		(7,593	)		(4,348	)		(2,937	)		(3,138	)

Income (loss) before income taxes		30,148			117,625			1,867			2,363			20,820
Income tax benefit (expense)		(231	)		(2	)		(218	)		—			—

Net income		29,917			117,623			1,649			2,363			20,820
Net income (loss) attributable to predecessor		—			75,740			(11,317	)		1,106			21,085
Net income (loss) attributable to previous owners		29,692			35,437			12,974			1,257			(265	)
Net income (loss) attributable to noncontrolling interest		104			(146	)		(8	)		—			—

Net income attributable to partners	$	121		$	6,592		$	—		$	—		$	—

Allocation of net income (loss) attributable to partners:
Limited partners	$	121		$	6,585		$	—		$	—		$	—

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

Earnings per unit attributable to limited partners:
Basic and diluted earnings per unit	$	0.01		$	0.30		$	n/a		$	n/a		$	n/a

Cash distributions declared per unit	$	1.5479		$	n/a		$	n/a		$	n/a		$	n/a


										(Unaudited)			(Unaudited)
Cash Flow Data:
Net cash flow provided by operating activities	$	90,800		$	83,680		$	44,729		$	17,433		$	38,455
Net cash used in investing activities		165,809			189,318			143,770			131,672			63,614
Net cash provided by financing activities		74,307			96,919			110,780			117,953			24,069

							(Unaudited)			(Unaudited)			(Unaudited)
Balance Sheet Data:
Working capital (deficit)	$	31,442		$	27,704		$	19,260		$	10,872		$	(966	)
Total assets		802,051			688,718			469,204			319,723			160,383
Total debt		371,000			155,000			115,428			61,784			62,536
Total equity		327,071			431,933			255,343			194,925			69,346


	High		Low
For Year Ended December 31, 2012:
NYMEX-WTI oil future price range per Bbl	$	109.77	$	77.69
NYMEX-Henry Hub natural gas future price range per MMBtu	$	3.90	$	1.91
ICE Brent oil future price range per Bbl	$	126.22	$	89.23

For Five Years Ended December 31, 2012:
NYMEX-WTI oil future price range per Bbl	$	145.29	$	33.87
NYMEX-Henry Hub natural gas future price range per MMBtu	$	13.58	$	1.91
ICE Brent oil future price range per Bbl	$	146.08	$	36.61


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


	Payments Due by Period (in thousands)
Contractual Obligations	Total		2013		2014- 2015		2016- 2017		Beyond 2017
Revolving credit facility (1)	$	371,000	$	—	$	—	$	371,000	$	—
Estimated interest payments (2)		46,282		11,677		23,434		11,171		—
Asset retirement obligations (3)		75,584		—		876		1,901		72,807
Decommissioning Trust Agreement (4)		16,560		4,140		8,280		4,140		—
Operating leases (5)		3,835		475		925		531		1,904
Compression services		2,766		2,766		—		—		—

Total	$	516,027	$	19,058	$	33,515	$	388,743	$	74,711


	2013			2014			2015		2016		2017		2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		817,672			1,222,125			1,126,112		1,113,275		1,020,067		900,000
Weighted-average fixed price	$	4.33		$	4.34		$	4.28	$	4.53	$	4.30	$	4.75

Collar contracts:
Average Monthly Volume (MMBtu)		633,000			120,000			80,000		—		—		—
Weighted-average floor price	$	4.75		$	5.08		$	5.25	$	—	$	—	$	—
Weighted-average ceiling price	$	5.82		$	6.31		$	6.75	$	—	$	—	$	—

Call spreads (1):
Average Monthly Volume (MMBtu)		430,000			120,000			80,000		—		—		—
Weighted-average sold strike price	$	4.59		$	5.08		$	5.25	$	—	$	—	$	—
Weighted-average bought strike price	$	5.84		$	6.31		$	6.75	$	—	$	—	$	—

Basis swaps:
Average Monthly Volume (MMBtu)		813,432			1,318,750			—		—		—		—
Spread	$	(0.11	)	$	(0.09	)	$	—	$	—	$	—	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		49,632			20,102			12,031		11,013		10,000		—
Weighted-average fixed price	$	106.79		$	94.06		$	90.29	$	90.39	$	88.30	$	—

Collar contracts:
Average Monthly Volume (Bbls)		4,750			39,158			45,000		44,000		42,000		—
Weighted-average floor price	$	87.16		$	94.97		$	90.00	$	85.00	$	85.00	$	—
Weighted-average ceiling price	$	116.94		$	108.91		$	104.34	$	103.40	$	99.00	$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		24,805			16,300			—		—		—		—
Weighted-average fixed price	$	48.72		$	58.91		$	—	$	—	$	—	$	—


	Remaining 2013			2014		2015		2016		2017		2018
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		49,632			56,060		57,031		55,013		52,000		42,000
Weighted-average fixed price	$	106.79		$	99.57	$	96.20	$	93.41	$	90.99	$	90.66

Collar contracts:
Average Monthly Volume (Bbls)		4,736			3,200		—		—		—		—
Weighted-average floor price	$	87.18		$	90.00	$	—	$	—	$	—	$	—
Weighted-average ceiling price	$	116.99		$	117.72	$	—	$	—	$	—	$	—

Basis swaps:
Average Monthly Volume (Bbls)		40,000			—		—		—		—		—
Spread	$	(10.20	)	$	—	$	—	$	—	$	—	$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		39,509			31,850		—		—		—		—
Weighted-average fixed price	$	45.46		$	49.19	$	—	$	—	$	—	$	—


Period Covered		Notional ($ in thousands)		Floating Rate	Fixed Rate

1/17/2012	1/17/2013	$	100,000	1 Month LIBOR	0.600%
1/17/2013	12/14/2016	$	100,000	1 Month LIBOR	1.305%
5/17/2012	1/17/2013	$	50,000	1 Month LIBOR	0.600%
1/17/2013	12/14/2016	$	50,000	1 Month LIBOR	0.970%


Name	Age		Position with our General Partner
John A. Weinzierl		44	President, Chief Executive Officer, and Chairman
Andrew J. Cozby		46	Vice President and Chief Financial Officer
Larry R. Forney		55	Vice President and Chief Operating Officer
Patrick T. Nguyen		40	Chief Accounting Officer
Kyle N. Roane		33	General Counsel and Corporate Secretary
Gregory M. Robbins		34	Vice President, Corporate Development
Jonathan M. Clarkson		63	Director
Scott A. Gieselman		49	Director
Kenneth A. Hersh		50	Director
P. Michael Highum		62	Director
Robert A. Innamorati		65	Director
Tony R. Weber		50	Director


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 and Chief Operating Officer
Patrick T. Nguyen		Chief Accounting Officer
Gregory M. Robbins		Vice President, Corporate Development


Award Recipient	Aggregate Number of Restricted Units
John A. Weinzierl		135,045
Andrew J. Cozby		39,285
Larry R. Forney		28,759
Patrick T. Nguyen		12,413
Gregory M. Robbins		10,663
Jonathan M. Clarkson		3,421
P. Michael Highum		3,511
Robert A. Innamorati		1,535


Name and Position	Year (4)		Salary		Bonus		Equity Awards (5)		All Other Compensation (6)		Total
John A. Weinzierl		2012	$	16,000	$	—	$	2,500,735	$	195,039	$	2,711,774
(President, Chief Executive Officer and Chairman)		2011		1,267		—		—		—		1,267

Andrew J. Cozby		2012	$	40,000	$	23,738	$	703,661	$	51,197	$	818,596
(Vice President and Chief Financial Officer) (1)		2011		3,168		21,823		—		—		24,991

Larry R. Forney		2012	$	40,000	$	20,000	$	508,088	$	35,882	$	603,970
(Vice President and Chief Operating Officer) (2)		2011		3,168		11,040		—		—		14,208

Patrick T. Nguyen		2012	$	32,000	$	8,000	$	222,233	$	17,995	$	280,228
(Chief Accounting Officer)		2011		2,534		7,830		—		—		10,364

Gregory M. Robbins		2012	$	32,000	$	8,000	$	192,238	$	16,289	$	248,527
(Vice President, Corporate Development) (3)		2011		2,534		8,023		—		—		10,557


Name	Quarterly Distributions Paid On LTIP Awards		Other		Total All Other Compensation
John A. Weinzierl	$	193,690	$	1,349	$	195,039
Andrew J. Cozby		48,408		2,789		51,197
Larry R. Forney		33,093		2,789		35,882
Patrick T. Nguyen		15,260		2,735		17,995
Gregory M. Robbins		13,554		2,735		16,289


			Estimated Future Payouts Under Non-Equity Incentive Plan Awards						Estimated Future Payouts Under Equity Incentive Plan Awards						All Other Equity Awards: Number of Restricted Units (#) (1)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Unit and Option Awards (2)
Name	Grant Date		Threshold ($)		Target ($)		Maximum ($)		Threshold (#)		Target (#)		Maximum (#)		All Other Equity Awards: Number of Restricted Units (#) (1)				Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Unit and Option Awards (2)
John A.Weinzierl		1/9/12		—		—		—		—		—		—		129,211		—		—	$	2,400,740
		5/31/12		—		—		—		—		—		—		5,834		—		—		99,995

Andrew J. Cozby		1/9/12		—		—		—		—		—		—		21,053		—		—		391,165
		5/31/12		—		—		—		—		—		—		18,232		—		—		312,496

Larry R. Forney		1/9/12		—		—		—		—		—		—		10,527		—		—		195,592
		5/31/12		—		—		—		—		—		—		18,232		—		—		312,496

Patrick T. Nguyen		1/9/12		—		—		—		—		—		—		6,579		—		—		122,238
		5/31/12		—		—		—		—		—		—		5,834		—		—		99,995

Gregory M. Robbins		1/9/12		—		—		—		—		—		—		6,579		—		—		122,238
		5/31/12		—		—		—		—		—		—		4,084		—		—		70,000


Name	Occurrence of a Change of Control
John A. Weinzierl	$	2,409,203
Andrew J. Cozby		700,844
Larry R. Forney		513,061
Patrick T. Nguyen		221,448
Gregory M. Robbins		190,228


Name	Fees Earned or Paid in Cash ($)		Restricted Unit Awards ($)(2)		All Other Compensation (3)		Total ($)
Jonathan M. Clarkson (1)	$	81,596	$	63,562	$	4,978	$	150,136
P. Michael Highum		58,118		65,024		5,109		128,251
Robert A. Innamorati		30,847		27,077		760		58,684


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 (3)
Memorial Resource (4)		7,061,294		24.41	%		5,360,912		100	%		36.22	%
Kenneth A. Hersh (5)		7,061,294		24.41	%		5,360,912		100	%		36.22	%
Jonathan M. Clarkson		15,013		*			—		—			*
Scott A. Gieselman		—		—			—		—			—
P. Michael Highum		7,603		*			—		—			*
Tony R. Weber		—		—			—		—			—
Robert A. Innamorati (6)		24,927		*			—		—			*
John A. Weinzierl (7)		240,308		*			—		—			*
Andrew J. Cozby		39,715		*			—		—			*
Larry R. Forney		30,464		*			—		—			*
Patrick T. Nguyen		13,595		*			—		—			*
Gregory M. Robbins		11,345		*			—		—			*
All executive officers and directors as a group (twelve persons)		7,450,221		25.75	%		5,360,912		100	%		37.36	%


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	%


*Formation Stage*

The consideration received by our general partner and Memorial Resource prior to or in connection with our initial public offering		• 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 36.2% 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.