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

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 þ

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

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

Indicate by check mark 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 þ

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 þ

The aggregate market value of the common units held by non-affiliates was approximately $1.34 billion on June 30, 2014, 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 20, 2015, the registrant had 84,020,116 common units, and 86,797 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.

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,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or include other “forward-looking” information. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

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 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 located in Texas, Louisiana, Colorado, Wyoming, New Mexico 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, 2014:

On February 23, 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78 million in cash for Memorial Resource’s East Texas and non-core Louisiana oil and gas properties (the “Property Swap”). Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. This transaction has an effective date of January 1, 2015.

The subordination period for the 5,360,912 subordinated units ended on February 13, 2015. All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one to one basis at the end of the subordination period.

In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). Under the MEMP Repurchase Program, units may be repurchased and retired from time to time at our discretion on the open market. The MEMP Repurchase Program does not obligate us to repurchase any dollar amount or specific number of common units and may be discontinued at any time. Through February 1, 2015 we repurchased $41.4 million in common units, which represents a repurchase of 2,809,495 common units.

In July 2014, we and Finance Corp. (collectively, the “Issuers”) completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the subsidiary guarantors named in the indenture and by certain future subsidiaries of the Partnership. The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and

August 1 of each year, commencing February 1, 2015. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers or certain of our subsidiaries, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately. The net proceeds from the notes offering were used to repay a portion of the outstanding borrowings under our revolving credit facility and for general partnership purposes. In January 2015, we repurchased a principal amount of approximately $3.0 million of the 2022 Senior Notes at an average price of 83.000% of the face value of the 2022 Senior Notes. For information regarding the Senior Notes, see Note 8 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

In September 2014, we sold 14,950,000 common units in a public offering (including 1,950,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units). In July 2014, we sold 9,890,000 common units in a public offering (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units). The net proceeds of approximately $541.3 million from these equity offerings, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.

Wyoming Acquisition. In July 2014, we acquired certain oil and natural gas liquids properties in Wyoming from a third party for a purchase price of approximately $906.1 million (the “Wyoming Acquisition”).

Eagle Ford Acquisition. In March 2014, we acquired certain oil and natural gas producing properties in the Eagle Ford from a third party for a purchase price of approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold.

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.

We engaged Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014. The following table summarizes information, based on a reserve report prepared by our internal reserve engineers and audited by NSAI and Ryder Scott (which we refer to as our “reserve report”), about our proved oil and natural gas reserves by geographic region as of December 31, 2014 and our average net production for the three months ended December 31, 2014:

											Average Net				Average
	Estimated Net Proved Reserves										Production				Reserve-to-		Producing Wells
			% Oil		% Natural		% Proved		Standardized				% of		Production
Region	Bcfe (1)		and NGL		Gas		Developed		Measure (2)		MMcfe/d		Total		Ratio (3)		Gross		Net
									(in millions)						(Years)
East Texas/North Louisiana		545		31%		69%		62%	$	684		127.0		55.8%		11.8		1,298		667
Rockies		557		91%		9%		61%		1,236	44.4			19.5%		34.4		819		382
South Texas		190		32%		68%		79%		321	32.8			14.4%		15.9		703		426
Permian		87		96%		4%		51%		175	11.7			5.1%		20.4		546		493
California		75		100%		0%		69%		344	11.9			5.2%		17.3		58		30
Total		1,454		62%		38%		63%	$	2,760	227.8			100.00%		17.5		3,424		1,998

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 publicly traded Delaware corporation focused on the exploration, development and acquisition of natural gas and oil properties. Memorial Resource is engaged in its business with the objective of growing its reserves, production and cash flows.

Memorial Resource owns all of the voting interests in our general partner, which owns 50% of our incentive distribution rights. Our general partner is party to an omnibus agreement with a wholly owned subsidiary of Memorial Resource and the Partnership in which Memorial Resource has agreed to provide the administrative, management and operational services that we believe are necessary to allow our general partner to manage, operate and grow our business.

As of December 31, 2014, Memorial Resource had total estimated proved reserves of approximately 1,632 Bcfe, primarily located in East Texas, North Louisiana and the Rockies. 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.

Because it is entitled to 50% of any cash distributed with respect to our incentive distribution rights and it controls our general partner, we believe Memorial Resource will be motivated to support the successful execution of our business strategy and will provide us with opportunities to pursue acquisitions that will be accretive to our unitholders. Memorial Resource views our partnership as part of its growth strategy, and we believe that Memorial Resource will be incentivized to contribute or sell additional assets to us and to pursue acquisitions jointly with us in the future. However, Memorial Resource regularly evaluates acquisitions and dispositions and may elect to acquire or dispose of properties in the future without offering us the opportunity to participate in those transactions. Although we believe Memorial Resource is incentivized to offer properties to us for purchase, Memorial Resource has no obligation to sell or offer properties to us.

Founded in 1988, NGP is a family of private equity investment funds organized to make investments in the energy and natural resources sectors. NGP is part of the investment platform of NGP Energy Capital Management, a premier investment franchise in the natural resources industry with $16.5 billion in cumulative committed capital under management 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 control MRD Holdco, which together with a group controls Memorial Resource. MRD Holdco is our largest unitholder as of February 13, 2015, holding 5,360,912 common units (approximately 6% of all outstanding). The Funds collectively indirectly own 50% of our incentive distribution rights. The remaining 50% of our incentive distribution rights is owned by our general partner, which 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. However, neither NGP nor the Funds has any obligation to provide any such access or opportunities to us.

Approximately 37% of our estimated proved reserves as of December 31, 2014 and approximately 56% of our average daily net production for the three months ended December 31, 2014 were located in the East Texas/North Louisiana region. Our East Texas/North 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 545 Bcfe of estimated net proved reserves as of December 31, 2014 based on our reserve report and generated average net production of 127.0 MMcfe/d for the three months ended December 31, 2014. 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. For information regarding the Property Swap, see “—Recent Developments—2015 Acquisition” contained herein.

Approximately 38% of our estimated proved reserves as of December 31, 2014 and approximately 20% of our average daily net production for the three months ended December 31, 2014 were located in the Rockies region. Our Rockies properties are primarily located in Larimer and Weld Counties of Colorado and Carbon, Lincoln, Sublette, Sweetwater and Uinta Counties of Wyoming. Key fields include the Lost Soldier and Wertz fields. Our Rockies properties contained 84.2 MMBbls and 51.5 Bcf of estimated net proved reserves of oil and natural gas, respectively, as of December 31, 2014 based on our reserve report and generated average net production of 44.4 MMcfe/d for the three months ended December 31, 2014.

Based on our reserve report, the Lost Soldier field contains more than 15% of our total estimated reserves. The oil properties in this field were acquired in July 2014 in the Wyoming Acquisition. The following table summarizes production volumes from this field from the date of acquisition through December 31, 2014:

Approximately 13% of our estimated proved reserves as of December 31, 2014 and approximately 14% of our average daily net production for the three months ended December 31, 2014 were located in the South Texas region. Our South Texas properties include wells and properties in numerous natural gas weighted fields located in Dewitt, Karnes, McMullen, Live Oak, Duval, Jim Hogg, Webb and Zapata Counties, Texas, including the Eagleville, NE Thompsonville, Laredo and East Seven Sisters fields. Our South Texas properties also include oil and natural gas producing properties acquired in the Eagle Ford Acquisition. Our South Texas properties contained 190 Bcfe of estimated net proved reserves as of December 31, 2014 based on our reserve report. Those properties collectively generated average net production of 32.8 MMcfe/d for the three months ended December 31, 2014.

Approximately 6% of our estimated proved reserves as of December 31, 2014 and approximately 5% of our average daily net production for the three months ended December 31, 2014 were located in the Permian Basin region of West Texas and New Mexico. Our Permian Basin properties include wells in Andrews, Archer, Baylor, Cochran, Coke, Crane, Crockett, Dawson, Ector, Gaines, Glasscock, Hockley, Jones, Loving, Pecos, Runnels, Shackelford, Terry, Tom Green, Ward, Winkler and Yoakum Counties of Texas and Eddy County of New Mexico. Key fields include the Anita, Atoka, Bronte, Dimmitt, Elkhorn, Hendrick, Kingdom Abo and North Square Lake fields. Our Permian Basin properties contained 13.9 MMBbls and 3.5 Bcf of estimated net proved reserves of oil and natural gas, respectively, as of December 31, 2014 based on our reserve report and generated average net production of 11.7 MMcfe/d for the three months ended December 31, 2014.

Approximately 5% of our estimated proved reserves as of December 31, 2014 and approximately 5% of our average daily net production for the three months ended December 31, 2014 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 12.5 MMBbls of estimated net proved reserves as of December 31, 2014 based on our reserve report. The Beta properties collectively generated average net production of 1,989 Bbls/d for the three months ended December 31, 2014.

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 Beta properties also 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.

Internal Controls. Our proved reserves were estimated at the well or unit level and audited for reporting purposes by NSAI and Ryder Scott, our independent reserve engineers. Memorial Resource maintains internal evaluations of our reserves in a secure reserve engineering database. NSAI and Ryder Scott interact 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 audit 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 audited by NSAI and Ryder Scott at least annually.

Our internal professional staff works closely with NSAI and Ryder Scott to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve audit process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide NSAI and Ryder Scott 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 audit of our reserves.

Internal Engineers. John D. Williams is the technical person at Memorial Resource primarily responsible to liaison with and provide oversight of our third-party reserve engineers, which audited the internally prepared reserve report for our properties. 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 18 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 a M.S. in petroleum engineering.

Ryder Scott Company, L.P. Ryder Scott is an independent oil and natural gas consulting firm. No director, officer, or key employee of Ryder Scott has any financial ownership in us, the Funds, or any of their respective affiliates. Ryder Scott’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported. Ryder Scott has not performed other work for us, the Funds, or any of their respective affiliates that would affect its objectivity. The audit of estimates of our proved reserves presented in the Ryder Scott reports were overseen by Miles Robert Palke.

Miles Palke has been practicing consulting petroleum engineering at Ryder Scott since 2010. Mr. Palke is a Licensed Professional Engineer in the State of Texas and has over 18 years of practical experience in petroleum engineering, with over 18 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M with a B.S. in petroleum engineering and from Stanford University with a M.S. in petroleum engineering.

Mr. Palke meets or exceeds 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; he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

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 audit of estimates of proved reserves at December 31, 2014 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. Eric J. Stevens; Mr. Craig H. Adams; Mr. Nathan C. Shahan and Mr. William J. Knights.

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 14 years of practical experience in petroleum engineering, with over 14 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 29 years of practical experience in petroleum geosciences, with over 16 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 16 years of practical experience in petroleum engineering, with over 10 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.

Eric Stevens has been practicing consulting petroleum engineering at NSAI since 2007. Mr. Stevens is a Licensed Professional Engineer in the State of Texas (License No. 102415) and has over 12 years of practical experience in petroleum engineering, with over 12 years of experience in the estimation and evaluation of reserves. He graduated from Brigham Young University in 2002 with a B.S. in mechanical engineering.

Craig Adams has been practicing consulting petroleum engineering at NSAI since 1997. Mr. Adams is a Licensed Professional Engineer in the State of Texas (License No. 68137) and has over 30 years of practical experience in petroleum engineering, with over 18 years of experience in the estimation and evaluation of reserves. He graduated from Texas Tech University in 1985 with a B.S. in petroleum engineering.

Nathan Shahan has been practicing consulting petroleum engineering at NSAI since 2007. Mr. Shahan is a Licensed Professional Engineer in the State of Texas (License No. 102389) and has over 13 years of practical experience in petroleum engineering, with over 8 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 2002 with a B.S. in petroleum engineering and in 2007 with a M.E. in petroleum engineering.

William Knights has been practicing consulting petroleum geoscience at NSAI since 1991. Mr. Knights, is a Licensed Professional Geoscientist in the State of Texas, Geology (License No. 1532), and has over 10 years of prior industry experience. He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology and in 1984 with a Master of Science Degree in Geology.

All eight 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 eight 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, 2014, based on our internally prepared reserve report audited by NSAI and Ryder Scott, 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, 2014 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, our drilling and development programs have been substantially funded from 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.”

During the fiscal year ended 2014, our proved undeveloped reserves increased 134.9 Bcfe, from 398.2 Bcfe to 533.1 Bcfe. We made approximately $164.0 million of capital expenditures during the year ended December 31, 2014 to convert approximately 112 Bcfe of proved undeveloped reserves to proved developed reserves. This decrease of 112 Bcfe was offset by a 246.9 Bcfe increase in proved undeveloped reserves during the year ended December 31, 2014 primarily due to acquisitions, reserve additions and price revisions.

For a description of our 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 summarize our average net production, average sales prices by product and average production costs by geographic region for the years ended December 31, 2014, 2013 and 2012, respectively:

	Year Ended December 31, 2014
	Oil				NGLs				Natural Gas				Total
			Average				Average				Average				Average		Lease
	Production		Sales		Production		Sales		Production		Sales		Production		Sales		Operating
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price		Expense
	(MBbls)		($/bbl)		(MBbls)		($/bbl)		(MMcf)		($/Mcf)		(MMcfe)		($/Mcfe)		($/Mcfe)

East Texas/North Louisiana		497	$	89.11		1,741	$	28.16		30,195	$	3.91		43,620	$	4.85	$	0.80
Rockies		875		79.83		225		48.50		3,508		3.95		10,109		9.36		3.16
Permian		664		85.51		—		—		529		5.67		4,512		13.24		6.44
South Texas		419		87.62		177		27.02		7,262		3.88		10,841		6.43		1.55
California		637		86.03		—		—		—		—		3,820		14.34		5.77
Total		3,092	$	84.88		2,143	$	30.20		41,494	$	3.93		72,902	$	6.72	$	1.85

Average net production (Mmcfe/d)														199.7

	Year Ended December 31, 2013
	Oil				NGLs				Natural Gas				Total
			Average				Average				Average				Average		Lease
	Production		Sales		Production		Sales		Production		Sales		Production		Sales		Operating
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price		Expense
	(MBbls)		($/bbl)		(MBbls)		($/bbl)		(MMcf)		($/Mcf)		(MMcfe)		($/Mcfe)		($/Mcfe)

East Texas/North Louisiana		383	$	100.61		1,368	$	31.26		24,946	$	3.33		35,450	$	4.64	$	0.80
Rockies		75		88.95		17		30.88		2,739		3.62		3,291		5.19		1.62
Permian		731		93.59		—		—		650		4.81		5,038		14.21		4.18
South Texas		26		91.31		247		32.08		7,589		3.00		9,228		3.58		1.41
California		549		100.31		—		—		—		—		3,296		16.72		6.36
Total		1,764	$	96.98		1,632	$	31.38		35,924	$	3.31		56,303	$	6.06	$	1.58

Average net production (Mmcfe/d)														154.3

	Year Ended December 31, 2012
	Oil				NGLs				Natural Gas				Total
			Average				Average				Average				Average		Lease
	Production		Sales		Production		Sales		Production		Sales		Production		Sales		Operating
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price		Expense
	(MBbls)		($/bbl)		(MBbls)		($/bbl)		(MMcf)		($/Mcf)		(MMcfe)		($/Mcfe)		($/Mcfe)

East Texas/North Louisiana		247	$	94.60		745	$	36.78		16,853	$	2.51		22,804	$	4.08	$	1.18
Rockies		75		85.78		—		—		2,576		2.71		3,026		4.44		1.42
Permian		596		90.22		—		—		653		4.46		4,231		13.40		4.10
South Texas		27		91.09		—		—		9,662		3.20		9,824		3.40		1.30
California		574		102.96		—		—		—		—		3,444		17.16		5.49
Total		1,519	$	95.54		745	$	36.78		29,744	$	2.82		43,329	$	5.90	$	1.85

Average net production (Mmcfe/d)														118.4

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, 2014.

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2014, substantially all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2014 relating to our leasehold acreage.

The following table sets forth information as of December 31, 2014 relating to our undeveloped leasehold acreage (including the remaining terms of leases and concessions).

Our drilling activities consist entirely of development wells. The following table sets forth information with respect to wells drilled and completed by us 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. At December 31, 2014, 12.0 gross (8.0 net) wells were in various stages of completion.

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, 2014, the Partnership or Memorial Resource is the operator of record of the properties containing 93% of our total estimated 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 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 or their affiliates, 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, costless 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. Conditions sometimes arise where actual borrowings are less

than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged.

It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit facility are counterparties to our derivative contracts. 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. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete. Hydraulic fracturing is a necessary part of the completion process because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. Nearly all of our proved non-producing and proved undeveloped reserves associated with future drilling, recompletion, and refracture stimulation projects, or approximately 36% of our total estimated proved reserves as of December 31, 2014, require hydraulic fracturing.

We have and continue to follow applicable industry standard practices and legal requirements for groundwater protection in our operations which are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). 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 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. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements.

Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it in a way that minimizes the impact to nearby surface water by disposing into approved disposal or injection wells. We currently do not discharge water to the surface.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “—Regulation of Environmental and Occupational Health and Safety Matters—Hydraulic Fracturing.”

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

Onshore and Offshore Insurance Program. We and Memorial Resource maintain insurance coverage against potential losses that we believe is customary in the industry. As of December 31, 2014, 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/$2.0 million in the aggregate and a $250,000 self-insured retention. 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 automobile liability insurance has limits of $1.0 million per occurrence. Our umbrella/excess liability limits for each occurrence is a minimum of $25.0 million. There is no deductible on our umbrella/excess liability insurance. 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 and exhausted. In addition, we maintain an energy package policy that includes control of well coverage (“COW”) with per occurrence limits for COW ranging from $10.0 million to $100.0 million and retentions ranging from $100,000 to $500,000. Specific to offshore operations, the energy package policy also includes loss of production income coverage insuring us against a loss up to $64.8 million due to a temporary interruption in the oil supply from our offshore facilities as a result of an insured physical loss to our offshore facilities. Our control of well policy insures us for blowout risks associated with drilling, completing and operating our wells. We maintain two separate Pollution Legal Liability (“PLL”) policies, one for all U.S. onshore operations, excluding California and one for California only. Our PLL non-California insurance policy has limits of $10.0 million per pollution event with a $1.0 million deductible. Our PLL California-only insurance policy has limits of $10.0 million with a $50,000 deductible per event.

As of December 31, 2014, we have insurance policies in effect that are intended to provide coverage for pollution losses including those related to our hydraulic fracturing operations. 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’ bodily 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 generally agree to indemnify us for liabilities arising from bodily 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 generally 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 may incur costs or liabilities 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.

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, occupational 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. The Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the Minerals Management Service) was replaced by the Bureau of Ocean Energy Management, or BOEM, and the Bureau of Safety and Environmental Enforcement, or BSEE, 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 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 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. The 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. The BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. The 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, the 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 the BOEM and BSEE regulations are frequently changed and subject to new interpretations.

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as CERCLA or the Superfund law, and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed “responsible parties.” These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. 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. Also, comparable state statutes may not contain a similar exemption for petroleum. 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, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities of $350 million per spill. 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 have adopted oil-spill prevention regulations that overlap with federal regulations.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, or RCRA, as amended, and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. It is possible, however, that these wastes, which could include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-

categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

It is possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials, or NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with the requirements of CERCLA, RCRA, OPA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

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

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

We use hydraulic fracturing extensively in our operations. Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the SDWA involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Also, the EPA is updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in early 2016. In addition, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014. In addition, Congress has from time to time considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Also, in the near future we may be subject to regulations that restrict our ability to discharge water produced as part of our production operations, and the ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. The EPA is currently developing effluent limitation guidelines that may impose federal pre-treatment standards on oil and gas operators transporting wastewater associated with hydraulic fracturing activities to publicly owned

treatment works for disposal. The EPA plans to propose such standards by early 2015. In addition, in May 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The revised proposed rule would require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. The Bureau of Land Management planned to issue a final rule in 2014; however, the final release of those rules are still pending.

Further, in April 2012, the EPA released final rules that subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the new source performance standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The rules include NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rules seek to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules could require a number of modifications to our operations including the installation of new equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely to be responsive to some of these requests. On September 23, 2013, the EPA finalized the portion of the rules addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. On December 19, 2014, the EPA released final updates and clarifications to the NSPS standards. In addition, on January 14, 2015, the EPA announced a series of steps it plans to take to address methane and smog-forming VOC emissions from the oil and gas industry. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Several states have adopted, or are considering adopting, regulations requiring the disclosure of the chemicals used in hydraulic fracturing and/or otherwise impose additional requirements for hydraulic fracturing activities. For example, in October 2011, the Louisiana Department of Natural Resources adopted new rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. Also, Texas requires oil and natural gas operators to disclose to the Texas Railroad Commission and the public the chemicals used in the hydraulic fracturing process, as well as the total volume of water used. On October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, amongst other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments also clarify the Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The disposal well rule amendments became effective November 17, 2014. Furthermore, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The “well integrity rule” took effect in January 2014. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices, which could lead to increased regulation. For example, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has also commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012, and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review is still pending. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

A number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have adversely impacted drinking water supplies, use of surface water, and the environment generally. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. 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. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

The federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or 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 of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in April 2012, the EPA released final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and NESHAPS programs. The rules include NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rules seek to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules could require a number of modifications to our operations including the installation of new equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely to be responsive to some of these requests. On September 23, 2013, the EPA finalized the portion of the rules addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. On December 19, 2014, the EPA released final updates and clarifications to the NSPS standards. In addition, on January 14, 2015, the EPA announced a series of steps it plans to take to address methane and smog-forming VOC emissions from the oil and gas industry.

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.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, in May 2010, the EPA adopted regulations under existing provisions of the federal Clean Air Act, or CAA, that, among other things, established Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. The so-called Tailoring Rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the PSD and Title V programs of the Clean Air Act. On June 23, 2014, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD or Title V programs. The EPA has announced that it is currently evaluating the decision and awaiting further action by the courts, and that it will provide relevant guidance on GHG permitting requirements.

In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, 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 adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the Obama Administration has announced in its Climate Action Plan that it intends to adopt additional regulations to reduce emissions of GHGs in the coming years, possibly including further restrictions on emissions of methane from oil and natural gas facilities.

Restrictions on GHG emissions that may be imposed in various states could adversely affect the oil and natural gas industry. Any GHG regulation could increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric driven compression at facilities to obtain regulatory permits and approvals in a timely manner. While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our development and production operations.

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. All of our current development and production activities, as well as proposed development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

The federal Endangered Species Act, or ESA, and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. For instance, the American burying beetle and the lesser prairie chicken both have habitat in some areas where we operate. The U.S. Fish and Wildlife Service, or FWS, identified the lesser prairie chicken, which inhabits portions of Colorado, Kansas, Nebraska, New Mexico, Oklahoma and Texas, as candidate for listing in 1998 and has listed it as “threatened” in March 2014. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The threatened species status of the lesser prairie chicken is currently subject to a pending lawsuit by at least three states. The lawsuit challenges FWS’ recent classification of the lesser prairie chicken. The presence of protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations and financial position.

We are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements.

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.

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, 2014, Memorial Resource had 505 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 500 Dallas Street, Suite1800, Houston, Texas 77002. 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 our current quarterly distribution, 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 at our current rate or at all.

Oil, natural gas and NGL prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.

Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2014, the NYMEX-WTI oil future price ranged from a high of $113.93 per Bbl to a low of $53.27 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.15 per MMBtu to a low of $1.91 per MMBtu. Recently, oil and natural gas prices have declined significantly. Through December 31, 2014, the West Texas Intermediate posted price had declined from a high of $107.26 per Bbl on June 20, 2014 to $53.27 per Bbl on December 31, 2014. In addition, the Henry Hub spot market price had declined from a high of $6.15 per MMBtu on February 19, 2014 to a low of $2.89 per MMBtu on December 31, 2014. Likewise, NGLs have suffered significant recent declines in realized prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics. A further or extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition and could cause us to reduce the distributions we pay to our unitholders or to cease paying distributions.

If commodity prices decline further 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.

As discussed above, recently oil, natural gas and NGL prices have declined significantly. A further or extended decline in commodity prices could 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 that 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 results of operations and 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 a derivative contract and, accordingly, prevent us from realizing the benefit of such a derivative contract.

Our estimated reserves and future production rates are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our 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. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.

In order to prepare our estimates, we must project production rates and timing of operating and development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary.

The process also requires economic assumptions about matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds.

Actual future production, oil prices, natural gas prices, revenues, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

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 that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash available for distribution.

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 often involves unprofitable efforts, not only from dry holes, but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then-realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of our development and production activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our development and production operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our unitholders may be adversely affected. 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.

The production from the properties acquired in the Wyoming Acquisition could be adversely affected by the cessation or interruption of the supply of CO₂ to those properties.

We inject water and CO₂ into formations on substantially all of the Wyoming Acquisition properties to increase production of oil and natural gas. The additional production and reserves attributable to the use of enhanced recovery methods are inherently difficult to predict. If we are unable to produce oil and gas by injecting CO₂ in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected. Additionally, our ability to utilize CO₂ to enhance production is subject to our ability to obtain sufficient quantities of CO₂. If, under our CO₂ supply contracts, the supplier is unable to deliver its contractually required quantities of CO₂ to us, or if our ability to access adequate supplies is impeded, then we may not have sufficient CO₂ to produce oil and natural gas in the manner or to the extent that we anticipate, and our future oil and gas production volumes will be negatively impacted.

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. We cannot predict in advance of drilling, testing and analysis of data whether any particular drilling location will yield production in sufficient quantities to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate may decline and

materially harm our business. Our ability to drill, recomplete and develop 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, drilling results, construction of infrastructure and lease expirations. 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.

Part of our strategy involves using horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

Risks that we face while completing our wells include, but are not limited to, the following:

If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical, which could have a material adverse impact on our financial condition, results of operations and cash available for distribution.

SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.

The unavailability or high cost of rigs, equipment, supplies 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, supplies and crews and can lead to shortages of, and increasing costs for, development equipment, supplies, 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. In addition, some of our

operations require supply materials for production, such as CO₂, which could become subject to shortages and increased costs. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and impact our development plan, which would thus affect our financial conduction, results of operations and 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.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

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

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, all of which could cause substantial financial losses. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The location of any 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. The occurrence of any of these or other similar events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension or disruption of operations, substantial revenue losses and repairs to resume operations.

We maintain insurance coverage against potential losses that we believe is customary in the industry. However, insurance against all operational risk is not available to us. These insurance 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. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. A loss not fully covered by insurance could have a material adverse effect on our business, financial position, results of operations and cash available for distribution.

The Beta properties are located in an area where we have limited operating experience, 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.

Development and production of oil and natural gas in offshore waters has inherent and historically higher risk than similar activities onshore.

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.

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

Our properties are located in Texas, Louisiana, offshore Southern California, Colorado, Wyoming and New Mexico. 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. The loss of those customers, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition and results of operations.

We had two customers that each accounted for 10% or more of total reported revenues for the year ended December 31, 2014. The loss of these customers or any significant customer, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition, results of operations and ability to make cash distributions. Also, if any significant customer reduces the volume it purchases 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. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production. See “Item 1. Business — Operations — Marketing and Major Customers.”

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

We are subject to credit risk due to concentration of our oil and natural gas receivables. The inability or failure of our significant customers, or any purchasers of our production, to meet their payment obligations to us or their insolvency or liquidation 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.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 be unable to pay the minimum quarterly distribution or our current quarterly distribution 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.

The terms of our indebtedness include 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, the indentures governing our senior notes 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 revolving 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 further 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.

The terms and conditions governing our indebtedness, including our senior notes and our revolving credit facility:

We may not be able to generate enough cash flow to meet our debt obligations and may be forced to take other actions to satisfy our debt obligations that may not be successful.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Moreover, and subject to certain limitations, we may be able to incur substantial additional indebtedness in the future. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing, could materially and adversely affect our ability to make payments on our indebtedness and our business, financial condition, results of operations and cash available for distribution.

Furthermore, our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including our revolving credit facility, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our debt instruments restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

We distribute all of our available cash to our unitholders after reserves established by our general partner, which may limit the cash available to service our senior notes or repay them at maturity.

Subject to the limitations on restricted payments contained in the indentures governing our senior notes and in our revolving credit facility, we will distribute all of our “available cash” each quarter to our unitholders. “Available cash” is defined in our partnership agreement.

As a result, we may not accumulate significant amounts of cash. These distributions could significantly reduce the cash available to us in subsequent periods to make payments on our senior notes.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Interest Price Risk” included under Part II of this annual report for further information regarding interest rate sensitivity.

Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our revolving credit facility and under the indentures for our senior notes. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.

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, financial condition, results of operations and cash available for distribution.

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, 2014, based on proved reserve volumes, we and Memorial Resource operated 93% and third parties operated 7% 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, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, 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, results of operations and cash available for distribution.

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, worker 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 measures 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.

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. The 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.

The BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. The 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, the 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.

Our operations on federal, state or Indian oil and natural gas leases must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Department of the Interior’s Bureau of Land Management, or the BLM, BOEM, BSEE, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

The Mineral Leasing Act of 1920, as amended, or the Mineral Act, prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. It is possible that our unitholders may be citizens of foreign countries who do not own their units in a U.S. corporation, or that even if such units are held through a U.S. corporation, their country of citizenship may be determined to be non-reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

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

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”), including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act, or CAA, that establish Prevention of Significant Deterioration, or PSD, and Title V permit reviews for GHG emissions from certain large stationary sources. On June 23, 2014, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD or Title V programs. The EPA has announced that it is currently evaluating the decision and awaiting further action by the courts, and that it will provide relevant guidance on GHG permitting requirements.

The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the Obama administration has announced in its Climate Action Plan that it intends to adopt additional regulations to reduce emissions of GHGs in the coming years, possibly including further restrictions on emissions of methane from oil and gas operations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs 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, they could have an adverse effect on our financial condition and results of 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.

The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs, new operating restrictions, or delays in our operations, which could adversely affect our results of operations and financial condition.

The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our activities in those areas or during certain seasons, such as breeding and nesting seasons. On March 27, 2014, the U.S. Fish and Wildlife Service (“FWS”) announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico and Colorado, where we conduct operations, as a threatened species under the ESA. Listing of the lesser prairie chicken as threatened imposes restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. The FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to us from species protection measures, time delays or limitations on our activities, which costs, delays or limitations may be significant and could adversely affect our results of operations and financial position.

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 some 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 Initial Position Limit Rule. The Initial 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 CFTC proposed a new version of the Initial Position Limit Rule in November 2013, referred to herein as the “Re-Proposed Position Limit Rule,” with respect to which the comment period has closed but a final rule has not been issued. The CFTC and bank regulators in September 2014 re-proposed rules which would impose margin requirements on uncleared swaps between banks, swap dealers and major swap participants, referred to herein as the “Re-Proposed SD/MSP Margin Rule.”

We qualify as a “non-financial entity” for purposes of the End-User Exception and we utilize such exception so our hedging activity is not 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 and, if the Re-Proposed SD/MSP Margin Rule is adopted, will be subject to such rule and required to post margin in accordance with such rule in connection with their swaps with other banks, swap dealers and major swap participants. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Re-Proposed Position Limit Rule and the Re-Proposed SD/MSP Margin Rule are ultimately effected, such proposed rules 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. 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.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our development and production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The Federal Water Pollution Control Act (the “CWA”) imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Also, the EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.

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 February 12, 2014, the EPA published a revised 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. 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. Further, on May 16, 2013, the BLM issued a revised proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans.

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 draft report, which is expected to be released for public comment and peer review, is still pending. A final report could be released as late as 2016. 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 16, 2013, the U.S. Department of Interior issued a revised proposed 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 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 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 final rule is described in more detail below.

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. A proposed rule is expected in early 2015.

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.

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, which ended December 31, 2014, owners and operators had to either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. Beginning January 1, 2015, all newly fractured wells are required to use green completions. Controls for certain storage vessels and pneumatic controllers were permitted to 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.

Our business could be adversely affected by security threats, including cyber-security threats, and related disruptions.

We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. As a producer of natural gas and oil, we face various security threats, including cyber-security threats, to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing and other facilities, refineries and pipelines. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, 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 MRD Holdco owns approximately 6% of our common units. 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 several of 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 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 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. Some 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, currently serves as Managing Partner and Chief

Operating Officer for NGP; and Mr. Weinzierl, the 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 an omnibus agreement with Memorial Resource and our general partner pursuant to which, among other things, Memorial Resource provides management, administrative and operating services for us and our general partner. The payments to Memorial Resource pursuant to this agreement will be substantial and will reduce the amount of cash available for distribution to unitholders.

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 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 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, 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. Since the subordination period has ended, 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. 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.

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 owns 50% of the outstanding incentive distribution rights, or IDRs, and may transfer them to a third party at any time without the consent of our unitholders. If our general partner transfers its IDRs 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.

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.

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

Sales by MRD Holdco of a substantial number of our common 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. MRD Holdco currently owns approximately 6% of our common 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 maintenance 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. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

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, Colorado, Wyoming, New Mexico 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, 2014.

Our common units are listed and traded on the NASDAQ Global Market under the symbol “MEMP.” As of February 20, 2015, there were approximately 138 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 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 the LTIP.

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. We have also issued incentive distribution rights (“IDRs”), which entitle the holder(s) thereof to additional increasing percentages, up to a maximum of 24.9% of the cash we distribute in excess of $0.54625 per common unit per quarter. Our general partner owns 50%, and the Funds indirectly own 50%, of the IDRs.

The holders of the IDRs are 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, which ended on February 13, 2015, in the following manner:

Our general partner’s 0.1% interest in us was represented by 86,797 general partner units at December 31, 2014. 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, 2014, awards of restricted common units 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 to other Memorial Resource employees who provide services to the Partnership. In conjunction with the issuance of these restricted common units and our equity offerings on July 15, 2014 and September 9, 2014, we issued 25,497 general partner units to our general partner to maintain its 0.1% interest in us, for which the capital contribution received from our general partner, was approximately $0.6 million. 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.

During the three months ended December 31, 2014, there were no repurchases of our common units except:

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, 2014, 2013, 2012, 2011 and 2010 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, the consolidated financial statements of REO from February 3, 2009 (inception) through December 11, 2012 and the Cinco Group from inception through October 1, 2013. 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:

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.

	For Year Ended December 31,
	2014			2013			2012			2011			2010
	($ in thousands, except per unit data)
Statement of Operations Data:													(Unaudited)
Revenues:
Oil & natural gas sales	$	490,249		$	341,197		$	255,608		$	231,923		$	112,793
Pipeline tariff income and other		3,856			2,419			2,815			2,689			2,894
Total revenues		494,105			343,616			258,423			234,612			115,687

Costs and expenses:
Lease operating		134,654			88,893			80,116			62,909			37,779
Pipeline operating		2,068			1,835			2,114			2,526			1,896
Exploration		790			1,130			2,463			1,126			246
Production and ad valorem taxes		31,601			17,784			16,048			11,680			4,839
Depreciation, depletion, and amortization		155,404			97,269			76,036			61,882			38,786
Impairment of proved oil and natural gas properties		407,540			54,362			10,532			18,415			11,838
General and administrative		45,619			43,495			30,342			26,695			16,262
Accretion of asset retirement obligations		5,618			4,853			4,377			4,032			3,111
(Gain) loss on commodity derivative instruments		(492,254	)		(26,281	)		(21,417	)		(58,407	)		(9,178	)
Gain on sale of properties		—			(2,848	)		(9,759	)		(63,033	)		(239	)
Other, net		(12	)		647			138			2,282			1,195
Total costs and expenses		291,028			281,139			190,990			70,107			106,535
Operating income		203,077			62,477			67,433			164,505			9,152
Other income (expense):
Interest expense, net		(83,550	)		(41,901	)		(20,436	)		(14,970	)		(4,732	)
Other income (expense)		(327	)		—			—			—			—
Amortization of investment premium		—			—			(194	)		(606	)		(907	)
Total other income (expense)		(83,877	)		(41,901	)		(20,630	)		(15,576	)		(5,639	)
Income (loss) before income taxes		119,200			20,576			46,803			148,929			3,513
Income tax benefit (expense)		(1,121	)		(308	)		(285	)		(139	)		(483	)
Net income		118,079			20,268			46,518			148,790			3,030
Net income (loss) attributable to noncontrolling interest		32			267			104			(146	)		(8	)
Net income attributable to Memorial Production Partners LP	$	118,047		$	20,001		$	46,414		$	148,936		$	3,038

Limited partners’ interest in net income:
Net income (loss) attributable to Memorial Production Partners LP	$	118,047		$	20,001		$	46,414		$	148,936		$	3,038
Net (income) loss allocated to predecessor		—			—			—			(75,740	)		11,317
Net (income) loss allocated to previous owners		—			(11,275	)		(46,293	)		(66,604	)		(14,355	)
Net (income) loss allocated to general partner		(206	)		(49	)		—			(7	)		—
Net (income) loss allocated to NGP IDRs		(88	)		—			—			—			—
Limited partners’ interest in net income	$	117,753		$	8,677		$	121		$	6,585		$	—

Earnings per unit attributable to limited partners:
Basic and diluted earnings per unit	$	1.66		$	0.19		$	0.01		$	0.30		n/a
Supplemental basic and diluted EPU (1)	$	1.66		$	0.43		$	2.03		$	6.83		n/a

Cash distributions declared per unit	$	2.20		$	2.08		$	1.55		n/a			n/a

Cash Flow Data:													(Unaudited)
Net cash flow provided by operating activities	$	224,898		$	193,697		$	156,844		$	122,140		$	56,065
Net cash used in investing activities		1,352,071			201,413			357,209			500,899			326,248
Net cash (used in) provided by financing activities		1,115,004			(3,585	)		208,821			374,982			281,018

Balance Sheet Data:										(Unaudited)			(Unaudited)
Working capital (deficit)	$	154,344		$	(3,050	)	$	60,629		$	48,620		$	23,484
Total assets		2,930,559			1,552,307			1,489,404			1,255,660			689,759
Total debt		1,595,413			792,067			630,182			361,001			193,014
Total equity		1,075,657			579,616			711,765			742,901			380,932

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “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.

We are a Delaware limited partnership focused on the ownership, acquisition and development of 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.

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, realized 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 can 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. Natural gas with a high Btu content (“wet” natural gas) sells at a premium to natural gas with low Btu content (“dry” natural gas) 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 produced 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 also affects the differential. Historically, these index prices have generally 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 can 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 typically 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 refiners’ 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 more closely tracked the ICE Brent price, and we have been able to successfully hedge this production through an ICE Brent priced hedge with a corresponding Midway-Sunset basis hedge through 2016.

Price Volatility. In the past, and particularly in the second half of 2014 and the beginning of 2015, 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.

Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, compression, water injection and disposal, the cost of CO₂ injection 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 are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties or, in the case of Wyoming, the gross products for production. Valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

We and our general partner are parties to an omnibus agreement with a wholly-owned subsidiary of 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. During 2014, Memorial Resource began to allocate its direct general and administrative costs based on estimated time spent on each entity, 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.

	For the Twelve Months Ended
	December 31,
	2014			2013			2012

Net income (loss)	$	118,079		$	20,268		$	46,518
Interest expense, net		83,550			41,901			20,436
Income tax expense (benefit)		1,121			308			285
DD&A		155,404			97,269			76,036
Impairment of proved oil and gas properties		407,540			54,362			10,532
Accretion of AROs		5,618			4,853			4,377
(Gains) losses on commodity derivative instruments		(492,254	)		(26,281	)		(21,417	)
Cash settlements received (paid) on commodity derivative instruments		13,522			19,879			44,111
(Gain) loss on sale of properties		—			(2,848	)		(9,759	)
Acquisition related costs		4,363			6,729			4,135
Unit-based compensation expense		7,874			3,558			1,423
Non-cash compensation expense		—			1,057			—
Exploration costs		790			1,130			2,463
Non-cash loss on office lease		1,442			—			—
Amortization of investment premium		—			—			194
Provision for environmental remediation		2,852			—			—
Adjusted EBITDA	$	309,901		$	222,185		$	179,334

In 2015, 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 acquisition opportunities may come from Memorial Resource, the Funds, and their respective affiliates, as well as from unrelated third parties. Our ability to add 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 2015, excluding potential acquisitions, we anticipate spending approximately 74% of our capital budget in East Texas, 11% in the Rockies, 7% in California and the balance in South Texas and the Permian Basin focused primarily on drilling, on-site maintenance, recompletions and capital workovers.

Oil prices declined significantly in the second half of 2014 and have continued to drop in early 2015. This decline in oil prices stems in large part from decreased demand due to weak economic activity and increased efficiency, an excess of supply due to sustained high output from North America, and the Organization of Petroleum Exporting Countries’ failure to reach agreement on production curbs in November 2014. The continuation 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. Although we cannot predict the occurrence of events or factors that will affect future commodity prices, such as the supply of, and demand for, oil, natural gas, and NGLs, and general domestic or foreign economic conditions and political developments, 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, forecasts that Brent crude oil prices will average $58 per Bbl in 2015 and $75 per Bbl in 2016. North Sea Brent crude oil spot prices averaged $62 per Bbl in December 2014, the lowest monthly average Brent price since May 2009, down $17 per Bbl from the November average. The combination of robust world crude oil supply growth and weak global demand has contributed to rising global inventories and falling crude oil prices. EIA expects global oil inventories to continue to build in 2015, keeping downward pressure on oil prices. Like Brent crude oil prices, WTI prices have decreased considerably, with monthly average prices falling by more than 44% as of December 2014 after reaching their 2014 peak of $106 per Bbl in June. EIA expects WTI crude oil prices to average $55 per Bbl in 2015 and $71 per Bbl in 2016.

EIA expects the Henry Hub natural gas spot price to average $3.52 per MMBtu this winter compared with $4.51 per MMBtu last winter, reflecting both lower-than-expected space heating demand and higher natural gas production this winter. EIA expects the Henry Hub natural gas spot price to average $3.44 per MMBtu in 2015 and $3.86 per MMBtu in 2016, compared with $4.39 per MMBtu in 2014. EIA expects monthly average spot prices to remain less than $4.00 per MMBtu until the fourth quarter of 2016.

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. 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.

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 have our internally prepared reserve report as of December 31 of each year audited by independent reserve engineers 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. 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.

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.

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, 2014 or 2013.

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, 2014, 2013, and 2012 have been derived from both our consolidated financial statements and our previous owners’ combined financial statements. The previous owners combined financial statements reflect: (i) the Tanos/Classic Properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective date of acquisition on a combined basis, (ii) the consolidated financial statements of REO for periods after common control commenced through the date of acquisition, (iii) the WHT Properties from February 2, 2011 (inception) through the date of acquisition, and (iv) the financial statements of the Cinco Group on a combined basis for periods after common control commenced through the date of acquisition. The results of operations attributable to the 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 transactions:

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

	For the Twelve Months Ended
	December 31,
	2014			2013			2012
Revenues:
Oil & natural gas sales	$	490,249		$	341,197		$	255,608
Pipeline tariff income and other		3,856			2,419			2,815
Total revenues		494,105			343,616			258,423

Costs and expenses:
Lease operating		134,654			88,893			80,116
Pipeline operating		2,068			1,835			2,114
Exploration		790			1,130			2,463
Production and ad valorem taxes		31,601			17,784			16,048
Depreciation, depletion, and amortization		155,404			97,269			76,036
Impairment of proved oil and natural gas properties		407,540			54,362			10,532
General and administrative		45,619			43,495			30,342
Accretion of asset retirement obligations		5,618			4,853			4,377
(Gain) loss on commodity derivative instruments		(492,254	)		(26,281	)		(21,417	)
(Gain) loss on sale of properties		—			(2,848	)		(9,759	)
Other, net		(12	)		647			138
Total costs and expenses		291,028			281,139			190,990
Operating income (loss)		203,077			62,477			67,433
Other income (expense):
Interest expense, net		(83,550	)		(41,901	)		(20,436	)
Other income (expense)		(327	)		—			—
Amortization of investment premium		—			—			(194	)
Total other income (expense)		(83,877	)		(41,901	)		(20,630	)
Income before income taxes		119,200			20,576			46,803
Income tax benefit (expense)		(1,121	)		(308	)		(285	)
Net income (loss)		118,079			20,268			46,518
Net income (loss) attributable to noncontrolling interest		32			267			104
Net income (loss) attributable to Memorial Production Partners LP	$	118,047		$	20,001		$	46,414

Oil and natural gas revenue:
Oil sales	$	262,407		$	171,095		$	145,103
NGL sales		64,718			51,215			26,647
Natural gas sales		163,124			118,887			83,858
Total oil and natural gas revenue	$	490,249		$	341,197		$	255,608

Production volumes:
Oil (MBbls)		3,092			1,764			1,519
NGLs (MBbls)		2,143			1,632			745
Natural gas (MMcf)		41,494			35,924			29,744
Total (MMcfe)		72,902			56,303			43,329
Average net production (MMcfe/d)		199.7			154.3			118.4

Average sales price:
Oil (per Bbl)	$	84.88		$	96.98		$	95.54
NGL (per Bbl)		30.20			31.38			35.75
Natural gas (per Mcf)		3.93			3.31			2.82
Total (Mcfe)	$	6.72		$	6.06		$	5.90

Average unit costs per Mcfe:
Lease operating expense	$	1.85		$	1.58		$	1.85
Production and ad valorem taxes	$	0.43		$	0.32		$	0.37
General and administrative expenses	$	0.63		$	0.77		$	0.70
Depletion, depreciation, and amortization	$	2.13		$	1.73		$	1.75

Net income of $118.1 million was generated for the year ended December 31, 2014, primarily due to significant gains on commodity derivatives which were mostly offset by impairment charges. Net income was $20.3 million for the year ended December 31, 2013, of which $11.3 million was attributable to the previous owners.

Revenues. Oil, natural gas and NGL revenues for the year ended December 31, 2014 totaled $490.2 million, an increase of $149.1 million compared with the year ended December 31, 2013. Production increased 16.6 Bcfe (approximately 29%), primarily from volumes associated with third party acquisitions. The average realized sales price increased $0.66 per Mcfe primarily due to an increase in oil volumes relative to other commodities related to our acquisitions in 2014. The favorable volume and pricing variance contributed to an approximate $100.5 million and $48.6 million increase in revenues, respectively.

Lease Operating. Lease operating expenses were $134.7 million and $88.9 million for the year ended December 31, 2014 and 2013, respectively. In our Wyoming Acquisition, we acquired more oil weighted properties which are generally more expensive to operate compared to natural gas properties (on a per Mcfe basis). On a per Mcfe basis, lease operating expenses increased to $1.85 for 2014 from $1.58 for 2013 due to 2014 oil acquisitions.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the year ended December 31, 2014 totaled $31.6 million, an increase of $13.8 million compared with the year ended December 31, 2013 primarily due to an increase in production volumes and ad valorem tax rates. On a per Mcfe basis, production and ad valorem taxes increased to $0.43 per Mcfe for the year ended December 31, 2014 from $0.32 per Mcfe for the year ended December 31, 2013 due to higher production tax rates on a per Mcfe basis for production from our new Wyoming properties.

Depreciation, Depletion and Amortization. DD&A expense for the year ended December 31, 2014 was $155.4 million compared to $97.3 million for the year ended December 31, 2013, a $58.1 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and the Partnership’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $28.7 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $29.4 million.

Impairment of proved oil and natural gas properties. For the year ended December 31, 2014, we recognized $407.5 million of impairments primarily related to certain properties in the Permian Basin, East Texas and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable due to a downward revision of estimated proved reserves as a result of declining commodity prices and updated well performance data. During 2013, we recorded $54.4 million of impairments consisting of $50.3 million related to certain properties in East Texas and $4.1 million related to certain properties in South Texas. For the East Texas properties, the estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on updated well performance data. In South Texas, the estimated future cash flows expected these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. For additional information, see Note 4 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

General and Administrative. General and administrative expenses for the year ended December 31, 2014 were $45.6 million. General and administrative expenses for the year ended December 31, 2014 included $7.9 million of non-cash unit-based compensation expense, $4.4 million of acquisition-related costs and a $1.8 million allocated loss on a previous corporate office lease. General and administrative expenses for the year ended December 31, 2013 totaled $43.5 million, of which $14.7 million was attributable to the previous owners. General and administrative expenses for 2013 included $3.6 million of non-cash unit-based compensation expense and $6.7 million of acquisition-related costs. The $2.1 million increase in general and administrative expenses consisted of increased salaries and employee count between periods offset by $5.8 million of one-time compensation expense related to the Tanos management buyout during the year ended December 31, 2013.

Gain/Loss on Commodity Derivative Instruments. Net gains on commodity derivative instruments of $492.3 million were recognized during the year ended December 31, 2014, consisting of $13.6 million of cash settlements received in addition to a $478.7 million increase in the fair value of open positions. Net gains on commodity derivative instruments of $26.3 million were recognized during 2013, of which $19.9 million consisted of cash settlements.

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.

Interest Expense, Net. Interest expense, net totaled $83.6 million during the year ended December 31, 2014, including amortization of deferred financing fees of approximately $4.2 million and accretion of net discount associated with our senior notes of $1.9 million. Interest expense, net totaled $41.9 million during the year ended December 31, 2013, including gains on interest rate

swaps of approximately $1.5 million, amortization of deferred financing fees of approximately $5.8 million (including write-offs associated with the previous owner’s revolving credit facility at the time their debt was repaid and terminated in March 2013) and accretion of net discount associated with our senior notes of $0.5 million. The $41.6 million increase in interest expense is primarily due to a higher aggregate principal amount of our senior notes issued and outstanding for the year ended December 31, 2014 compared to the year ended December 31, 2013. During the year ended December 31, 2014, interest of $2.8 million was capitalized and included in our capital expenditures.

Average outstanding borrowings under the Partnership’s revolving credit facility were $413.6 million during the year ended December 31, 2014 compared to $184.7 million during the year ended December 31, 2013. Average outstanding borrowings under the previous owners’ revolving credit facilities were $21.3 million during the year ended December 31, 2013. For the year ended December 31, 2014, the Partnership had an average of $950.7 million aggregate principal amount of our senior notes issued and outstanding. For the year ended December 31, 2013, the Partnership had an average of $342.2 million aggregate principal amount of our senior notes issued and outstanding.

Net income was $20.3 million for the year ended December 31, 2013, of which $11.3 million was attributable to the previous owners. Net income was $46.5 million for the year ended December 31, 2012, of which $46.3 million was attributable to the previous owners

Revenues. Oil, natural gas and NGL revenues for 2013 totaled $341.2 million, an increase of $85.6 million compared with 2012. Production increased 13.0 Bcfe (approximately 30%) and the average realized sales price increased $0.16 per Mcfe. The favorable volume variance contributed to an approximately $76.6 million increase in revenues, whereas the favorable pricing variance contributed to a $9.0 million increase in revenues.

Lease Operating. Lease operating expenses for 2013 were $88.9 million compared to $80.1 million for 2012, an $8.8 million year-to-year increase. Lease operating expenses increased primarily due to costs associated with properties acquired during 2012 and increased drilling activities. On a per Mcfe basis, lease operating expenses decreased to $1.58 for 2013 from $1.85 for 2012.

Production and Ad Valorem Taxes. Production and ad valorem taxes for 2013 totaled $17.8 million, an increase of $1.8 million compared with 2012. The increase was largely due to an $8.4 million increase in production taxes primarily due to increased production levels. Ad valorem taxes are property taxes generally assessed and levied at the local level. Production taxes imposed at the state level are usually based on either volume or revenue. There is no production and ad valorem tax assessed for our Beta properties. Production taxes were 3.92% and 2.23% as a percentage of oil and natural gas revenue in 2013 and 2012, respectively.

Depreciation, Depletion and Amortization. DD&A expense for 2013 was $97.3 million compared to $76.0 million for 2012, a $21.3 million year-to-year increase primarily due to increased production volumes related to acquisitions in 2012 and 2013 as well as results from drilling. DD&A expense per Mcfe was $1.73 for 2013 compared to $1.75 for 2012. Increased production volumes caused DD&A expense to increase by $22.8 million, while the 1% change in the DD&A rate between periods caused DD&A expense to decrease by $1.5 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. During 2013, we recorded $54.4 million of impairments consisting of $50.3 million related to certain properties in East Texas and $4.1 million related to certain properties in South Texas. For the East Texas properties, a downward revision of estimated proved reserves based on updated well performance data triggered the impairment. For the South Texas properties, a downward revision of estimated proved reserves based on pricing terms specific to these properties triggered the impairment. During 2012, we recorded impairments of $10.5 million in impairments related to proved oil and natural gas properties which were a part of the Cinco Group of assets. These impairments were a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area.

General and Administrative. General and administrative expenses for 2013 were $43.5 million, of which $14.7 million was attributable to the previous owners. Tanos also recorded $5.8 million of general and administrative expenses related to the management buyout. General and administrative expenses for 2013 included $3.6 million of non-cash unit-based compensation expense and $6.7 million of acquisition-related costs. General and administrative expenses for 2012 were $30.3 million, of which

$19.0 million was attributable to the previous owners. General and administrative expenses for 2012 included $1.4 million of non-cash unit-based compensation expense and $4.1 million of acquisition-related costs.

Gain on Derivative Instruments. Net gains on commodity derivative instruments of $26.3 million were recognized during 2012, of which $19.9 million consisted of cash settlements. Net gains on commodity derivative instruments of $21.4 million were recognized during 2012, of which $44.1 million consisted of cash settlements.

Gain on Sale of Properties. Our previous owners recognized a net gain on the sale of properties of $2.8 million during 2013. This gain was primarily related to the sale of a natural gas gathering pipeline and certain non-operated oil and gas properties in East Texas. For more information, see Note 3 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data,” contained herein. The Cinco Group recognized a net gain on sale of properties of $9.8 million during 2012. In July 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. In September 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Ector County, Texas to third party for $4.7 million and recognized a gain of approximately $2.2 million.

Net Interest Expense. Net interest expense totaled $41.9 million during 2013, including gains on interest rate swaps of approximately $1.5 million and amortization of deferred financing fees of approximately $5.8 million. Net interest expense totaled $20.4 million during 2012, of which $10.4 million was attributable to the Partnership’s revolving credit facility, including losses on interest rate swaps of approximately $4.0 million and amortization of deferred financing fees of approximately $0.6 million.

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. Any volatility in the debt markets would likely 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 volatile. In an effort to reduce the variability of our cash flows, we have hedged the commodity prices associated with a portion of our expected crude oil, NGL and natural gas volumes through 2019 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, general partner and (if applicable) holders of our IDRs. 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 30 to 45 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 evaluate counterparty risks related to our commodity derivative contracts and trade credit. Some of the lenders, or certain of their affiliates, under our revolving credit facility are counterparties to our derivative contracts. 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 or our indentures. 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 February 23, 2015, our liquidity of $843.0 million consisted of $1.0 million of cash and cash equivalents and $842.0 million of available borrowings under our revolving credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we monitor events and circumstances surrounding each of the lenders in our revolving credit facility. As of December 31, 2014, the borrowing base under our revolving credit facility was $1.44 billion and we had $412.0 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 2015. A continuing decline in oil and natural gas prices or a prolonged period of lower oil and natural gas prices could result in a reduction of our borrowing base under our revolving credit facility and could trigger mandatory principal repayments.

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, 2014, we had letters of credit with an outstanding aggregate amount of approximately $6.7 million.

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 9 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, 2014, we had a working capital balance of $154.3 million, which includes a $205.3 million net asset derivative position.

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 2015. 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 is party to a $2.0 billion revolving credit facility, with a current borrowing base of $1.44 billion, that matures in March 2018 and is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). As of December 31, 2014, we had $412.0 million of outstanding borrowings and $6.7 million of outstanding letters of credit under our revolving credit facility. 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 2015; 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 an unfavorable borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

A 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.

Borrowings under our revolving credit facility bear interest, at our option, at either: (i) the Alternate 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 1/100^th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% 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), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index Rate plus a margin that varies from 1.50%

to 2.50% 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 (i) a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is defined under our revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and (ii) 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 or permit 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, 2014, we believe we were in compliance with all of the financial and other covenants under our revolving credit facility.

In January 2015, we repurchased a principal amount of approximately $3.0 million at an average price of 83.000% of the face value of the 2022 Senior Notes. We used available cash and funds under our revolving credit facility to pay for these repurchases. See “—2014 Developments” under “Item 1. Business” for additional information regarding the issuance of the 2022 Senior Notes.

In April 2013, May 2013 and October 2013, the Issuers issued $300.0 million, $100.0 million and $300.0 million, respectively, of their 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of the our subsidiaries (other than Finance Corp. and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes were issued under and are governed by an indenture dated as of April 17, 2013.

For information regarding the 2021 Senior Notes and 2022 Senior Notes, see Note 8 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

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, 2014, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.” As of December 31, 2014, the fair value of our open derivative contracts was a net asset of $517.1 million. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. 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, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Interest Rate 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 the year ended December 31, 2014 is presented on a consolidated basis. The cash flows for the years ended December 31, 2013 and 2012 is presented on a combined basis, consisting of the consolidated financial information of the Partnership and the combined financial information of 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 income increased by $97.8 million and net cash provided by operating activities increased by $31.2 million. Production increased 16.6 Bcfe (approximately 29%) and the average realized sales price increased to $6.72 per Mcfe as previously discussed under “—Results of Operations.” Cash paid for interest during the year ended December 31, 2014 was $63.7 million compared to $40.4 million during the year ended December 31, 2013. Net cash provided by operating activities included $11.7 million of cash receipts on derivative instruments and we had a $12.8 million decrease in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during the year ended December 31, 2014 compared to the year ended December 31, 2013.

Investing Activities. Net cash used in investing activities during the year ended December 31, 2014 was $1.36 billion, of which $1.08 billion was used to acquire oil and natural gas properties from third parties and $264.2 million was used for additions to oil and gas properties. Cash used in investing activities during the year ended December 31, 2013 was $201.4 million, of which $38.7 million was used to acquire oil and natural gas properties from third parties and $161.7 million was used for additions to oil and gas properties. See Note 3 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding acquisitions and divestitures.

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and gas properties. For the years ended December 31, 2014 and 2013, additions to restricted investments were $4.0 million and $5.4 million, respectively. 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.

Financing Activities. For the year ended December 31, 2014, we issued a total of 24,840,000 common units generating gross proceeds of approximately $553.3 million, offset by approximately $12.5 million of costs incurred in conjunction with the issuance of common units. The net proceeds from these issuances, including our general partner’s proportional capital contributions, were primarily used to repay borrowings on our revolving credit facility.

In March 2013, we issued 9,775,000 common units in a public offering generating gross proceeds of approximately $179.4 million, offset by approximately $7.6 million of costs incurred in conjunction with the issuance of common units. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT. In October 2013, we issued 16,675,000 common units in a public offering. This issuance generated total net proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportional capital contribution, were used to repay a portion of outstanding borrowings under our revolving credit facility.

After deducting underwriting discounts and offering expenses, net proceeds of $484.0 million from the issuances of the 2022 Senior Notes and $672.5 million from the issuances of the 2021 Senior Notes during the years ended December 31, 2014 and 2013, respectively, were used to repay portions of borrowings outstanding under the Partnership’s revolving credit facility and other general partnership purposes. See Note 8 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our Senior Notes.

We paid $55.4 million to MRD LLC in connection with our March 2013 acquisition of all of the outstanding equity interests in WHT and repaid $89.3 million of indebtedness under WHT’s credit facility. An additional $96.4 million was paid to MRD LLC related to the October 2013 Cinco Group acquisition. Distributions to NGP affiliates were $355.5 million related to the Cinco Group acquisition. We paid $33.9 million to an operating subsidiary of MRD LLC in April 2014 to acquire certain oil and natural properties in East Texas. In October 2014, we paid $15.0 million to acquire oil and gas properties in the Rockies from Memorial Resource.

Distributions to partners during the year ended December 31, 2014 were $154.9 million compared to $96.6 million during 2013. The increase is primarily due to an increase in the outstanding units between periods and an increase in the distribution rate. Distributions made by the previous owners during the year ended December 31, 2013 were $31.1 million. See Note 1 and Note 12.

The Partnership had borrowings of $1.45 billion under its revolving credit facility during 2014 that were used primarily to fund the Eagle Ford and Wyoming Acquisitions and to fund its drilling program. The Partnership had net payments of $268.0 million under its revolving credit facility during the year ended December 31, 2013. The Cinco Group had advances of $17.4 million under their credit facilities and repaid $187.2 million of outstanding borrowings during the year ended December 31, 2013. Deferred financing costs of approximately $11.5 million were incurred during the year ended December 31, 2014 compared to approximately $20.9 million during the year ended December 31, 2013.

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 2013 primarily due to an increase in production volumes. Production increased 13.0 Bcfe (approximately 30%) and the average realized sales price increased to $6.06 per Mcfe as previously discussed under “—Results of Operations.” Cash paid for interest during the year ended December 31, 2013 was $40.4 million compared to $13.9 million during the year ended December 31, 2012. Net cash provided by operating activities included $18.9 million of cash receipts on derivative instruments for the year ended December 31, 2013 compared to $42.3 million of cash receipts on derivatives instruments for the year ended December 31, 2012. The period-to-period gain was offset by a $43.8 million period-to-period increase in impairments. In addition, we had a $16.5 million increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during the year ended December 31, 2013 compared to the year ended December 31, 2012. We used cash flows provided by operating activities primarily to fund distributions to our partners and additions to oil and gas properties. 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 2013 was $201.4 million, of which $38.7 million was used to acquire oil and natural gas properties and $161.7 million was used for additions to oil and gas properties. Cash used in investing activities during 2012 was $357.2 million, of which $277.6 million was used to acquire oil and natural gas properties and $107.8 million was used for additions to oil and gas properties.

Financing Activities. As discussed above, we sold common units in two separate public equity offerings during 2013. The net proceeds from the March 2013 equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT. The net proceeds from the October 2013 equity offering, including our general partner’s proportional capital contribution, were used to repay a portion of outstanding borrowings under our revolving credit facility. In December 2012, we sold 11,975,000 common units in a public offering generating total net proceeds of

approximately $194.1 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 and to repay indebtedness under our revolving credit facility. 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 Issuers completed three private placements of the 2021 Senior Notes during 2013. The issuers issued a $300.0 million aggregate principal amount at 98.521% of par in April 2013, an additional $100.0 million aggregate principal amount at 102.0% of par in May 2013 and an additional $300.0 million aggregate principal amount at 97.0% of par in October 2013. Proceeds from these issuances were used to repay borrowings outstanding under our revolving credit facility.

Distributions to partners were $96.6 million for the year ended December 31, 2013 compared to $34.4 million for the year ended December 31, 2012 due to increases in both declared distribution rates per unit and increases in the number of outstanding units. Distributions to Memorial Resource increased to $151.7 million for 2013 compared to $45.5 million for 2012 as a result of additional acquisitions from Memorial Resource in 2013. Distributions to NGP affiliates were $355.5 million related to the Cinco Group acquisition for 2013 compared to $242.2 million for 2012 related to the Beta acquisition.

The net proceeds from the 2021 Senior Notes, as noted above, were used to repay borrowings outstanding under our revolving credit facility. There were no senior notes issued during 2012. The Partnership had net payments of $268.0 million under its revolving credit facility during 2013. The previous owners had net repayments of $259.2 million under their revolving credit facilities during 2013. The Partnership incurred loan origination fees of approximately $20.9 million during 2013 primarily related to the 2021 Senior Notes. The Partnership had net borrowings of $251.0 million under its revolving credit facility during 2012 that were used primarily to fund the acquisitions of oil and gas properties. The previous owners had net borrowings of $18.2 million under their revolving credit facilities during 2012. The Partnership and the previous owners incurred loan origination fees of approximately $1.4 million and $0.8 million, respectively, during 2012.

The previous owners received contributions of $7.2 million and $64.6 million during 2013 and 2012, respectively, to partially fund their development and property acquisition program. The previous owners made distributions of $31.1 million during 2013, all of which was attributable to the Cinco Group. The previous owners made distributions of $29.5 million during 2012, of which $20.6 million was attributable to the Cinco Group and $7.8 million was attributable to REO.

The Cinco Group sold certain interests in oil and gas properties offshore Louisiana during 2012 for an aggregate $40.1 million to an NGP controlled entity, of which $38.1 million was received in 2012. The remaining proceeds were released from escrow in April 2013. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $6.3 million and was recognized in the equity statement as a net contribution.

See “— Outlook” for additional information regarding our capital spending program for 2015.

In 2015, 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 and general partner units ($1.90 per unit on an annualized basis). On February 12, 2015, we paid a $46.3 million cash distribution for the fourth quarter 2014 to our unitholders, our general partner and the holders of our IDRs. This distribution represented an annualized amount of $2.20 per common unit. Assuming no further changes in the distribution rate and the number of common units and general partner units currently outstanding, the aggregate distribution paid to all of our unitholders in 2015 would total approximately $185.2 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 2015 through a combination of cash from operations, borrowings under our revolving credit facility and the issuance of equity or debt securities.

In the table below, we set forth our contractual obligations as of December 31, 2014. 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.

			Payment or Settlement due by Period
Contractual Obligation	Total		2015		2016 - 2017		2018-2019		Thereafter
			(in thousands)
Revolving credit facility (1)	$	412,000	$	—	$	—	$	412,000	$	—
Senior Notes (2)
2021 Senior Notes		1,046,938		53,375		106,750		106,750		780,063
2022 Senior Notes		776,719		36,094		68,750		68,750		603,125
Estimated interest payments (3)		47,512		11,179		22,359		13,974		—
Asset retirement obligations (4)		110,372		—		5,189		3,706		101,477
Decommissioning Trust Agreement (5)		10,350		4,140		6,210		—		—
CO₂ minimum purchase commitment (6)		50,495		9,608		20,330		14,055		6,502
Operating leases (7)		3,665		788		621		410		1,846
Compression services		6,526		6,526		—		—		—
Total	$	2,464,577	$	121,710	$	230,209	$	619,645	$	1,493,013

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, 2014 and the average prices at which the production will be hedged:

	2015			2016			2017		2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,605,278			2,692,442			2,450,067		2,160,000		1,914,583
Weighted-average fixed price	$	4.28		$	4.40		$	4.31	$	4.51	$	4.75

Collar contracts:
Average Monthly Volume (MMBtu)		350,000			—			—		—		—
Weighted-average floor price	$	4.62		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	5.80		$	—		$	—	$	—	$	—

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

Basis swaps:
Average Monthly Volume (MMBtu)		2,940,000			2,508,333			415,000		115,000		—
Spread	$	(0.12	)	$	(0.04	)	$	—	$	0.15	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		314,281			332,813			326,600		312,000		160,000
Weighted-average fixed price	$	90.96		$	85.83		$	84.38	$	83.74	$	85.52

Collar contracts:
Average Monthly Volume (Bbls)		5,000			—			—		—		—
Weighted-average floor price	$	80.00		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	94.00		$	—		$	—	$	—	$	—

Basis swaps:
Average Monthly Volume (Bbls)		97,500			95,000			—		—		—
Spread	$	(7.07	)	$	(9.56	)	$	—	$	—	$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		149,200			84,600			—		—		—
Weighted-average fixed price	$	43.02		$	41.49		$	—	$	—	$	—

Our basis swaps as of December 31, 2014 included in the table above are presented on a disaggregated basis below:

	2015			2016			2017			2018
Natural Gas Derivative Contracts:

NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,280,000			2,103,333			300,000			—
Spread	$	(0.11	)	$	(0.06	)	$	(0.05	)	$	—

HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000			135,000			115,000			115,000
Spread	$	(0.08	)	$	0.07		$	0.14		$	0.15

CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000			—			—			—
Spread	$	(0.25	)	$	—		$	—		$	—

TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000			270,000			—			—
Spread	$	(0.09	)	$	0.06		$	—		$	—

Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,500			55,000			—			—
Spread - Brent	$	(9.73	)	$	(13.35	)	$	—		$	—

Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			—			—
Spread - WTI	$	(3.25	)	$	(4.34	)	$	—		$	—

The following table summarizes our derivative contracts as of December 31, 2013 and the average prices at which the production was hedged:

	2014			2015			2016		2017		2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,575,458			2,145,278			2,342,442		2,230,067		2,060,000		1,814,583
Weighted-average fixed price	$	4.34		$	4.30		$	4.42	$	4.31	$	4.52	$	4.77

Collar contracts:
Average Monthly Volume (MMBtu)		340,000			350,000			—		—		—		—
Weighted-average floor price	$	4.93		$	4.62		$	—	$	—	$	—	$	—
Weighted-average ceiling price	$	6.12		$	5.80		$	—	$	—	$	—	$	—

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

Basis swaps:
Average Monthly Volume (MMBtu)		2,822,083			—			—		—		—		—
Spread	$	(0.09	)	$	—		$	—	$	—	$	—	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		136,444			148,281			142,313		130,600		122,000		40,000
Weighted-average fixed price	$	95.82		$	93.07		$	86.85	$	85.96	$	85.62	$	85.00

Collar contracts:
Average Monthly Volume (Bbls)		23,000			5,000			—		—		—		—
Weighted-average floor price	$	82.83		$	80.00		$	—	$	—	$	—	$	—
Weighted-average ceiling price	$	105.31		$	94.00		$	—	$	—	$	—	$	—

Basis swaps:
Average Monthly Volume (Bbls)		57,292			57,500			—		—		—		—
Spread	$	(9.21	)	$	(9.73	)	$	—	$	—	$	—	$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		118,500			112,800			—		—		—		—
Weighted-average fixed price	$	36.23		$	35.04		$	—	$	—	$	—	$	—

Our basis swaps as of December 31, 2013 included in the table above are presented on a disaggregated basis below:

The change in hedged volumes between the current and preceding fiscal year is primarily due third party acquisitions consummated during 2014.

At December 31, 2014, we had $412.0 million of debt outstanding under our revolving credit facility, with a LIBOR Market Index Rate plus 1.75%, or 1.92%. 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.

Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2014, we had the following interest rate swap open positions:

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

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. As of December 31, 2014, some of the lenders, or certain of their affiliates, under our revolving credit facility are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. 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. At December 31, 2014, after taking into effect netting arrangements, we had counterparty exposure of $309.8 million related to our derivative instruments. 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 $207.3 million against amounts outstanding under our revolving credit facility at December 31, 2014.

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. Some of the counterparties on our derivative contracts in place as of December 31, 2014 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, 2014.

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 (2013) 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, 2014 based on the criteria set forth under the COSO Framework.

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, 2014. The report, which expresses an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2014, 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, 2014 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 and subsidiaries’ (the Partnership) internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) 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 Form10-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 LP and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Memorial Production Partners LP and subsidiaries as of December 31, 2014 and 2013, 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, 2014, and our report dated February 26, 2015 expressed an unqualified opinion on those consolidated and combined financial statements.

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 Brunson 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 duty under our partnership agreement 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 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 26, 2015.

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 Chief Executive Officer and Chairman of the board of directors since January 2014. Previously, Mr. Weinzierl served as our general partner’s President, Chief Executive Officer and Chairman of the board from April 2011 to January 2014. Mr. Weinzierl has also served as Chief Executive Officer and a director of Memorial Resource since its formation in January 2014. Previously, Mr. Weinzierl served as President and Chief Executive Officer of MRD LLC from April 2011 to January 2014 and then as Chief Executive Officer until June 2014. 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 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.

William J. Scarff has served as our general partner’s President since January 2014. Mr. Scarff has also served as President of Memorial Resource since its formation in January 2014. Previously, Mr. Scarff served as President of MRD LLC from January 2014 to June 2014. From 2000 through January 2014, Mr. Scarff has served as President and Chief Executive Officer of several private exploration and production companies sponsored by NGP. From October 2010 until January 2014, Mr. Scarff was President and Chief Executive Officer of Propel Energy, LLC. Prior to that, he was President and Chief Executive Officer of Seismic Ventures, Inc. from 2006 to 2009. From 2005 to 2014, Mr. Scarff was President and Chief Executive Officer of Proton Operating Company, LLC and from 1999 to 2005, he was President and Chief Executive Officer of Proton Energy, LLC and its affiliates. From 1978 to 1999, Mr. Scarff held a variety of positions of increasing responsibility in Marathon Oil Company, Anadarko Production Company, Burlington Resources, Texas Meridian Resource Corporation and Hilcorp Energy Company.

Robert L. Stillwell, Jr. has served as our general partner’s Vice President and Chief Financial Officer since January 2015 and was Vice President, Finance from July 2014 through December 2014. Previously, he served as Treasurer of MRD LLC from June 2012 to June 2014. From January 2011 to June 2012, Mr. Stillwell served as an investment banker at Citigroup in the Global Energy Group. From June 2010 to December 2010 and from July 2007 to June 2010, he worked in investment banking with UBS and Scotia Waterous, respectively. Mr. Stillwell began his career in the corporate finance group of EXCO Resources, Inc.

Christopher S. Cooper has served as our general partner’s Senior Vice President and Chief Operating Officer since November 2014. Previously, he served in a variety of operational, technical and strategic planning positions with Marathon Oil Company since 1990. From August 2013 until November 2014, Mr. Cooper served as Director, Global Projects. From November 2011 until August 2013, he served as Director, Financial Planning/Operations. From July 2009 until November 2011, Mr. Cooper served as Asset Manager/Regional Vice President, Mid-Continent, and from May 2007 until July 2009, he served as Asset Manager, Powder River Basin.

Patrick T. Nguyen has served as our general partner’s Vice President and Chief Accounting Officer since January 2015 and was Chief Accounting Officer from June 2011 through December 2014. 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 CPA license in the state of Texas.

Kyle N. Roane has served as our general partner’s Senior Vice President, General Counsel and Corporate Secretary since November 2014 and our Vice President, General Counsel and Corporate Secretary from January 2014 to November 2014. Previously, he served as our general partner’s General Counsel and Corporate Secretary from February 2012 through December 2013. Mr. Roane has also served as Senior Vice President, General Counsel and Corporate Secretary of Memorial Resource since November 2014 and was Vice President, General Counsel and Corporate Secretary from January 2014 to November 2014. Previously, Mr. Roane served as Vice President, General Counsel and Corporate Secretary of MRD LLC from January 2014 to June 2014 and was General Counsel and Corporate Secretary of MRD LLC from February 2012 through December 2013. From 2005 to February 2012, Mr. Roane practiced corporate and securities law at Akin, Gump, Strauss, Hauer & Feld L.L.P.

Gregory M. Robbins has served as our general partner’s Senior Vice President, Corporate Development since November 2014 and Vice President, Corporate Development from January 2013 to November 2014. 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. Mr. Robbins has also served as Senior Vice President, Corporate Development of Memorial Resource since November 2014 and was Vice President, Corporate Development from April 2014 to November 2014. Previously, Mr. Robbins served as the Vice President of Corporate Development of MRD LLC from January 2013 to June 2014, Director of Corporate Development from April 2012 to January 2013, and Treasurer from June 2011 to April 2012. 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.

W. Donald Brunson has served as a member of the board of directors of our general partner since December 2014. Subsequent to his retirement in 2012, Mr. Brunson has served as Chairman and Co-Founder of Bank of Houston from 2004 to 2012. From 2012 to 2014, he served as Chairman Emeritus of Bank of Houston. From 1996 to 2004, he held positions with American Prudential Capital, Inc. In 1994 and 1995, he served as President and was a board member and member of the executive management committee with Sunbelt National Bank. Prior to 1994, Mr. Brunson also held positions with Southwest Bank of Texas, Heights State Bank, Houston National Bank, Allied Bank of Texas, and Price Waterhouse & Co.

The board believes that Mr. Brunson’s extensive banking experience brings substantial and valuable skills and experiences to the board of directors.

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, corporate governance committee, from October 2012 to January 2015, and was elected to the compensation committee, effective January 2015, 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.

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 also served as a member of the board of directors of Memorial Resource since its formation in January 2014 and was a member of MRD LLC’s board of managers from September 2011 to June 2014. Mr. Gieselman has been a managing director of NGP since April 2007. Mr. Gieselman has served as a member of the board of directors of Rice Energy, Inc. since January 2014. 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.

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 has also served as a member of the board of directors of Memorial Resource since its formation in January 2014 and was a member of MRD LLC’s board of managers from April 2011 to June 2014. 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. Mr. Hersh served as a director of NGP Capital Resources Company from November 2004 until September 2014. 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 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.

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

Tony R. Weber has served as a member of the board of directors of our general partner since September 2011. Mr. Weber has also served as Chairman of the board of directors of Memorial Resource since its formation in January 2014 and was a member of MRD LLC’s board of managers from September 2011 to June 2014. Mr. Weber currently serves as Managing Partner and Chief Operating Officer 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. He currently serves on the Dean’s Council of the Mays Business School at Texas A&M University 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, 500 Dallas Street, Suite 1800, Houston, Texas 77002. 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 Brunson currently serve on the audit committee, and Mr. Clarkson serves as the chairman. Messrs. Clarkson, Highum and Brunson 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 four meetings in 2014.

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 three meetings in 2014.

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, 2014 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. 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/corporate-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, 500 Dallas Street, Suite 1800, Houston, Texas 77002 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 and Code of Business Conduct and 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 a wholly-owned subsidiary of 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.

Some of our general partner’s named executive officers are also executive officers 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 estimated time spent on each entity for 2014, on production for 2013 and on a reserve basis methodology for 2012. 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, 2014, our general partner’s named executive officers and independent directors were granted awards of restricted common units as indicated in the following table:

The board of directors of our general partner determines any awards made under our LTIP. With regard to the awards made during 2014, the board of directors took a number of factors into account, including:

For any subsequent year, the board of directors may take some or all of these factors into account, and may also consider other factors that it deems relevant at the time of determination.

On January 9, 2015, certain of our general partner’s 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. The restricted units vest and the forfeiture restrictions will generally lapse in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant (except with respect to the awards to our independent directors), 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, other than change of control agreements.

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, 2014, 2013 and 2012.

						Equity		All Other
Name and Position	Year	Salary		Bonus		Awards (4)		Compensation (5)		Total
John A. Weinzierl	2014	$	165,000	$	—	$	2,800,008	$	468,106	$	3,433,114
(Chief Executive Officer and Chairman) (1) (6)	2013		83,152		285,313		2,249,996		320,292		2,938,753
	2012		16,000		—		2,500,735		195,039		2,711,774

William J. Scarff	2014	$	153,542	$	176,458	$	1,999,990	$	108,250	$	2,438,240
(President)

Andrew J. Cozby	2014	$	165,000	$	154,000	$	1,300,010	$	226,960	$	1,845,970
(Former Vice President and Chief Financial Officer) (2)	2013		110,869		142,656		1,207,885		137,175		1,598,585
	2012		40,000		23,738		703,661		51,197		818,596

Robert L. Stillwell, Jr.	2014	$	123,750	$	96,250	$	250,007	$	44,830	$	514,837
(Vice President and Chief Financial Officer) (2)

Larry R. Forney	2014	$	165,000	$	154,000	$	1,300,010	$	221,113	$	1,840,123
(Former Vice President and Chief Operating Officer) (3)	2013		110,869		142,656		1,231,255		125,215		1,609,995
	2012		40,000		20,000		508,088		35,882		603,970

Kyle N. Roane	2014	$	165,000	$	143,000	$	899,990	$	139,043	$	1,347,033
(Senior Vice President, General Counsel and Corporate Secretary)	2013		110,869		71,328		815,625		61,570		1,059,392

Gregory M. Robbins	2014	$	165,000	$	143,000	$	899,990	$	142,498	$	1,350,488
(Senior Vice President, Corporate Development)	2013		110,869		71,328		812,509		70,557		1,065,263
	2012		32,000		8,000		192,238		16,289		248,527

The following supplemental table presents the components of “All Other Compensation” for each named executive officer for the year ended December 31, 2014:

The following table sets forth certain information with respect to grants of plan-based awards to our named executive officers in 2014.

The following table sets forth certain information with respect to outstanding equity awards at December 31, 2014.

The following table sets forth certain information with respect to equity-based awards held by our named executive officers, which vested in 2014.

		Restricted Common Unit Awards
		Number of Units		Unit Price		Market Value of Units
Name	Vesting Date (1)	That Have Vested		On Vesting Date		That Have Vested
		(#) (2)				($) (3)

John A. Weinzierl	01/09/14		43,070	$	21.99		947,109
	05/31/14		41,817	$	22.37		935,446

Andrew J. Cozby	01/09/14		7,161	$	21.99		157,470
	05/31/14		27,342	$	22.37		611,641

Robert L. Stillwell, Jr.	05/31/14		3,350	$	22.37		74,940
	08/31/14		1,082	$	23.40		25,319

Larry R. Forney	01/09/14		4,077	$	21.99		89,653
	05/31/14		27,342	$	22.37		611,641

Kyle N. Roane	01/09/14		284	$	21.99		6,245
	05/31/14		15,879	$	22.37		355,213

Gregory M. Robbins	01/09/14		2,420	$	21.99		53,216
	05/31/14		15,538	$	22.37		347,585

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, 2014 and using our closing common unit price on such date of $14.59. 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, 2014.

For 2015, 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 20, 2015, the following table sets forth the beneficial ownership of our common units that are owned by:

Memorial Production Partners GP LLC, our general partner, owns 50% of all of our IDRs 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, 2014:

MRD Holdco controls Memorial Resource and owns approximately 6.0% of our common units. Memorial Resource owns 100% of the voting membership interests in our general partner, and the Funds collectively indirectly own 50% of our incentive distribution rights. As of February 20, 2015, our general partner owns a 0.1% general partner interest in us, evidenced by 86,797 general partner units, and 50% 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.

Third 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 and 50% of our IDRs. Under our general partner’s third amended and restated limited liability company agreement, the sole member interests in our general partner are classified as Class A membership interests. Memorial Resource owns all of the Class A membership interests in our general partner. The Class A membership interests are the sole voting interests in our general partner and entitle Memorial Resource, as the Class A member, to all distributions we make to our general partner (including distributions with respect to our general partner’s 0.1% general partner interest in us).

Memorial Resource 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.

In December 2011, in connection with the closing of our initial public offering, we entered into an omnibus agreement with our general partner and MRD LLC. Memorial Resource succeeded to all of MRD LLC’s duties and obligations under the omnibus agreement in connection with certain restructuring transactions at the time of Memorial Resource’s initial public offering.

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 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 for sixty days after the expiration of the applicable statute of limitations with respect to income taxes.

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.

In April 2014, we acquired certain oil and natural gas properties in East Texas from a subsidiary of Memorial Resource, for approximately $33.3 million, including estimated customary post-closing adjustments. The acquired properties primarily represent additional working interests in wells currently owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields.

In October 2014, we acquired certain oil and natural gas properties in Weld County, Colorado from a subsidiary of Memorial Resource for approximately $15.0 million in cash consideration. The acquired properties represent working interests in wells located in the Wattenberg field (the “Wattenberg Acquisition”).

Each of the above transactions was approved by the general partner’s board of directors and by its conflicts committee. Some of the executive officers of our general partner hold similar positions with Memorial Resource, and many of the directors of our general partner own economic interests, investments and other economic incentives in affiliates of Memorial Resource. All of our general partner’s non-independent directors also 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 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 controls our general partner 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, 2014. 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, 2014 were approved by the audit committee.

The following table summarizes the aggregate KPMG fees 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 and combined 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 balance sheets of Memorial Production Partners LP and subsidiaries (the Partnership) as of December 31, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2014, 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 and subsidiaries’ internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2015 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 statements of operations, equity, and cash flows have been prepared on a combined basis of accounting.

	December 31,			December 31,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	970		$	13,139
Accounts receivable:
Oil and natural gas sales		44,105			31,132
Joint interest owners and other (Note 2)		35,458			4,634
Affiliates		—			4,473
Short-term derivative instruments		208,585			7,600
Prepaid expenses and other current assets		12,630			9,146
Total current assets		301,748			70,124
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,007,214			1,748,438
Support equipment and facilities		198,088			16,030
Other		3,006			2,900
Accumulated depreciation, depletion and impairment		(991,819	)		(418,688	)
Property and equipment, net		2,216,489			1,348,680
Long-term derivative instruments		311,802			42,657
Restricted investments		77,361			73,385
Other long-term assets		23,159			17,461
Total assets	$	2,930,559		$	1,552,307

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	21,790		$	8,566
Accounts payable - affiliates		12,781			474
Revenues payable		25,073			16,291
Accrued liabilities (Note 2)		84,471			39,847
Short-term derivative instruments		3,289			7,996
Total current liabilities		147,404			73,174
Long-term debt (Note 8)		1,595,413			792,067
Asset retirement obligations		110,372			99,619
Long-term derivative instruments		—			5,875
Other long-term liabilities		1,713			1,956
Total liabilities		1,854,902			972,691
Commitments and contingencies (Note 13)
Equity:
Partners' equity (deficit):
Common units (80,421,992 units outstanding at December 31, 2014 and 55,877,831 units outstanding at December 31, 2013)		1,085,265			582,075
Subordinated units (5,360,912 units outstanding at December 31, 2014 and 2013)		(16,419	)		(8,715	)
General partner (86,797 units outstanding at December 31, 2014 and 61,300 units outstanding at December 31, 2013)		1,251			728
Total partners' equity		1,070,097			574,088
Noncontrolling interests		5,560			5,528
Total equity		1,075,657			579,616
Total liabilities and equity	$	2,930,559		$	1,552,307

	For the Year Ended
	December 31,
	2014			2013*			2012*
Revenues:
Oil & natural gas sales	$	490,249		$	341,197		$	255,608
Pipeline tariff income and other		3,856			2,419			2,815
Total revenues		494,105			343,616			258,423

Costs and expenses:
Lease operating		134,654			88,893			80,116
Pipeline operating		2,068			1,835			2,114
Exploration		790			1,130			2,463
Production and ad valorem taxes		31,601			17,784			16,048
Depreciation, depletion, and amortization		155,404			97,269			76,036
Impairment of proved oil and natural gas properties		407,540			54,362			10,532
General and administrative		45,619			43,495			30,342
Accretion of asset retirement obligations		5,618			4,853			4,377
(Gain) loss on commodity derivative instruments		(492,254	)		(26,281	)		(21,417	)
(Gain) loss on sale of properties		—			(2,848	)		(9,759	)
Other, net		(12	)		647			138
Total costs and expenses		291,028			281,139			190,990
Operating income (loss)		203,077			62,477			67,433
Other income (expense):
Interest expense, net		(83,550	)		(41,901	)		(20,436	)
Other income (expense)		(327	)		—			—
Amortization of investment premium		—			—			(194	)
Total other income (expense)		(83,877	)		(41,901	)		(20,630	)
Income (loss) before income taxes		119,200			20,576			46,803
Income tax benefit (expense)		(1,121	)		(308	)		(285	)
Net income (loss)		118,079			20,268			46,518
Net income (loss) attributable to noncontrolling interest		32			267			104
Net income (loss) attributable to Memorial Production Partners LP	$	118,047		$	20,001		$	46,414

Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	$	118,047		$	20,001		$	46,414
Net (income) loss allocated to previous owners		—			(11,275	)		(46,293	)
Net (income) loss allocated to general partner		(206	)		(49	)		—
Net (income) loss allocated to NGP IDRs		(88	)		—			—
Limited partners' interest in net income (loss)	$	117,753		$	8,677		$	121

Earnings per unit: (Note 10)
Basic and diluted earnings per unit	$	1.66		$	0.19		$	0.01
Weighted average limited partner units outstanding:
Basic and diluted		70,859			46,017			22,880

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

	For the Year Ended
	December 31,
	2014			2013*			2012*
Cash flows from operating activities:
Net income (loss)	$	118,079		$	20,268		$	46,518
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		155,404			97,269			76,036
Impairment of proved oil and natural gas properties		407,540			54,362			10,532
(Gain) loss on derivative instruments		(492,405	)		(26,829	)		(16,578	)
Cash settlements (paid) received on derivative instruments		11,693			18,919			42,307
Premiums paid for derivatives		—			—			(411	)
Deferred income tax expense (benefit)		994			—			—
Amortization of deferred financing costs		4,227			5,845			1,991
Accretion of senior notes net discount		1,921			504			—
Amortization of investment premium		—			—			194
Accretion of asset retirement obligations		5,618			4,853			4,377
Amortization of equity awards		7,874			3,558			1,423
Gain on sale of properties		—			(2,848	)		(9,759	)
Exploration costs		—			95			36
Non-cash compensation expense		—			1,057			—
Changes in operating assets and liabilities:
Accounts receivable		(23,126	)		(2,492	)		(5,733	)
Prepaid expenses and other assets		(2,111	)		(1,210	)		(555	)
Payables and accrued liabilities		29,842			20,113			7,164
Other		(652	)		233			(698	)
Net cash provided by operating activities		224,898			193,697			156,844
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(1,083,761	)		(38,664	)		(277,623	)
Additions to oil and gas properties		(264,245	)		(161,675	)		(107,789	)
Additions to restricted investments		(3,976	)		(5,361	)		(4,599	)
Additions to other property and equipment		(89	)		(238	)		(1,748	)
Proceeds from the sale of oil and natural gas properties		—			4,525			34,521
Other		—			—			29
Net cash used in investing activities		(1,352,071	)		(201,413	)		(357,209	)
Cash flows from financing activities:
Advances on revolving credit facilities		1,446,000			958,355			391,000
Payments on revolving credit facilities		(1,137,000	)		(1,485,537	)		(121,819	)
Deferred financing costs		(11,494	)		(20,908	)		(2,225	)
Proceeds from senior notes		492,425			688,563			—
Capital contributions from previous owners		—			7,233			64,597
Contributions related to sale of assets to NGP affiliate		—			2,013			38,125
Proceeds from general partner contribution		570			521			206
Proceeds from the issuance of common units		553,288			511,204			202,572
Costs incurred in conjunction with issuance of common units		(12,510	)		(21,066	)		(8,268	)
Distributions to partners		(154,852	)		(96,643	)		(34,436	)
Distribution to Memorial Resource (see Note 1)		(48,880	)		(151,714	)		(45,489	)
Restricted units returned to plan		(1,012	)		—			—
Distribution to NGP affiliates (see Note 1)		—			(355,495	)		(242,174	)
Repurchases under unit repurchase program		(11,531	)		—			—
Transfer of operating subsidiary to Memorial Resource (see Note 12)		—			—			(3,751	)
Distributions made by previous owners		—			(31,098	)		(29,517	)
Cash retained by previous owners		—			(9,013	)		—
Net cash (used in) provided by financing activities		1,115,004			(3,585	)		208,821
Net change in cash and cash equivalents		(12,169	)		(11,301	)		8,456
Cash and cash equivalents, beginning of period		13,139			24,440			15,984
Cash and cash equivalents, end of period	$	970		$	13,139		$	24,440

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

	Partner's Equity (Deficit)
	Limited Partners						General			Previous			NGP			Noncontrolling
	Common			Subordinated			Partner			Owners			IDRs			Interest		Total
Balance December 31, 2011*	$	241,034		$	61,708		$	426		$	434,576		$	—		$	5,157	$	742,901
Net income (loss)		114			7			—			46,293			—			104		46,518
Net proceeds from the issuance of common units		194,134			—			—			—			—			—		194,134
Contributions		—			—			206			64,597			—			—		64,803
Contribution of oil and gas properties		—			—			—			6,893			—			—		6,893
Distribution attributable to net assets acquired (Note 1)		(209,720	)		(77,701	)		(242	)		—			—			—		(287,663	)
Net book value of net assets acquired (Note 12)		99,972			44,269			94			(144,335	)		—			—		—
Contribution related to sale of assets to NGP affiliate		—			—			—			40,138			—			—		40,138
Net book value of net assets acquired by NGP affiliate		—			—			—			(33,859	)		—			—		(33,859	)
Amortization of equity awards		1,423			—			—			—			—			—		1,423
Distributions		(26,152	)		(8,298	)		(34	)		(29,517	)		—			—		(64,001	)
Deferred tax liability adjustments		335			111			—			—			—			—		446
Other		64			60			—			(92	)		—			—		32
Balance December 31, 2012*		301,204			20,156			450			384,694			—			5,261		711,765
Net income (loss)		7,880			797			49			11,275			—			267		20,268
Net proceeds from the issuance of common units		490,138			—			—			—			—			—		490,138
Contributions		—			—			521			7,233			—			—		7,754
Distribution attributable to net assets acquired (Note 1)		(490,400	)		(67,242	)		(559	)		55,281			—			—		(502,920	)
Net book value of net assets acquired (Note 12)		355,159			48,739			403			(404,301	)		—			—		—
Amortization of equity awards		3,558			—			—			—			—			—		3,558
Distributions		(85,342	)		(11,165	)		(136	)		(31,098	)		—			—		(127,741	)
Other		(122	)		—			—			(2,302	)		—			—		(2,424	)
Net assets retained by previous owners		—			—			—			(20,782	)		—			—		(20,782	)
Balance, December 31, 2013		582,075			(8,715	)		728			—			—			5,528		579,616
Net income (loss)		113,573			4,180			206			—			88			32		118,079
Net proceeds from the issuance of common units		540,698			—			—			—			—			—		540,698
Contributions		—			—			570			—			—			—		570
Distributions		(142,719	)		(11,794	)		(251	)		—			(88	)		—		(154,852	)
Distribution attributable to net assets acquired (Note 12)		(2,321	)		(90	)		(2	)		—			—			—		(2,413	)
Amortization of equity awards		7,874			—			—			—			—			—		7,874
Common units repurchased under repurchase program (Note 9)		(12,903	)		—			—			—			—			—		(12,903	)
Restricted units repurchased (See Note 9)		(1,012	)		—			—						—			—		(1,012	)
Balance, December 31, 2014	$	1,085,265		$	(16,419	)	$	1,251		$	—		$	—		$	5,560	$	1,075,657

*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.

The Partnership was formed in April 2011 by Memorial Resource Development LLC (“MRD LLC”) to own, acquire and exploit oil and natural gas properties in North America. Memorial Resource Development Corp. (“MRD”) was formed by MRD LLC in January 2014 to exploit, develop and acquire natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed in April 2011 by Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P. (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. In June 2014, (i) the Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”), after which MRD Holdco owned 100% of MRD LLC, and (ii) MRD LLC distributed certain assets, including all of our subordinated units, to MRD Holdco. On June 18, 2014, MRD LLC contributed substantially all of its assets, including its interest in our general partner, to MRD in connection with MRD’s initial public offering. On June 27, 2014, MRD LLC merged into MRD Operating LLC, a subsidiary of MRD. Memorial Resource provides management, administrative, and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds are private equity funds managed by Natural Gas Partners (“NGP”). The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.

Unless the context requires otherwise, references to “Memorial Resource” refer collectively to MRD and its subsidiaries other than the Partnership. 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. 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 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 located in Texas, Louisiana, Colorado, Wyoming, New Mexico, 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).

Memorial Production Finance Corporation (“Finance Corp.”), our wholly-owned subsidiary, has no material assets or any liabilities other than as a co-issuer of our debt securities and as a guarantor of certain of our other indebtedness. Its activities will be limited to co-issuing our debt securities and engaging in other activities incidental thereto.

References to “the previous owners” for accounting and financial reporting purposes refer collectively to:

Each of these aforementioned acquisitions was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were 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 12 for additional information.

Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements were derived from the historical accounting records of the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented.

The previous owners combined financial statements reflect: (i) certain oil and gas properties acquired from MRD LLC in April and May 2012 for periods after common control commenced through their respective date of acquisition on a combined basis for all periods presented, (ii) the consolidated financial statements of REO for all periods presented, (iii) the WHT Properties from February 2, 2011 (inception) through the date of acquisition, (iv) the financial statements of Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), Tanos Energy, LLC (“Tanos”), together with its wholly-owned subsidiaries, Prospect Energy, LLC (“Prospect”), and certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) (collectively, the “Cinco Group”) on a combined basis for periods after common control commenced through the date of acquisition. The Partnership acquired substantially all of the Cinco Group on October 1, 2013 from: (a) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds, and (b) MRD LLC.

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.

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”). Certain amounts in the prior year financial statements have been reclassified to conform to current presentation.

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 the previous owners as discussed above. All material intercompany balances and transactions have been eliminated.

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 and the previous owners 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 the previous owners. 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, 2014 and 2013, respectively.

If we were to lose any one of our customers, the loss could temporarily delay the 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.

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.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. 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. Support equipment and facilities are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years.

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.

There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012.

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. We engaged Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. 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 decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other property and equipment is stated at historical cost 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 generally 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. These restricted investments may consist 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 and generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013 and 2012 was approximately $4.2 million, $5.8 million, and $2.0 million, respectively.

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to 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. Impairment expense for the years ended December 31, 2014, 2013 and 2012 was approximately $407.5 million, $54.4 million, and $10.5 million, respectively.

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 in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.

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 there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2014 or 2013.

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 a wholly-owned subsidiary of Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource allocated indirect general and administrative costs based on time allocations for the year ended December 31, 2014, on production for the year ended December 31, 2013 and on a reserve basis methodology for the year ended December 31, 2012. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 12 for additional information regarding the omnibus agreement.

General and administrative expenses associated with 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 capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we had $2.8 million in capitalized interest. We did not have any capitalized interest for the years ended December 31, 2013 and 2012.

We are organized as a pass-through entity for federal and most state income tax purposes. As a result, our partners are responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. Deferred income taxes arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. We had a net deferred income tax liability of $3.1 million and $2.0 million at December 31, 2014 and 2013, respectively.

We must recognize the income 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 income 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, 2014 or 2013.

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 10 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 11 for further information.

The governing documents of certain entities within the Cinco Group provided for the issuance of incentive units. The incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. Tanos recognized compensation expense related to the forfeiture of incentive units during April 2013 as further discussed in Note 12.

Accounts receivable from joint interest owners and other consisted of the following at the dates indicated (in thousands):

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

Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Partnership beginning on January 1, 2017. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures.

Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we and the previous owners 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.

The Partnership has consummated several common control acquisitions since completing its IPO in December 2011, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP.

Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

Wyoming Acquisition. On July 1, 2014, we consummated a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for an aggregate purchase price of approximately $906.1 million, including estimated post-closing adjustments (the “Wyoming Acquisition”). We recorded revenues of $72.0 million in the statement of operations and generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date. The following table summarizes the preliminary fair value of the third party assets acquired and liabilities assumed in the Wyoming Acquisition (in thousands):

Eagle Ford Acquisition. On March 25, 2014, we closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold. During the year ended December 31, 2014, revenues of approximately $36.5 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and we generated earnings of approximately $16.3 million for the year ended December 31, 2014.

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

The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Eagle Ford Acquisition and Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership 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 transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

Third Party. We closed two separate transactions during the year ended December 31, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands):

The Cinco Group also acquired certain oil and gas properties and leases in Texas from third parties for a final purchase price of $9.3 million.

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 MRD LLC, 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.

Collectively, the previous owners consummated multiple acquisitions during 2012 by acquiring operating and non-operating interests in certain oil and natural gas properties primarily located in various Texas and New Mexico counties for an aggregate adjusted purchase price of $150.7 million, the largest of which was completed in July by Stanolind. In July 2012, Stanolind completed an acquisition of working interests, royalty interests and net revenue interests (the “Menemsha Acquisition”) located in various counties in Texas for a final purchase price of $74.7 million. During the year ended December 31, 2012, approximately $4.9 million of revenue and $0.9 million of earnings were recorded in the statements of operations related to the Menemsha Acquisition subsequent to the closing date.

The following table summarizes the fair value of the third party 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 year ended December 31, 2012 as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition 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 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.

On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. Tanos also sold certain non-operated oil and gas properties in 2013 for $2.9 million and recorded a gain of $1.4 million.

The previous owners sold certain interests in oil and gas properties located offshore Louisiana on October 11, 2012 for an aggregate $40.1 million to an NGP controlled entity, of which $38.1 million was received upon closing and the remaining proceeds were released from escrow in April 2013. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $6.3 million and is recognized in the equity statement as a net contribution.

On July 11, 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. On September 18, 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Ector County, Texas to a third party for $4.7 million and recognized a gain of approximately $2.2 million.

The majority of the proceeds generated from these sales were used to acquire operating and non-operating interests in certain oil and natural gas properties located primarily in various Texas and New Mexico counties.

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, 2014 and 2013, 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 with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2014 and December 31, 2013. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2014 and December 31, 2013 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013 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 creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. 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 $207.3 million against amounts outstanding under our revolving credit facility at December 31, 2014, reducing our maximum credit exposure to approximately $309.8 million, of which approximately $109.7 million was with a single counterparty. See Note 8 for additional information regarding our revolving credit facility.

A combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and basis swaps) is used to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. 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 a variety of locations such as NYMEX WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At December 31, 2014, the Partnership had the following open commodity positions:


	2015			2016			2017		2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,605,278			2,692,442			2,450,067		2,160,000		1,914,583
Weighted-average fixed price	$	4.28		$	4.40		$	4.31	$	4.51	$	4.75

Collar contracts:
Average Monthly Volume (MMBtu)		350,000			—			—		—		—
Weighted-average floor price	$	4.62		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	5.80		$	—		$	—	$	—	$	—

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

Basis swaps:
Average Monthly Volume (MMBtu)		2,940,000			2,508,333			415,000		115,000		—
Spread	$	(0.12	)	$	(0.04	)	$	0.00	$	0.15	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		314,281			332,813			326,600		312,000		160,000
Weighted-average fixed price	$	90.96		$	85.83		$	84.38	$	83.74	$	85.52

Collar contracts:
Average Monthly Volume (Bbls)		5,000			—			—		—		—
Weighted-average floor price	$	80.00		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	94.00		$	—		$	—	$	—	$	—

Basis swaps:
Average Monthly Volume (Bbls)		97,500			95,000			—		—		—
Spread	$	(7.07	)	$	(9.56	)	$	—	$	—	$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		149,200			84,600			—		—		—
Weighted-average fixed price	$	43.02		$	41.49		$	—	$	—	$	—

Our basis swaps included in the table above are presented on a disaggregated basis below:


	2015			2016			2017			2018
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,280,000			2,103,333			300,000			—
Spread	$	(0.11	)	$	(0.06	)	$	(0.05	)	$	—

HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000			135,000			115,000			115,000
Spread	$	(0.08	)	$	0.07		$	0.14		$	0.15

CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000			—			—			—
Spread	$	(0.25	)	$	—		$	—		$	—

TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000			270,000			—			—
Spread	$	(0.09	)	$	0.06		$	—		$	—

Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,500			55,000			—			—
Spread - Brent	$	(9.73	)	$	(13.35	)	$	—		$	—

Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			—			—
Spread - WTI	$	(3.25	)	$	(4.34	)	$	—		$	—

Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2014, we had the following interest rate swap open positions:

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.

		Asset Derivatives						Liability Derivatives
		December 31,			December 31,			December 31,			December 31,
Type	Balance Sheet Location	2014			2013			2014			2013
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	225,882		$	18,578		$	17,297		$	17,120
Interest rate swaps	Short-term derivative instruments		—			845			3,289			2,699
Gross fair value			225,882			19,423			20,586			19,819
Netting arrangements	Short-term derivative instruments		(17,297	)		(11,823	)		(17,297	)		(11,823	)
Net recorded fair value	Short-term derivative instruments	$	208,585		$	7,600		$	3,289		$	7,996

Commodity contracts	Long-term derivative instruments	$	339,031		$	77,348		$	28,534		$	38,456
Interest rate swaps	Long-term derivative instruments		1,305			27			—			2,137
Gross fair value			340,336			77,375			28,534			40,593
Netting arrangements	Long-term derivative instruments		(28,534	)		(34,718	)		(28,534	)		(34,718	)
Net recorded fair value	Long-term derivative instruments	$	311,802		$	42,657		$	—		$	5,875

We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes and neither did the previous owners. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2014, 2013, and 2012:

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 presents the changes in the asset retirement obligations for the years ended December 31, 2014, 2013, and 2012:

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

We are a “Well-Known Seasoned Issuer” under SEC rules and have filed a universal shelf registration statement with the SEC that allows us to issue debt and equity securities. Any debt securities issued will be governed by an indenture. Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership.

Credit facilities tied to a borrowing base are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated:

OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and certain of our current and future subsidiaries.

The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base.

Borrowings under our revolving credit facility bear interest, at our option, at either: (i) the Alternate 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 0.50% to 1.50% 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), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index Rate plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

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

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

During the year ended December 31, 2014, the revolving credit facility was primarily used to fund the acquisitions of oil and gas properties. See Note 3 for additional information regarding these acquisitions.

On July 17, 2014, we and Finance Corp. (collectively, the “Issuers”) completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by

the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing February 1, 2015.

The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately.

On April 17, 2013, May 23, 2013 and October 10, 2013, the Issuers issued $300.0 million, $100.0 million and $300.0 million, respectively, of 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture and are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control.

The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers or any subsidiary guarantor that is a significant subsidiary, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately.

REO, WHT, Stanolind, Boaz, Crown, Tanos and Propel each maintained multi-year variable-rate senior secured revolving credit facilities that were primarily used for both working capital needs and to fund acquisition and development expenditures. All of Stanolind’s indebtedness outstanding under the Stanolind revolving credit facility was attributable to Stanolind SPV. Likewise, all of Propel Energy’s indebtedness outstanding under the Propel Energy revolving credit facility was attributable to Propel SPV.

On December 12, 2012, indebtedness then outstanding under the REO’s revolving credit facility of $28.5 million and all accrued interest was paid off in full and the revolving credit facility was terminated. On March 28, 2013, the debt balance then outstanding under the WHT revolving credit facility of $89.3 million and all accrued interest was paid off in full and the revolving credit facility was terminated. On April 1, 2013, indebtedness then outstanding under the Tanos revolving credit facility of $27.0 million was repaid and on April 25, 2013 all accrued interest was paid off in full and the revolving credit facility was terminated. On October 1, 2013, the debt balance then outstanding under the Boaz and Crown revolving credit facilities and all accrued interest was paid off in full and these revolving credit facilities were terminated. On October 1, 2013, the debt balance then outstanding under the Stanolind and Propel Energy revolving credit facilities and all accrued interest was paid off in full by the Partnership on behalf of Stanolind and Propel Energy, respectively.

The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented:

Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:

The following table presents borrowings and repayments under our consolidated and combined revolving credit facilities for the periods presented (in thousands):

For accounting and financial reporting purposes, any amounts that were repaid concurrent with the closing of the Beta acquisition, the WHT Properties, or the Cinco Group acquisition were a component of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facilities.”

At December 31, 2014, we had $6.7 million of letters of credit outstanding related to operations at our properties acquired in the Wyoming Acquisition.

On September 9, 2014, we issued 14,950,000 common units representing limited partner interests in the Partnership (including 1,950,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.29 per unit generating total net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.

On July 15, 2014, we issued 9,890,000 common units representing limited partner interests in the Partnership (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.

On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $18.35 per unit generating total net proceeds of approximately $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT as further discussed under Note 12.

On October 8, 2013, we issued 16,675,000 common units representing limited partner interests in the Partnership (including 2,175,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $19.90 per unit generating total net proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportional capital contribution, were used to repay a portion of outstanding borrowings under our revolving credit facility.

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. 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 Notes 8 and 12. 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.

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

						General
	Common			Subordinated		Partner
Balance, December 31, 2011		16,661,294			5,360,912		22,044
Common units issued		11,975,000			—		—
Restricted common units issued		287,943			—		—
Restricted common units forfeited		(2,334	)		—		—
General partner units issued		—			—		12,273
Balance, December 31, 2012		28,921,903			5,360,912		34,317
Common units issued		26,450,000			—		—
Restricted common units issued		524,717			—		—
Restricted common units forfeited		(11,734	)		—		—
Restricted common units repurchased (1)		(7,055	)		—		—
General partner units issued		—			—		26,983
Balance, December 31, 2013		55,877,831			5,360,912		61,300
Common units issued		24,840,000			—		—
Restricted common units issued		684,954			—		—
Restricted common units forfeited		(38,294	)		—		—
Restricted common units repurchased (1)		(42,587	)		—		—
Common units repurchased under repurchase program		(899,912	)		—		—
General partner units issued		—			—		25,497
Balance, December 31, 2014		80,421,992			5,360,912		86,797

Restricted common units are a component of common units as presented on our consolidated and combined balance sheets. See Note 11 for additional information regarding restricted common units that were granted during the years ended December 31, 2014, 2013 and 2012.

As of December 31, 2014, MRD Holdco owned 100% of the subordinated units. Memorial Resource owns 100% of our general partner, which owns 50% of our incentive distribution rights. The Funds collectively indirectly own 50% of our incentive distribution rights.

Common & Subordinated Units. The common units and the subordinated units are separate classes of the 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. The subordination period ended on February 13, 2015.

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 and IDRs. Our general partner owns a 0.1% interest in us. 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, general partner and holders of our IDRs 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 after giving effect to priority earnings allocations in an amount equal to incentive

cash distributions allocated to our general partner and NGP. 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.

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. We have also issued IDRs, which entitle the holder(s) thereof to additional increasing percentages, up to a maximum of 24.9%, of the cash we distribute in excess of $0.54625 per common unit per quarter. Our general partner owns 50%, and the Funds indirectly own 50%, of the IDRs.

Minimum Quarterly Distribution. During the subordination period, the common units had 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 were deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units were not entitled to receive any distributions from operating surplus until the common units had received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages were paid on the subordinated units. The practical effect of the subordinated units was to increase the likelihood that during the subordination period there would be available cash from operating surplus to be distributed on the common units. The subordination period ended on February 13, 2015.

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

The holders of the IDRs are 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 (i.e., the first quarter of 2015) in the following manner:

The subordination period extended 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 were are met:

On February 13, 2015, each outstanding subordinated unit converted into one common unit and will 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, our general partner will have the right to convert its general partner units into common units or to receive cash in exchange for such general partner units at the equivalent common unit fair market value

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):

								Distribution
				Amount		Aggregate		Received by
Quarter	Declaration Date	Record Date	Payable Date	Per Unit		Distribution		Affiliates
4^th Quarter 2014	January 26, 2015	February 5, 2015	February 12, 2015	$	0.5500	$	46.3	$	3.1
3^rd Quarter 2014	October 23, 2014	November 5, 2014	November 12, 2014	$	0.5500	$	47.8	$	3.1
2^nd Quarter 2014	July 24, 2014	August 5, 2014	August 12, 2014	$	0.5500	$	39.5	$	3.0
1^st Quarter 2014	April 24, 2014	May 6, 2014	May 13, 2014	$	0.5500	$	33.8	$	3.0
4^th Quarter 2013	January 27, 2014	February 6, 2014	February 13, 2014	$	0.5500	$	33.8	$	3.0
3^rd Quarter 2013	October 22, 2013	November 1, 2013	November 12, 2013	$	0.5500	$	33.8	$	6.9
2^nd Quarter 2013	July 18, 2013	August 1, 2013	August 12, 2013	$	0.5125	$	22.9	$	6.4
1^st Quarter 2013	April 18, 2013	May 1, 2013	May 13, 2013	$	0.5125	$	22.6	$	6.4
4^th Quarter 2012	January 15, 2013	February 1, 2013	February 13, 2013	$	0.5075	$	17.4	$	6.3
3^rd Quarter 2012	October 19, 2012	November 1, 2012	November 12, 2012	$	0.4950	$	11.1	$	6.2
2^nd Quarter 2012	July 19, 2012	August 1, 2012	August 13, 2012	$	0.4800	$	10.7	$	6.0
1^st Quarter 2012	April 19, 2012	May 1, 2012	May 14, 2012	$	0.4800	$	10.7	$	6.0

The following table summarizes our previous owners’ equity transactions with respect to the period indicated (dollars in thousands):

	Tanos/Classic Properties			REO			WHT Properties			Cinco Group			Total Previous Owners
Balance, December 31, 2011	$	50,853		$	72,755		$	99,524		$	211,444		$	434,576
Net income		1,000			28,691			8,369			8,233			46,293
Contributions		—			—			—			64,597			64,597
Contribution of oil and gas properties		—			—			—			6,893			6,893
Net book value of net assets acquired by Partnership		(50,639	)		(93,696	)		—			—			(144,335	)
Contribution related to sale of assets to NGP affiliate		—			—			—			40,138			40,138
Net book value of net assets acquired by NGP affiliate		—			—			—			(33,859	)		(33,859	)
Distributions		(1,214	)		(7,750	)		—			(20,553	)		(29,517	)
Other		—			—			—			(92	)		(92	)
Balance, December 31, 2012		—			—			107,893			276,801			384,694
Net income (loss)		—			—			(1,219	)		12,494			11,275
Contributions		—			—			—			7,233			7,233
Distribution attributable to net assets acquired		—			—			—			55,281			55,281
Net book value of net assets acquired by Partnership		—			—			(106,674	)		(297,627	)		(404,301	)
Distributions		—			—			—			(31,098	)		(31,098	)
Other		—			—			—			(2,302	)		(2,302	)
Net assets retained by previous owners		—			—			—			(20,782	)		(20,782	)
Balance, December 31, 2013	$	—		$	—		$	—		$	—		$	—

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

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

Our supplemental basic and diluted EPU includes all the earnings generated by the Partnership’s previous owners for all periods presented due to common control considerations. As discussed under Note 1, material transactions between entities under common control are accounted for retrospectively.

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 years ended December 31, 2014, 2013 and 2012 there were multiple awards of restricted common units that were granted under the LTIP to both 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 typically 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.

Based on the market price per unit on the date of grant, the aggregate fair value of the restricted common units awarded to our general partner’s executive officers and other Memorial Resource employees during the years ended December 31, 2014, 2013 and 2012 was $15.0 million, $9.7 million and $5.0 million, respectively. The restricted common units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. 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. Compensation costs are recorded as direct general and administrative expenses.

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

The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):

The unrecognized compensation cost associated with restricted common unit awards was an aggregate $16.5 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.1 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 years ended December 31, 2014, 2013 and 2012, the restricted common unitholders received a distribution of approximately $1.9 million, $1.0 million and $0.2 million, respectively.

Amounts due to (due from) Memorial Resource and certain affiliates of NGP at December 31, 2014 and 2013 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

On April 1, 2014, we acquired certain oil and natural gas properties in East Texas from a subsidiary of MRD LLC, for approximately $33.3 million, including customary post-closing adjustments (the “Double A Acquisition”). The acquired properties primarily represent additional working interests in wells currently owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. This acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date.

On October 1, 2014, we acquired certain oil and natural gas properties in Weld County, Colorado from Memorial Resource for approximately $15.0 million in cash consideration. The acquired properties represent working interests in wells located in the Wattenberg field (the “Wattenberg Acquisition”). Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee. This acquisition has an effective date of October 1, 2014 and was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date.

Due to common control considerations, the difference between the purchase price and the total identifiable assets has been recorded as a contribution on our Statements of Consolidated and Combined Equity.

On March 28, 2013, we acquired all of the outstanding equity interests in WHT from operating subsidiaries of MRD LLC for a purchase price of $200.0 million, which included $4.0 million of working capital and other customary adjustments. This acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our March 25, 2013 public offering of common units (including our general partner’s proportionate capital contribution). Terms of the transaction were approved by our general partner’s Board and by its conflicts committee. The WHT Properties consist of additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. 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 October 1, 2013, we acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from MRD LLC and certain affiliates of NGP for an aggregate purchase price of approximately $603 million, subject to customary post-closing adjustments. The Cinco Group acquisition was funded with borrowings under our revolving credit facility. Terms of the transaction were approved by the Board and by its conflicts committee. 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 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. 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 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). 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 MRD LLC 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 MRD LLC was as follows (in thousands):

Memorial Resource continues to provide management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):

In connection with the December 2012 Beta acquisition, Memorial Resource entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC, 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.

An affiliate of REO collected a management fee for providing administrative services to REO prior to the Beta acquisition. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. The following table summarizes the amount of management fees REO incurred and paid, which are included in general and administrative expenses in the accompanying statements of operations for the periods presented (in thousands):

WildHorse and Tanos, collectively owned the outstanding equity interests in WHT prior to March 28, 2013. Under the terms of a management agreement dated April 8, 2011, WildHorse provided executive, financial, accounting and land services to WHT. WildHorse also managed day-to-day field operations and drilling activities. Geological, executive and other services were provided by Tanos. To compensate for these services, WHT paid WildHorse and Tanos management fees totaling approximately $0.2 million per month. In connection with the WHT acquisition, the management agreement was terminated as of March 28, 2013. WildHorse collected an additional $0.6 million under a transitional agreement that was in place from April 2013 through July 2013.

As the designated operator, WildHorse received both operated and non-operated revenues on behalf of WHT and billed and received joint interest billings. WildHorse also paid for lease operating expenses, drilling cost and general and administrative costs on behalf of WHT. Receivable and payable balances were settled monthly between WHT and WildHorse.

The Partnership entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to ensure that ownership, operation, and maintenance of acquired properties could be smoothly transitioned. The term of these agreements were from October 1, 2013 through February 28, 2014. The Partnership paid transition service fees of approximately $0.8 million in the aggregate under these agreements.

Certain of the Cinco Group entities entered into an advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the years ended December 31, 2013 and 2012 were approximately $0.3 million and $0.4 million, respectively. Certain of the Cinco Group entities also paid a financing fee equal to a percentage of the capital contributions raised by NGP. These fees were considered a syndication cost and reduced equity contributions for financing fees paid. Fees for the year ended December 31, 2012 were approximately $0.4 million. There were no fees during the year ended December 31, 2013.

On April 1, 2013, Tanos’ management team sold its 1.066% membership interest in Tanos to MRD LLC and all incentive units held were forfeited. In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a Transition Services Agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity.

The governing documents of Tanos provided for the issuance of incentive units. Tanos granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions when declared, but

only after cumulative distribution thresholds had been achieved (i.e., recovery of specified members’ capital contributions plus a rate of return). These incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. No compensation cost was recorded related to incentive units prior to the incentive units being forfeited on April 1, 2013. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as general and administrative expense during April 2013.

For the years ended December 31, 2014, 2013 and 2012, the Partnership incurred gathering and salt water disposal fees of approximately $0.7 million, $0.6 million and $0.8 million, respectively, from affiliates.

During 2012, the Cinco Group received an equity contribution of $6.9 million of oil and gas properties in the Hendricks Field located in the Permian Basin of Texas by an NGP controlled entity. Due to common control considerations, this equity contribution was recorded at historical cost of the properties.

During 2012, Boaz reimbursed a member of its management team approximately $0.3 million in general, administrative, and lease operating expenses related to an oral lease agreement between the member of management and a third party for a field office and yard located in Bronte, Texas.

See Note 3 for additional information regarding the divestiture of certain interests in oil and gas properties offshore Louisiana that the Cinco Group sold during 2012 to an NGP controlled entity.

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, 2014, 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, 2014 and 2013, $2.1 million and $0.4 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, 2014, the gross account balance included in restricted investments was approximately $2.7 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $0.8 million at December 31, 2014.

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, 2014, the maximum remaining obligation net to REO’s interest was approximately $8.7 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, 2014 (in thousands):

We have leases for offshore Southern California pipeline right-of-way use as well as office space in our operating regions. We also lease equipment and incur surface rentals related to our business operations. The previous owners also leased equipment and office space under various operating leases and incurred surface rentals related to their operations.

For the years ended December 31, 2014, 2013 and 2012, we recognized $6.4 million, $2.4 million and $1.0 million of rent expense, respectively. The previous owners recorded rent expense of approximately $2.3 million and $2.1 million for the years ended December 31, 2013 and 2012, 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 (in thousands):

At December 31, 2014, we had a CO₂ purchase commitment with a third party that was assumed in our Wyoming Acquisition. The table below outlines our purchase commitment under the contract (in thousands):

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. The plan received employer contributions of approximately $1.4 million, $0.9 million, and $0.4 million in 2014, 2013, and 2012, respectively.

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 $0.6 million and $0.5 million in 2013 and 2012, respectively. Approximately $0.3 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for each of the years ended December 31, 2013, and 2012. This plan was terminated effective December 31, 2013.

Certain Cinco Group entities made matching contributions to defined contribution plans for the benefit of their eligible employees. Matching employer contributions of approximately $0.1 million and $0.2 million were made to these plans in 2013 and 2012, respectively. Such contributions to these plans are included in general and administrative expenses in the accompanying combined statements of operations.

The following tables present 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.

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except per unit amounts)
For the Year Ended December 31, 2014:
Revenues	$	100,977		$	123,310		$	147,243		$	122,575
Operating income (loss)		(17,904	)		(96,170	)		129,685			187,466
Net income (loss)		(34,057	)		(114,206	)		103,226			163,116
Net income (loss) attributable to Memorial Production Partners LP		(34,112	)		(114,194	)		103,076			163,277
Net income (loss) noncontrolling interest		55			(12	)		150			(161	)
Limited partners’ interest in net income (loss)		(34,118	)		(114,120	)		102,925			163,066
Basic and diluted earnings per unit		(0.56	)		(1.86	)		1.39			1.88

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except per unit amounts)
For the Year Ended December 31, 2013:
Revenues	$	68,102		$	90,174		$	93,240		$	92,100
Operating income (loss)		2,245			60,814			(27,368	)		26,786
Net income (loss)		(4,297	)		52,695			(39,039	)		10,909
Net income (loss) attributable to Memorial Production Partners LP		(4,293	)		52,597			(39,165	)		10,862
Net income allocated to previous owners		729			6,418			4,128			—
Net income (loss) noncontrolling interest		(4	)		98			126			47
Limited partners’ interest in net income (loss)		(5,017	)		46,133			(43,290	)		10,811
Basic and diluted earnings per unit		(0.14	)		1.04			(0.97	)		0.18

The Partnership consummated several common control acquisitions in 2013, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP. The quarterly financial information for the year ended December 31, 2013 presented above has been retrospectively revised for these common control transactions. See Notes 2 and 10 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:

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.

We engaged NSAI and Ryder Scott to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014. 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, 2014, 2013 and 2012, respectively:

		Year Ended December 31, 2014
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
	Beginning of year		39,149			607,139			28,846			1,015,105
	Extensions and discoveries		849			12,723			711			22,085
	Purchase of minerals in place		69,095			13,036			22,351			561,713
	Production		(3,092	)		(41,494	)		(2,143	)		(72,902	)
	Sales of minerals in place		—			—			—			—
	Revision of previous estimates		(6,431	)		(31,777	)		(287	)		(72,090	)
	End of year		99,570			559,627			49,478			1,453,911

Proved developed reserves:
	Beginning of year		22,265			387,548			15,959			616,893
	End of year		54,526			380,397			35,539			920,783

Proved undeveloped reserves:
	Beginning of year		16,884			219,591			12,887			398,212
	End of year		45,044			179,230			13,939			533,128

		Year Ended December 31, 2013
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
	Beginning of year		39,089			604,440			29,352			1,015,095
	Extensions and discoveries		5,655			40,770			1,747			85,180
	Purchase of minerals in place		119			16,294			258			18,554
	Production		(1,764	)		(35,924	)		(1,632	)		(56,303	)
	Sales of minerals in place		—			—			—			—
	Revision of previous estimates		(3,950	)		(18,441	)		(879	)		(47,421	)
	End of year		39,149			607,139			28,846			1,015,105

Proved developed reserves:
	Beginning of year		24,515			376,932			15,947			619,704
	End of year		22,265			387,548			15,959			616,893

Proved undeveloped reserves:
	Beginning of year		14,574			227,508			13,405			395,391
	End of year		16,884			219,591			12,887			398,212

		Year Ended December 31, 2012
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
	Beginning of year		27,150			579,751			15,045			832,913
	Extensions and discoveries		7,501			19,869			1,053			71,192
	Purchase of minerals in place		11,336			113,617			7,095			224,202
	Production		(1,519	)		(29,744	)		(745	)		(43,329	)
	Sales of minerals in place		(4,214	)		(4,214	)	--				(29,499	)
	Revision of previous estimates		(1,165	)		(74,839	)		6,904			(40,384	)
	End of year		39,089			604,440			29,352			1,015,095

Proved developed reserves:
	Beginning of year		19,332			413,431			10,015			589,504
	End of year		24,515			376,932			15,947			619,704

Proved undeveloped reserves:
	Beginning of year		7,818			166,320			5,030			243,409
	End of year		14,574			227,508			13,405			395,391

Noteworthy amounts included in the categories of proved reserve changes 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, 2014:

On February 23, 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78 million in cash for Memorial Resource’s East Texas and non-core Louisiana oil and gas properties. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. This transaction has an effective date of January 1, 2015.

The subordination period for the 5,360,912 subordinated units ended on February 13, 2015. All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period.

We repurchased an additional $28.5 million in common units, which represents a repurchase and retirement of 1,909,583 common units under the MEMP Repurchase Program through February 1, 2015.

Delaware		90-0726667
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
500 Dallas Street, Suite 1800, Houston, TX		77002
(Address of principal executive offices)		(Zip Code)

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

Large accelerated filer	þ	Accelerated filer	¨

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

Region	Developed Acreage (1)
	Gross (2)		Net (3)
East Texas/North Louisiana		169,134		85,000
Rockies		137,824		69,691
South Texas		110,038		99,513
Permian		37,766		35,756
Total		454,762		289,960

● Commercial General Liability;		● Oil Pollution Act Liability;
● Primary Umbrella / Excess Liability;		● Pollution Legal Liability;
● Property;		● Charterer’s Legal Liability;
● Workers’ Compensation;		● Non-Owned Aircraft Liability;
● Employer’s Liability;		● Automobile Liability;
● Maritime Employer’s Liability;		● Directors & Officers Liability;
● U.S. Longshore and Harbor Workers’;		● Employment Practices Liability;
● Energy Package/Control of Well;		● Crime; and
● Loss of Production (offshore only);		● Fiduciary

		Page
	PART I
Item 1.	Business	8
Item 1A.	Risk Factors	32
Item 1B.	Unresolved Staff Comments	60
Item 2.	Properties	60
Item 3.	Legal Proceedings	60
Item 4.	Mine Safety Disclosures	60
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	61
Item 6.	Selected Financial Data	63
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	66
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	84
Item 8.	Financial Statements and Supplementary Data	90
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	90
Item 9A.	Controls and Procedures	90
Item 9B.	Other Information	92
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	93
Item 11.	Executive Compensation	99
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	108
Item 13.	Certain Relationships and Related Transactions, and Director Independence	109
Item 14.	Principal Accountant Fees and Services	113
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	114
Signatures		118

	Year Ended
	December 31,
	2014
Production Volumes:
Oil (MBbls)		514
NGLs (MBbls)		106
Total (MMcfe)		3,717
Average net production (MMcfe/d)		20.2

	Reserves
	Oil		Natural Gas		NGLs		Total
	(MBbls)		(MMcf)		(MBbls)		(MMcfe) (1)
Estimated Proved Reserves
Developed		54,526		380,397		35,539		920,783
Undeveloped		45,044		179,230		13,939		533,128
Total		99,570		559,627		49,478		1,453,911

Proved developed reserves as a percentage of total proved reserves								63	%

Standardized measure (in thousands) (2)							$	2,759,607

Oil and Natural Gas Prices (3)
Oil – WTI per bbl							$	91.48
Natural gas – Henry Hub per MMBtu							$	4.35

	Undeveloped				Net Acreage Subject to
Region	Acreage				Lease Expiration by Year
	Gross (1)		Net (2)		2015		2016		2017
Rockies		88,820		52,072		2,557		3,963		7,800
Permian		11,867		11,804		804		531		—
East Texas/North Louisiana		9,962		3,165		205		840		128
South Texas		2,717		2,204		13		—		—
Total		113,366		69,245		3,579		5,334		7,928

	Year Ended December 31,
	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
Development wells:
Productive		102.0		57.3		45.0		32.6		38.0		24.4
Dry		7.0		1.9		—		—		1.0		1.0
Exploratory wells:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total wells:
Productive		102.0		57.3		45.0		32.6		38.0		24.4
Dry		7.0		1.9		—		—		1.0		1.0
Total		109.0		59.2		45.0		32.6		39.0		25.4

	Years Ending December 31,
	2014			2013			2012
Major customers:
Phillips 66 (1)		13	%		15	%		13	%
ConocoPhillips (1)	n/a			n/a				14	%
Sinclair Oil & Gas Company		12	%	n/a			n/a

	Common Unit
	Price Range				Cash
	High		Low		Distributions
2014
4th Quarter	$	22.36	$	11.75	$	0.5500
3rd Quarter	$	24.31	$	21.38	$	0.5500
2nd Quarter	$	24.75	$	21.06	$	0.5500
1st Quarter	$	23.15	$	20.16	$	0.5500

2013
4th Quarter	$	22.29	$	19.30	$	0.5500
3rd Quarter	$	21.36	$	18.19	$	0.5500
2nd Quarter	$	20.65	$	18.16	$	0.5125
1st Quarter	$	20.12	$	17.58	$	0.5125

	Total Quarterly Distributions	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders			General Partner			IDRs (1)
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	%		0.1	%		14.9	%
Thereafter	above $0.59375		75.0	%		0.1	%		24.9	%

							Approximate Dollar
					Total Number of		Value of Units
			Average		Units Purchased		That May Yet
	Total Number of		Price Paid		as Part of Publicly		Be Purchased
Period	Units Purchased		per Unit		Announced Plans		Under the Plans
							(in thousands)
Repurchase Program (1)
October 1, 2014 - October 31, 2014		—	$	—		—	$	—
November 1, 2014 - November 30, 2014		—	$	—		—	$	—
December 1, 2014 - December 31, 2014		899,912	$	14.36		899,912	$	137,079

	High		Low
For the Year Ended December 31, 2014:
NYMEX-WTI oil future price range per Bbl	$	107.26	$	53.27
NYMEX-Henry Hub natural gas future price range per MMBtu	$	6.15	$	2.89
ICE Brent oil future price range per Bbl	$	115.06	$	57.33

For the Five Years Ended December 31, 2014:
NYMEX-WTI oil future price range per Bbl	$	113.93	$	53.27
NYMEX-Henry Hub natural gas future price range per MMBtu	$	6.15	$	1.91
ICE Brent oil future price range per Bbl	$	126.65	$	57.33

	December 31, 2014
	Carrying		Estimated
Description	Amount		Fair Value
2021 Senior Notes, fixed-rate, due May 1, 2021	$	690,557	$	563,500
2022 Senior Notes, fixed-rate due August 1, 2022		492,856	$	380,000

Name	Age	Position with our General Partner
John A. Weinzierl	46	Chief Executive Officer and Chairman
William J. Scarff	59	President
Robert L. Stillwell, Jr.	37	Vice President and Chief Financial Officer
Christopher S. Cooper	47	Senior Vice President and Chief Operating Officer
Patrick T. Nguyen	42	Vice President and Chief Accounting Officer
Kyle N. Roane	35	Senior Vice President, General Counsel and Corporate Secretary
Gregory M. Robbins	36	Senior Vice President, Corporate Development
W. Donald Brunson	69	Director
Jonathan M. Clarkson	65	Director
Scott A. Gieselman	51	Director
Kenneth A. Hersh	52	Director
P. Michael Highum	64	Director
Tony R. Weber	52	Director

Name		Principal Position
John A. Weinzierl		Chief Executive Officer and Chairman
William J. Scarff		President
Andrew J. Cozby		Former Vice President and Chief Financial Officer
Robert L. Stillwell		Vice President and Chief Financial Officer
Larry R. Forney		Former Vice President and Chief Operating Officer
Kyle N. Roane		Senior Vice President, General Counsel and Corporate Secretary
Gregory M. Robbins		Senior Vice President, Corporate Development

	Aggregate Number
Award Recipient	of Restricted Units
John A. Weinzierl		125,168
William J. Scarff		89,405
Andrew J. Cozby (1)		58,114
Robert L. Stillwell, Jr.		11,176
Larry R. Forney (2)		58,144
Kyle N. Roane		40,232
Gregory M. Robbins		40,232
Jonathan M. Clarkson		4,548
P. Michael Highum		4,548
Robert A. Innamorati (3)		4,548

	Vesting	Aggregate Number
Award Recipient	Period	of Restricted Units
John A. Weinzierl (1)	3 years		11,327
Christopher S. Cooper	3 years		33,981
Jonathan M. Clarkson	1 year		8,091
P. Michael Highum	1 year		8,091
W. Donald Brunson	1 year		8,091

	Quarterly
	Distributions				Total
	Paid On				All Other
Name	LTIP Awards		Other		Compensation
John A. Weinzierl	$	458,156	$	9,950	$	468,106
William J. Scarff		98,346		9,904		108,250
Andrew J. Cozby		217,010		9,950		226,960
Robert L. Stillwell, Jr.		34,880		9,950		44,830
Larry R. Forney		211,163		9,950		221,113
Kyle N. Roane		129,093		9,950		139,043
Gregory M. Robbins		132,548		9,950		142,498

		All Other Equity Awards: Number of Restricted		Grant Date Fair Value of Unit and Option
		Units		Awards
Name	Grant Date	(#) (1)		($) (2)
John A. Weinzierl	05/30/14		125,168		2,800,008

William J. Scarff	05/30/14		89,405		1,999,990

Andrew J. Cozby	05/30/14		58,114		1,300,010

Robert L. Stillwell, Jr.	05/30/14		11,176		250,007

Larry R. Forney	05/30/14		58,114		1,300,010

Kyle N. Roane	05/30/14		40,232		899,990

Gregory M. Robbins	05/30/14		40,232		899,990

		Restricted Common
		Unit Awards
		Number of Units		Market Value of
		Units That Have		Units That Have
	Vesting	Have Not Vested		Have Not Vested
Name	Date (1)	(#)		($) (2)
John A. Weinzierl	Various		249,928		3,646,450
William J. Scarff	Various		89,405		1,304,419
Andrew J. Cozby	Various		114,027		1,663,654
Robert L. Stillwell, Jr.	Various		18,956		276,568
Larry R. Forney	Various		111,369		1,624,874
Kyle N. Roane	Various		70,855		1,033,774
Gregory M. Robbins	Various		72,596		1,059,176

	Occurrence of a
Name	Change of Control
John A. Weinzierl	$	3,646,450
William J. Scarff		1,304,419
Andrew J. Cozby		1,663,654
Robert. L. Stillwell, Jr.		276,568
Larry R. Forney		1,624,874
Kyle N. Roane		1,033,774
Gregory M. Robbins		1,059,176

	Fees Earned		Restricted		All Other
	or Paid in Cash		Unit Awards		Compensation		Total
Name	($)		($)(3)		(4)		($)
Jonathan M. Clarkson (1)	$	107,500	$	100,011	$	18,425	$	225,936
P. Michael Highum		100,000		100,011		19,135		219,146
Robert A. Innamorati (2)		91,667		100,011		17,602		209,280
W. Donald Brunson (2)		8,333		—		—		8,333

Name of Beneficial Owner (1)	Common Units Beneficially Owned (2)		Percentage of Common Units Beneficially Owned (3)
MRD Holdco LLC (4)		5,360,912		6.38	%
Kenneth A. Hersh (5)		5,360,912		6.38	%
Jonathan M. Clarkson		32,652	*
Scott A. Gieselman		—		—
P. Michael Highum		20,242	*
Tony R. Weber		—		—
John A. Weinzierl		556,420	*
William J. Scarff		96,943	*
Andrew J. Cozby (6)		152,424	*
Robert L. Stillwell, Jr.		22,871	*
Larry R. Forney (7)		142,895	*
Gregory M. Robbins		89,707	*
Kyle N. Roane		86,825	*
W. Donald Brunson		16,666	*
All executive officers and directors as a group (14 persons)		6,683,820		7.95	%
* Less than 1.0%

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans not approved by security holders (1):
Long-Term Incentive Plan		—		—		746,611

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. All of these units were sold to the public in a secondary offering by Memorial Resource in November 2013;
	·	5,360,912 subordinated units, all of which converted to common units on February 13, 2015 and are now owned by MRD Holdco;
	·	21,444 general partner units;
	·	all of our incentive distribution rights (50% of which were transferred to the Funds in December 2013); 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 MRD Holdco as the holder of approximately 6.0% of our limited partner interests, pro rata and 0.1% to our general partner, assuming it makes any capital contributions necessary to maintain its 0.1% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 25.0% of the distributions above the highest target distribution level, including the general partner’s 0.1% general partner interest.

	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of less than $0.1 million on its general partner units and MRD Holdco would receive an annual distribution of approximately $2.5 million on its common units. For the twelve months ended December 31, 2014, our general partner and its affiliates received an aggregate of $12.0 million in cash distributions from us, which consisted of approximately $11.8 million in respect of subordinated units and approximately $0.2 million in respect of our general partner units and the general partner’s incentive distribution rights.

Payments to our general partner and its affiliates	Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner and its affiliates in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the amount of such expenses that are allocable to us. For the twelve months ended December 31, 2014, we reimbursed our general partner and its affiliates an aggregate of $24.4 million for all direct and indirect expenses incurred or payments made on our behalf and all other expenses allocable to us or otherwise incurred in connection with operating our business

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

Liquidation Stage

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

	2014		2013
Audit fees (1)	$	1,800	$	2,704
Audit-related fees (2)	n/a		n/a
Tax fees (3)		414		266
All other fees (4)	n/a		n/a
Total	$	2,214	$	2,970

Exhibit Number			Description

2.1##	—		Purchase and Sale Agreement, dated as of September 18, 2012, by and among Memorial Production Operating LLC, Goodrich Petroleum Company, L.L.C. and Goodrich Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on September 19, 2012).

2.2##	—		Purchase and Sale Agreement, dated as of November 19, 2012, by and among Memorial Production Operating LLC and Rise Energy Partners, LP (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on November 20, 2012).

2.3##	—		Purchase and Sale Agreement, dated as of March 18, 2013, among Memorial Resource Development LLC, Tanos Energy, LLC, WildHorse Resources, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on March 19, 2013).

2.4##	—		Purchase and Sale Agreement, dated as of July 15, 2013, between Boaz Energy Partners, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 2013).

2.5##	—		Purchase and Sale Agreement, dated as of July 15, 2013, between Crown Energy Partners Holdings, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.2 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 2013).

2.6##	—		Purchase and Sale Agreement, dated as of July 15, 2013, between Propel Energy, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.3 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 2013).

2.7##	—		Purchase and Sale Agreement, dated as of July 15, 2013, between Stanolind Oil and Gas LP and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.4 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 2013).

2.8##	—		Purchase and Sale Agreement, dated as of July 15, 2013, between Memorial Resource Development LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.5 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 2013).

2.9##	—	Purchase and Sale Agreement, dated as of March 25, 2014, between Alta Mesa Eagle, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on March 25, 2014).

2.10##	—	Purchase and Sale Agreement, dated as of May 2, 2014, among Merit Management Partners I, L.P., Merit Energy Partners III, L.P., Merit Pipeline Company, LLC and Merit Energy Company, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2014).

3.1	—		Certificate of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).

3.2	—		First Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

3.3	—		Certificate of Formation of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.4 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).

3.4	—		Third Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.4 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 6, 2014).

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

Exhibit Number		Description
4.2	—	Indenture, dated April 17, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2013).

4.3	—	First Supplemental Indenture, dated as of October 7, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on November 7, 2013).

4.4	—	Indenture, dated July 17, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2014).

4.5	—	Registration Rights Agreement, dated July 17, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Barclays Capital Inc., as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2014).

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

10.2	—	Credit Agreement, dated as of December 14, 2011, among Memorial Production Operating LLC, as borrower, Memorial Production Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, BNP Paribas, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011), as amended by First Amendment to Credit Agreement, dated as of April 30, 2012 (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 15, 2012), as further amended by Second Amendment to Credit Agreement, dated as of September 18, 2012 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on September 19, 2012), as further amended by Third Amendment to Credit Agreement, dated as of December 3, 2012 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 4, 2012), as further amended by Fourth Amendment to Credit Agreement and First Amendment to Guaranty Agreement, dated as of March 8, 2013 (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 10, 2013), as further amended by Fifth Amendment to Credit Agreement, dated as of March 19, 2013 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on March 21, 2013), as further amended by Sixth Amendment to Credit Agreement, dated as of September 26, 2013 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on October 1, 2013), as further amended by Seventh Amendment to Credit Agreement, dated as of June 13, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on June 19, 2014), as further amended by Eighth Amendment to Credit Agreement, dated as of October 10, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on October 14, 2014), and as further amended by Ninth Amendment to Credit Agreement, dated as of December 17, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 18, 2014).

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

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

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

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

10.7	—	Purchase Agreement, dated April 12, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Wells Fargo Securities, LLC, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2013).

10.8	—	Purchase Agreement, dated May 20, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Wells Fargo Securities, LLC, as the initial purchaser (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 23, 2013).

10.9	—	Purchase Agreement, dated October 7, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Wells Fargo Securities, LLC, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on October 10, 2013).

10.10	—	Purchase Agreement, dated July 14, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Barclays Capital Inc., as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on July 15, 2014).

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

23.1*	—	Consent of KPMG LLP.

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

23.3*	—		Consent of Ryder Scott Company, L.P.

31.1*	—	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

31.2*	—	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

32.1*	—	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

99.2*			Report of Ryder Scott Company, L.P.

101.CAL*	—	XBRL Calculation Linkbase Document

101.DEF*	—	XBRL Definition Linkbase Document

101.INS*	—	XBRL Instance Document

101.LAB*	—	XBRL Labels Linkbase Document

101.PRE*	—	XBRL Presentation Linkbase Document

101.SCH*	—	XBRL Schema Document

	Memorial Production Partners LP
	(Registrant)

	By:	Memorial Production Partners GP LLC, its general partner

Date: February 26, 2015	By:	/s/ Robert L. Stillwell, Jr.
		Robert L. Stillwell, Jr.
		Vice President and Chief Financial Officer of Memorial Production Partners GP LLC

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

/s/ John A. Weinzierl	Chief Executive Officer and Chairman	February 26, 2015
John A. Weinzierl	(Principal Executive Officer)

/s/ Robert L. Stillwell, Jr.	Vice President and Chief Financial Officer	February 26, 2015
Robert L. Stillwell, Jr.	(Principal Financial Officer)

/s/ Patrick T. Nguyen	Vice President and Chief Accounting Officer	February 26, 2015
Patrick T. Nguyen	(Principal Accounting Officer)

/s/ Jonathan M. Clarkson	Director	February 26, 2015
Jonathan M. Clarkson

/s/ W. Donald Brunson	Director	February 26, 2015
W. Donald Brunson

/s/ Scott A. Gieselman	Director	February 26, 2015
Scott A. Gieselman

/s/ Kenneth A. Hersh	Director	February 26, 2015
Kenneth A. Hersh

/s/ P. Michael Highum	Director	February 26, 2015
P. Michael Highum

/s/ Tony R. Weber	Director	February 26, 2015
Tony R. Weber