Amplify Energy (AMPYW) 8-K Memorial Production Partners LP

Exhibit 99.1

MEMORIAL PRODUCTION PARTNERS LP

RECAST OF CERTAIN SECTIONS OF THE 2012 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

		Page
	Glossary of Oil and Natural Gas Terms	2
Recast Item 6.	Selected Financial Data.		6
Recast Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		8
Recast Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.		27

1

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

Bbl/d:One Bbl per day.

Bcf:One billion cubic feet of natural gas.

Bcfe: One billion cubic feet of natural gas equivalent.

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

Boe/d: One Boe per day.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

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

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

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

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

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

Dry HoleorDry 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.

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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.

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

MBtu/d: One thousand Btu per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe:One million cubic feet of natural gas equivalent.

Net Acresor 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.

NYMEX:New York Mercantile Exchange.

Oil:Oil and condensate.

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

OPIS:Oil Price Information Service.

Play: A geographic area with hydrocarbon potential.

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

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

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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).

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Reservoir:A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

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

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

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the United States Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

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

Wellbore:The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

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

WTI: West Texas Intermediate.

5

RECAST ITEM 6.  SELECTED FINANCIAL DATA

The following selected financial data should be read in conjunction with “Recast Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained herein and “Recast Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Report.

Basis of Presentation. The selected financial data as of, and for the years ended, December 31, 2012, 2011, 2010, 2009 and 2008 have been derived from our consolidated financial statements and our predecessor and/or the previous owners’ combined financial statements. The combined financial statements of our predecessor are those of BlueStone and the Classic Carve-Out through December 13, 2011 and the WHT Assets for periods after April 8, 2011 through December 13, 2011. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in both April and May 2012 and March 2013 and the consolidated financial statements of REO from February 3, 2009 (inception) through December 11, 2012. The combined selected financial data of our predecessor and/or the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated those assets separately during those periods.

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

• Two separate acquisitions of assets in South Texas in April and October 2008, respectively, for a total purchase price of approximately $14.7 million.

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

• The acquisition of working interests in Beta properties in December 2009 for approximately $73.8 million.

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

• Two separate acquisitions of assets in East Texas in January and March 2010, respectively, for a net purchase price of approximately $14.0 million.

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

• The acquisition of assets in East Texas in mid-December 2010 from a publicly traded oil and gas producer for a net purchase price of approximately $15.0 million.

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

• The acquisition of oil and natural gas properties and related assets from a third party in April 2011 for a total purchase price of approximately $302.0 million.

• Two separate acquisitions of assets in East Texas in May and September 2012, respectively, for a net purchase price of approximately $126.9 million.

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	For Year Ended December 31,
	2012			2011			2010			2009			2008
	($ in thousands, except per unit data)
										(Unaudited)			(Unaudited)
Statement of Operations Data:
Revenues:
Oil & natural gas sales	$	172,263		$	170,411		$	89,338		$	32,032		$	56,418
Pipeline tariff income		1,468			1,379			1,332			—			—
Other income		224			825			1,433			319			622
Total revenues		173,955			172,615			92,103			32,351			57,040
Costs and expenses:
Lease operating		53,453			46,975			32,513			12,191			9,239
Pipeline operating		2,114			2,526			1,896			—			—
Exploration		554			417			161			2,690			374
Production and ad valorem taxes		9,555			6,887			2,838			2,032			3,604
Depreciation, depletion, and amortization		49,390			41,748			29,697			19,011			13,835
Impairment of proved oil and natural gas properties		—			15,141			11,800			3,480			18,564
General and administrative		18,019			15,549			10,544			5.845			4,400
Accretion of asset retirement obligations		3,755			3,549			2,924			326			226
(Gain) loss on commodity derivative instruments		(16,996	)		(47,314	)		(7,679	)		(11,121	)		(9,815	)
Gain on sale of properties		(426	)		(63,024	)		(1	)		(7,851	)		(7,395	)
Other, net		730			2,260			1,195			448			50
Total costs and expenses		120,148			24,714			85,888			27,051			33,082
Operating income		53,807			147,901			6,215			5,300			23,958
Other income (expense):
Interest expense, net		(15,043	)		(10,830	)		(3,441	)		(2,937	)		(3,138	)
Amortization of investment premium		(194	)		(606	)		(907	)		—			—
Total other income (expense)		(15,237	)		(11,436	)		(4,348	)		(2,937	)		(3,138	)
Income (loss) before income taxes		38,570			136,465			1,867			2,363			20,820
Income tax benefit (expense)		(285	)		(139	)		(218	)		—			—
Net income		38,285			136,326			1,649			2,363			20,820
Net income (loss) attributable to predecessor		—			75,740			(11,317	)		1,106			21,085
Net income (loss) attributable to previous owners		38,060			54,140			12,974			1,257			(265	)
Net income (loss) attributable to noncontrolling interest		104			(146	)		(8	)		—			—
Net income attributable to partners	$	121		$	6,592		$	—		$	—		$	—
Allocation of net income (loss) attributable to partners:
Limited partners	$	121		$	6,585		$	—		$	—		$	—
General partner	$	—		$	7		$	—		$	—		$	—
Earnings per unit attributable to limited partners:
Basic and diluted earnings per unit	$	0.01		$	0.30		$	n/a		$	n/a		$	n/a
Cash distributions declared per unit	$	1.5479		$	n/a		$	n/a		$	n/a		$	n/a
										(Unaudited)			(Unaudited)
Cash Flow Data:
Net cash flow provided by operating activities	$	117,900		$	92,435		$	44,729		$	17,433		$	38,455
Net cash used in investing activities		183,223			373,504			143,770			131,672			63,614
Net cash provided by financing activities		63,689			273,657			110,780			117,953			24,069
							(Unaudited)			(Unaudited)			(Unaudited)
Balance Sheet Data:
Working capital (deficit)	$	39,171		$	38,934		$	19,261		$	10,872		$	(965	)
Total assets		1,006,190			906,836			469,206			319,725			160,383
Total debt		460,300			254,900			115,359			61,760			62,526
Total equity		434,964			531,457			255,344			194,926			69,345

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RECAST ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Recast Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report. 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 our 2012 Form 10-K. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Forward-Looking Statements” in the front of our 2012 Form 10-K.

Overview

We are a Delaware limited partnership formed in April 2011 by Memorial Resource to own, acquire and exploit oil and natural gas properties in North America. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. As of December 31, 2012:

• Our total estimated proved reserves were approximately 771 Bcfe, of which approximately 63% were natural gas and 60% were classified as proved developed reserves;

• We produced from 1,671 gross (926 net) producing wells across our properties, with an average working interest of 55%, and we or Memorial Resource operated 97% of the properties in which we have interests; and

• Our average net production for the three months ended December 31, 2012 was 92.9 MMcfe/d, implying a reserve-to-production ratio of approximately 23 years.

Business Environment and Operational Focus

Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions.

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

• production volumes;

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

• lease operating expenses;

• general and administrative expenses; and

• Adjusted EBITDA (defined below).

Production Volumes

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

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Realized Prices on the Sale of Oil and Natural Gas

We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

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

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

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

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

The oil produced from our onshore properties is a combination of sweet and sour oil, varying by location. This oil is sold at the NYMEX-WTI price, which is adjusted for quality and transportation differential, depending primarily on location and purchaser. The oil produced from our Beta properties is sour oil. Prices for 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 traded at a premium to the NYMEX-WTI price and has more closely tracked the ICE Brent price. We believe this trend will continue for the foreseeable future and on February 1, 2013 executed a basis swap trade that guarantees a price differential to the ICE Brent price covering the remainder of 2013. That basis hedge has not always been available and may not be available in the future or at a price that is economical or at all.

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

	High		Low
For Year Ended December 31, 2012:
NYMEX-WTI oil future price range per Bbl	$	109.77	$	77.69
NYMEX-Henry Hub natural gas future price range per MMBtu	$	3.90	$	1.91
ICE Brent oil future price range per Bbl	$	126.22	$	89.23
For Five Years Ended December 31, 2012:
NYMEX-WTI oil future price range per Bbl	$	145.29	$	33.87
NYMEX-Henry Hub natural gas future price range per MMBtu	$	13.58	$	1.91
ICE Brent oil future price range per Bbl	$	146.08	$	36.61

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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

We strive to increase our production levels to maximize our revenue and cash available for distribution. Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, and materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed.

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

We monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we monitor our production expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold. We typically evaluate our oil and natural gas operating costs on a per Mcfe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.

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

General and Administrative Expenses

We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. During the year ended December 31, 2012, Memorial Resource allocated its general and administrative costs based on the relative size of our proved and probable reserves in comparison to Memorial Resource’s proved and probable reserves. In January 2013, Memorial Resource began to allocate its general and administrative costs based on our relative production in comparison to Memorial Resource’s production, which they believe will more accurately reflect the cost incurred to provide services to us. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf. For a detailed description of the omnibus agreement, please read “Item 13. Certain Relationships and Related Transactions, and Director Independence — Related Party Agreements —Omnibus Agreement” contained in our 2012 Form 10-K.

Adjusted EBITDA

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

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Plus:

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

• Income tax expense;

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

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

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

• Unrealized losses on commodity derivative contracts;

• Losses on sale of assets and other, net;

• Unit-based compensation expenses;

• Exploration costs;

• Acquisition related costs;

• Amortization of investment premium;

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

• Other non-routine items that we deem appropriate.

Less:

• Interest income;

• Income tax benefit;

• Unrealized gains on commodity derivative contracts;

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

• Other non-routine items that we deem appropriate.

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

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, research analysts and rating agencies, to assess:

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

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

• the viability of projects and the overall rates of return on alternative investment opportunities.

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.

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Calculation of Adjusted EBITDA

	For Year Ended December 31,
	2012			2011			2010
	($ in thousands)
Net income	$	38,285		$	136,326		$	1,649
Interest expense, net		15,043			10,830			3,441
Income tax expense		285			139			218
DD&A		49,390			41,748			29,697
Impairment		—			15,141			11,800
Accretion of AROs		3,755			3,549			2,924
Unrealized (gains) losses on commodity derivative instruments		20,612			(38,494	)		(547	)
Acquisition related costs		3,290			1,045			890
Unit-based compensation expense		1,423			—			—
Gain on sale of properties		(426	)		(63,024	)		(1	)
Exploration costs		554			417			161
Amortization of investment premium		194			606			907
Net operating cash flow from acquisitions, effective date through closing date		5,808			—			—
Adjusted EBITDA	$	138,213		$	108,283		$	51,139

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

	For Year Ended December 31,
	2012			2011			2010
	($ in thousands)
Net cash provided by operating activities	$	117,900		$	92,435		$	44,729
Changes in working capital		(7	)		1,638			3,231
Interest expense		15,043			10,830			3,441
Premiums paid for derivatives		—			7,117			—
Premiums received for derivatives		—			(2,520	)		—
Unrealized gain (loss) on interest rate swaps		(3,198	)		(1,721	)		(296	)
Acquisition related costs		3,290			1,045			890
Amortization of deferred financing fees		(1,426	)		(1,077	)		(981	)
Income tax expense – current portion		285			175			2
Exploration costs		518			361			123
Net operating cash flow from acquisitions, effective date through closing date		5,808			—			—
Adjusted EBITDA	$	138,213		$	108,283		$	51,139

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Critical Accounting Policies and Estimates

Oil and Natural Gas Properties

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

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and natural gas reserves related to the associated field.

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

Proved Oil and Natural Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We intend to use NSAI to prepare a reserve report as of December 31 of each year for a vast majority of our proved reserves and to prepare internal estimates of our proved reserves as of June 30 of each year.

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

A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment. For example, if the SEC prices used for our December 31, 2012 reserve report had been $10.00 less per Bbl and $1.00 less per MMBtu, then the standardized measure of our estimated proved reserves as of December 31, 2012 would have decreased by approximately $333 million, from $994 million to $661 million.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production, drilling results, 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.

Asset Retirement Obligations

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

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2012 or 2011.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under 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.

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Results of Operations

The results of operations for the years ended December 31, 2012, 2011 and 2010 have been derived from both our consolidated financial statements subsequent to the closing of our initial public offering and our predecessor’s and/or previous owners’ combined financial statements. The combined financial statements of our predecessor are those of BlueStone and the Classic Carve-Out through December 13, 2011 and the WHT Assets for periods after April 8, 2011 through December 13, 2011. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in both April and May 2012 and March 2013 for periods after common control commenced through their respective acquisition dates and the consolidated financial statements of REO from February 3, 2009 (inception) through December 11, 2012. The results of operations attributable to our predecessor and/or previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods.

Factors Affecting the Comparability of the Combined Historical Financial Results

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

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

• Two separate acquisitions of assets in East Texas in January and March 2010, respectively, for a net purchase price of approximately $14.0 million.

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

• The acquisition of assets in East Texas in mid-December 2010 from a publicly traded oil and gas producer for a net purchase price of approximately $15.0 million.

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

• The acquisition of oil and natural gas properties and related assets from a third party in April 2011 for a total purchase price of approximately $302.0 million.

• Two separate acquisitions of assets in East Texas in May and September 2012, respectively, for a net purchase price of approximately $126.9 million.

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.

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

	For Year Ended December 31,
	2012			2011			2010
	(in thousands, except operating and per unit amounts)
Revenues:
Oil & natural gas sales	$	172,263		$	170,411		$	89,338
Pipeline tariff income		1,468			1,379			1,332
Other income		224			825			1,433
Total revenues	$	173,955		$	172,615		$	92,103
Costs and expenses:
Lease operating		53,453			46,975			32,513
Pipeline operating		2,114			2,526			1,896
Exploration		554			417			161
Production and ad valorem taxes		9,555			6,887			2,838
Depreciation, depletion, and amortization		49,390			41,748			29,697
Impairment of proved oil and natural gas properties		—			15,141			11,800
General and administrative		18,019			15,549			10,544
Accretion of asset retirement obligations		3,755			3,549			2,924
Realized gain on commodity derivative instruments		(37,608	)		(8,820	)		(7,132	)
Unrealized (gain) loss on commodity derivative instruments		20,612			(38,494	)		(547	)
Gain on sale of properties		(426	)		(63,024	)		(1	)
Other, net		730			2,260			1,195
Total costs and expenses		120,148			24,714			85,888
Operating income		53,807			147,901			6,215
Other income (expense):
Interest expense, net		(15,043	)		(10,830	)		(3,441	)
Amortization of investment premium		(194	)		(606	)		(907	)
Total other income (expense)		(15,237	)		(11,436	)		(4,348	)
Income (loss) before income taxes		38,570			136,465			1,867
Income tax benefit (expense)		(285	)		(139	)		(218	)
Net income		38,285			136,326			1,649
Net income attributable to predecessor		—			75,740			(11,317	)
Net income attributable to previous owners		38,060			54,140			12,974
Net income (loss) attributable to noncontrolling interest		104			(146	)		(8	)
Net income attributable to partners	$	121		$	6,592		$	—
Oil and natural gas revenue:
Oil sales	$	82,299		$	73,618		$	46,584
NGL sales		25,823			19,865			2,837
Natural gas sales		64,141			76,928			39,917
Total oil and natural gas revenue	$	172,263		$	170,411		$	89,338
Production Volumes:
Oil (MBbls)		820			731			639
NGLs (MBbls)		704			371			69
Natural gas (MMcf)		23,144			19,211			9,151
Total (MMcfe)		32,285			25,823			13,403
Average net production (MMcfe/d)		88.2			70.7			36.7
Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	100.33		$	100.64		$	72.81
NGL(per Bbl)		36.73			53.55			40.82
Natural gas (per Mcf)		2.77			4.00			4.36
Total (Mcfe) (excluding commodity derivatives)	$	5.34		$	6.60		$	6.66
Total (Mcfe) (including commodity derivatives)	$	6.50		$	6.94		$	7.20
Average unit costs per Mcfe:
Lease operating expense	$	1.66		$	1.82		$	2.43
Production and ad valorem taxes	$	0.30		$	0.27		$	0.21
General and administrative expenses	$	0.56		$	0.60		$	0.79
Depletion, depreciation, and amortization	$	1.53		$	1.62		$	2.22

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Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Net income was $38.3 million for the year ended December 31, 2012, of which $38.1 million was attributable to the previous owners. Net income was $136.3 million for the year ended December 31, 2011, of which $75.7 million was attributable to our predecessor and $54.1 million was attributable to the previous owners. Our predecessor recorded an aggregate gain on the sale of properties of $63.0 million during 2011 with no comparable gain recorded during 2012.

Revenues. Oil, natural gas and NGL revenues for 2012 totaled $172.3 million, an increase of $1.9 million compared with 2011. Production increased 6,462 MMcfe (approximately 25%) and the average realized sales price (excluding realized gain on derivatives) decreased $1.26 per Mcfe. The favorable volume variance contributed to a $42.6 million increase in revenues, whereas the unfavorable pricing variance contributed to a $40.7 million decrease in revenues.

Lease Operating.Lease operating expenses for 2012 were $53.5 million compared to $47.0 million for 2011, a $6.5 million year-to-year increase. Lease operating expenses increased primarily due to costs associated with properties acquired by both the Partnership from third parties in May and September of 2012 and our predecessor in April and May of 2011. On a per Mcfe basis, lease operating expenses decreased to $1.66 for 2012 from $1.82 for 2011.

Production and Ad Valorem Taxes. Production and ad valorem taxes for 2012 totaled $9.6 million, an increase of $2.7 million compared with 2011. The increase was largely due to a $2.0 million increase in ad valorem taxes primarily due to higher assessed values as a result of increased production levels. Ad valorem taxes are property taxes generally assessed and levied at the local level. The value of the discounted cash flow estimated from future production in the upcoming year is the appraisal methodology used in Texas. There is no production and ad valorem tax assessed for our Beta properties. Production taxes were 3.3% and 3.4% as a percentage of oil and natural gas revenue in 2012 and 2011, respectively.

Depreciation, Depletion and Amortization. DD&A expense for 2012 was $49.4 million compared to $41.7 million for 2011, a $7.7 million year-to-year increase primarily due to increased production volumes related to acquisitions in 2011 and 2012. DD&A expense per Mcfe was $1.53 for 2012 compared to $1.62 for 2011. Increased production volumes caused DD&A expense to increase by $10.5 million, while the 6% change in the DD&A rate between periods caused DD&A expense to decrease by $2.8 million. An increase in proved reserve volumes more than offset the impact of increases to the depletable cost base.

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

Impairment of Proved Oil and Natural Gas Properties. No impairments to proved oil and natural gas properties were recognized during 2012. During 2011, approximately $3.1 million of the $15.1 million of impairments related to a well abandoned in the Burke Unit located in South Texas due to a situation encountered during drilling, causing costs and future benefits to become unrecoverable. The remaining $12.0 million of impairments in 2011 consisted of $6.9 million to the Craton field and $4.0 million to the Cayuga field, both of which are located in East Texas, as well as $0.1 million to the Benavides field and $1.0 million to the Wishbone field in South Texas. For these impairments, the estimated future cash flows expected from properties in these fields were compared to their carrying values and determined to be unrecoverable as a result of declines in natural gas prices. All impairments recognized during 2011 were attributable to our predecessor.

General and Administrative. Our general and administrative expenses include the costs of administrative employees and related benefits, management fees paid to Memorial Resource, professional fees and other costs not directly associated with field operations. General and administrative expenses for 2012 were $18.0 million, of which $6.7 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 $3.3 million of acquisition-related costs. General and administrative expenses for 2011 totaled $15.5 million, of which $15.3 million was attributable to our predecessor and the previous owners.

On a per Mcfe basis, general and administrative expenses were $0.56 in 2012 compared to $0.60 in 2011 due to increased production volumes.

Gain on Derivative Instruments. Net gains on commodity derivative instruments of $17.0 million were recognized during 2012, of which $37.6 million was a realized gain and $20.6 million was an unrealized loss. Net gains on commodity derivative instruments of $47.3 million were recognized during 2011, of which $8.8 million was a realized gain and $38.5 million was an unrealized gain.

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

Gain on Sale of Properties. Our predecessor recognized a gain on sale of properties of $63.0 million during 2011. We recorded no comparable gain in 2012. Effective January 1, 2011, our predecessor acquired BP’s interests in producing wells located in Duval, Jim Hogg, McMullen and Webb counties in exchange for (i) our predecessor’s interest in approximately 10,700 net acres located in the Nueces Field of the Eagle Ford Shale and (ii) $20 million in cash, subject to certain closing adjustments. The transaction closed on May 31, 2011 and the predecessor paid a total of approximately $12.9 million in cash consideration at closing, net of adjustments. The preliminary purchase price allocation resulted in the acquisition date fair value of $82.6 million allocated to proved oil and gas properties, $1.2 million allocated to asset retirement obligations, $0.5 million to accrued liabilities, and $0.6 million to deferred tax liabilities. After taking into consideration the net book value of $5.2 million for the Nueces Field properties exchanged to BP and the $12.9 million in cash consideration paid at closing, the predecessor recorded a $62.2 million gain relating to such transaction.

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

Net Interest Expense. Net interest expense is comprised of interest on credit facilities, amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Net interest expense totaled $15.0 million during 2012, of which $10.4 million was attributable to the Partnership’s revolving credit facility, including unrealized losses on interest rate swaps of approximately $3.5 million and amortization of deferred financing fees of approximately $0.6 million. Unamortized deferred financing costs associated with REO’s revolving credit facility were approximately $0.4 million at December 31, 2011. The unamortized deferred financing costs associated with this revolving credit facility were written-off at the time REO’s debt was repaid and terminated in December 2012. During 2012 the average outstanding borrowings under the Partnership’s revolving credit facility were $204.3 million. Net interest expense totaled $10.8 million during 2011, of which $10.3 million was attributable to our predecessor and the previous owners. Only $0.5 million was attributable to the Partnership’s revolving credit facility, including unrealized losses on interest rate swaps of $0.3 million.

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

Net income was $136.3 million for the year ended December 31, 2011, of which $75.7 million was attributable to our predecessor and $54.1 million was attributable to the previous owners. Our predecessor recorded a net loss of $11.3 million for the year ended December 31, 2010, none of which was attributable to the Partnership. The previous owners recorded net income of $13.0 million for the year ended December 31, 2010, none of which was attributable to the Partnership. Revenues generated for 2011 were $172.6 million compared to $92.1 million for 2010, an $80.5 million year-to-year increase. Our predecessor recorded an aggregate gain on the sale of properties of $63.0 million during 2011 with no comparable gain recorded during 2010. Gains on commodity derivative instruments of $47.3 million were recognized during 2011 compared to gains on commodity derivative instruments of $7.7 million recognized in 2010.

Revenues. Oil, natural gas and NGL revenues for 2011 totaled $170.4 million, an increase of $81.1 million compared with 2010. Production increased 12,420 MMcfe (approximately 93%) and the average realized sales price (excluding realized gain on derivatives) decreased $0.06 per Mcfe. The favorable volume contributed to an $82.7 million increase in revenues, while the unfavorable pricing variance resulted in a $1.6 million reduction in revenues. Production volumes increased primarily related to the 2010 acquisitions of certain oil and gas assets in South Texas that were fully integrated in 2011, the acquisition of properties from BP in May 2011 and the acquisition of certain oil and gas assets in April 2011.

Lease Operating.Lease operating expenses for 2011 were $47.0 million compared to $32.5 million for 2010, a $14.5 million year-to-year increase. Lease operating expenses increased primarily due to costs associated with the South Texas properties acquired in 2010 which were fully integrated in 2011, the BP properties acquired in May 2011 and the acquisition of certain oil and gas assets in April 2011. On a per Mcfe basis, lease operating expenses decreased to $1.82 for 2011 from $2.43 for 2010.

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Production and Ad Valorem Taxes. Production and ad valorem taxes for 2011 totaled $6.9 million, an increase of $4.0 million compared with 2010. The increase in production and ad valorem taxes was largely due to higher onshore oil, natural gas and NGL revenues during 2011. Higher assessed values as a result of higher commodity prices were also a contributing factor. Production taxes were 3.4% and 3.6% as a percentage of oil and natural gas revenue in 2011 and 2010, respectively.

Depreciation, Depletion and Amortization. DD&A expense for 2011 was $41.8 million compared to $29.7 million for 2010, a $12.1 million year-to-year increase primarily due to increased production volumes related to acquisitions in 2010 and 2011. DD&A expense per Mcfe was $1.62 for 2011 compared to $2.22 for 2010. Increased production volumes caused DD&A expense to increase by $27.6 million, while the 27% change in the DD&A rate between periods caused DD&A expense to decrease by $15.5 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 cost base changes, then the DD&A rate moves in the same direction. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes.

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

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

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

General and Administrative. General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to Memorial Resource, professional fees and other costs not directly associated with field operations. General and administrative expenses for 2011 totaled $15.5 million, of which $15.3 million was attributable to our predecessor and the previous owners. For 2010, general and administrative expenses were $10.5 million. General and administrative expenses were $0.60 per Mcfe in 2011 compared to $0.79 per Mcfe in 2010 due to increased production volumes.

Gain on Derivative Instruments. Net gains on commodity derivative instruments of $47.3 million were recognized during 2011, of which $8.8 million was a realized gain and $38.5 million was an unrealized gain. Net gains on commodity derivative instruments of $7.7 million were recognized during 2010, of which $7.1 million was a realized gain and $0.6 million was an unrealized gain.

Gain on Sale of Properties. Our predecessor recognized a gain on sale of properties of $63.0 million during 2011 with no comparable gain recorded in 2010. Effective January 1, 2011, our predecessor acquired BP’s interests in producing wells located in Duval, Jim Hogg, McMullen and Webb counties in exchange for (i) our predecessor’s interest in approximately 10,700 net acres located in the Nueces Field of the Eagle Ford Shale and (ii) $20 million in cash, subject to certain closing adjustments. The transaction closed on May 31, 2011 and the predecessor paid a total of approximately $12.9 million in cash consideration at closing, net of adjustments. The preliminary purchase price allocation resulted in the acquisition date fair value of $82.6 million allocated to proved oil and gas properties, $1.2 million allocated to asset retirement obligations, $0.5 million to accrued liabilities, and $0.6 million to deferred tax liabilities. After taking into consideration the net book value of $5.2 million for the Nueces Field properties exchanged to BP and the $12.9 million in cash consideration paid at closing, the predecessor recorded a $62.2 million gain relating to such transaction.

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

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Net Interest Expense.Net interest expense is comprised of interest income, interest on credit facilities, amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Net interest expense totaled $10.8 million during 2011, of which $10.3 million was attributable to our predecessor and the previous owners. Only $0.5 million was attributable to the Partnership’s revolving credit facility, including unrealized losses on interest rate swaps of $0.3 million. Net interest expense was $3.4 million in 2010, all of which was attributable to our predecessor and the previous owners. The increase was due primarily to additional debt incurred in conjunction with the acquisitions of oil and natural gas assets by our predecessor and the previous owners.

Liquidity and Capital Resources

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

Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We may also have the ability to issue additional equity and debt as needed. Our exposure to current credit conditions includes our revolving credit facility, cash investments and counterparty performance risks. Volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

Crude oil, NGL and natural gas prices are volatile. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected crude oil, NGL and natural gas volumes through 2018 by entering into derivative financial instruments including floating for fixed crude oil, NGL and natural gas swaps. With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. See “Recast Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.” The current market conditions may also impact our ability to enter into future commodity derivative contracts. A significant reduction in commodity prices could reduce our operating margins and cash flow from operations.

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

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

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

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

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

As of December 31, 2012, our liquidity of $127.7 million consisted of $8.0million of available cash and $119.7 million of available borrowings under our revolving credit facility and WHT’s revolving credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our revolving credit facilities. As of December 31, 2012, the borrowing base under the Partnership’s revolving credit facility was $460.0 million and outstanding indebtedness under this credit facility was $371.0 million. On March 28, 2013, the Partnership acquired all of the outstanding equity interests in WHT and the borrowing base under the Partnership’s revolving credit facility increased to $580.0 million. Upon the issuance of senior notes in a private offering on April 17, 2013, the borrowing base under the Partnership’s revolving credit facility was reduced to $505.0 million. Upon the issuance of additional senior notes in a private offering on May 23, 2013, the borrowing base under the Partnership’s revolving credit facility was reduced to $480.0 million and outstanding indebtedness under this credit facility was reduced to $39.0 million. As of December 31, 2012, the borrowing base under WHT’s revolving credit facility was $120.0 million with $89.3 million of outstanding borrowings. On March 28, 2013, the debt balance then outstanding under the WHT revolving credit facility and all accrued interest was paid off in full and the credit facility was terminated. The borrowing base under the Partnership’s revolving credit facility is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to 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.

A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands. As of December 31, 2012, we had no letters of credit outstanding.

Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including credit facility borrowings and debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 8 and Note 10 of the Notes to Consolidated and Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Report.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. We believe our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next twelve months. As of December 31, 2012, we had a positive working capital balance of $39.2 million.

Capital Expenditures

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

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

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The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our revolving credit facility will exceed our planned capital expenditures and other cash requirements for 2013. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, generally. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures. See “— Outlook” contained in Part II—Item 7 of our 2012 Form 10-K for additional information regarding our capital spending program.

Revolving Credit Facility—Partnership

OLLC entered into a $1.0 billion multi-year revolving credit facility at the closing of our initial public offering that matures in December 2016 and is guaranteed by us and all of our current and future subsidiaries. The revolving credit facility had an initial borrowing base of $300.0 million. On December 3, 2012, we entered into a third amendment to our credit agreement, which among other things increased the borrowing base to $460.0 million upon closing of the Beta acquisition. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In the future, we may be unable to access sufficient capital under our revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

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

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

Our revolving credit facility requires us to maintain a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense or, for the periods ending on March 31, 2013, June 30, 2013, and September 30, 2013, a ratio of Annualized Consolidated EBITDAX to Annualized Consolidated Net Interest Expense (as each term is defined under our revolving credit facility), which we refer to in either case as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under our revolving credit facility, of not less than 1.0 to 1.0.

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

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

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

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

Revolving Credit Facility – WHT

WHT entered into a $400.0 million multi-year revolving credit facility on April 8, 2011 that was scheduled to mature in April 2016. The revolving credit facility had an initial borrowing base of $230.0 million. On March 28, 2013, the Partnership acquired all of the outstanding equity interests in WHT. In connection with this acquisition, 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 credit facility was terminated.

Commodity Derivative Contracts

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

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

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of December 31, 2012, see “ Recast Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” contained herein.

Interest Rate Derivative Contracts

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. See “Recast Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” contained herein for additional information regarding fixed-for-floating interest rate swap open positions as of December 31, 2012.

Counterparty Exposure

As of December 31, 2012, the fair value of our open derivative contracts was a net receivable of $22.4 million. All of the Partnership’s derivative contracts are with major financial institutions who are also lenders under the Partnership’s revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Recast Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” contained herein for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for each of the years in the two-year period ended December 31, 2012 is presented on a combined basis, consisting of the consolidated financial information of the Partnership and the combined financial information of our predecessor and the previous owners. The cash flows for the twelve months ended December 31, 2010 is presented on a combined basis, consisting of the combined financial information of our predecessor and the previous owners. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated and Combined Cash Flows included under “Recast Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report.

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	For Year Ended December 31,
	2012		2011		2010
	(in thousands)
Net cash provided by operating activities	$	117,900	$	92,435	$	44,729
Net cash used in investing activities		183,223		373,504		143,770
Net cash provided by financing activities		63,689		273,657		110,780

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Operating Activities.Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash flows provided by operating activities increased during 2012 primarily due to an increase in production volumes as a result of properties acquired by the Partnership from third parties in May and September 2012 and the 2011 acquisition activities of both our predecessor and the previous owners. We used cash flows provided by operating activities primarily to fund distributions to our partners and additions to oil and gas properties. Our predecessor and the previous owners primarily used cash flows provided by operating activities to fund its exploration and development expenditures.

Investing Activities. Cash used in investing activities during 2012 was $183.2 million, of which $126.9 million was used to acquire oil and natural gas properties and $51.3 million was used for additions to oil and gas properties. See “— Significant Current Developments” contained in Part I—Item 1 of our 2012 Form 10-K for additional information regarding our acquisitions of oil and natural gas properties from third parties. During 2012, we participated in the drilling and/or completion of 9 new wells in South Texas and East Texas/North Louisiana with a success rate of 100%. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. Additions to restricted investments were $4.6 million. See Note 7 of the Notes to Consolidated and Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report for additional information regarding our restricted investments.

During 2011, our predecessor and the previous owners spent $318.7 million on several acquisitions, the largest of which was the purchase of certain oil and natural gas properties in East Texas from a third party for approximately $302.0 million. An additional $52.2 million was used for additions to oil and gas properties. Our predecessor participated in the drilling of 6 gross wells in 2011 with a success rate of 100%. Acquisition and development expenditures were offset by proceeds from the sale of properties for $3.2 million. Additions to restricted investments associated with the Beta properties were $5.3 million.

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

Distributions to partners for 2012 were $34.4 million, of which Memorial Resource received $19.2 million. We distributed $45.5 million to Memorial Resource in connection with our acquisitions of oil and gas properties from them in April and May 2012. See “— Significant Current Developments” contained in Part I—Item 1 of our 2012 Form 10-K for additional information. The Partnership had net borrowings of $251.0 million that were used primarily to fund the acquisitions of oil and gas properties. WHT made net repayments of $10.6 million under its revolving credit facility. Also during 2012, we incurred loan origination fees of approximately $1.4 million.

On December 14, 2011, the Partnership completed its initial public offering of 9,000,000 common units at a price of $19.00 per unit, which generated net proceeds to the Partnership of approximately $146.5 million after deducting underwriting discounts, structuring fees and other offering and formation-related fees. In connection with our initial public offering, we distributed approximately $73.6 million as partial consideration to Memorial Resource in exchange for the net assets of our predecessor and repaid $198.3 million of our predecessor’s credit facilities concurrent with the closing of our initial public offering. This cash distribution was financed with approximately $130.0 million in borrowings under a new senior secured revolving credit facility and the net cash proceeds generated from our initial public offering. On December 22, 2011, the underwriters exercised a portion of their over-allotment option, purchasing an additional 600,000 common units issued by the Partnership at the initial public offering price, which generated net proceeds to the Partnership of approximately $10.7 million. Of this amount, $10.0 million was used to repay indebtedness under our revolving credit facility. Loan origination fees were $2.5 million related to this revolving credit facility.

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During 2011, our predecessor and the previous owners had net advances of $19.5 million under their revolving credit facilities. Capital contributions of $135.5 million were used to fund the development and property acquisition program of both our predecessor and the previous owners. The previous owners also made distributions of $65.0 million. Loan origination fees incurred by our predecessor and the previous owners were approximately $2.8 million during 2011.

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

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash flows provided by operating activities increased during 2011 primarily due to an increase in production volumes as a result acquisition activities of both our predecessor and the previous owners. Cash flows provided by operating activities were primarily used to fund the exploration and development expenditures of both our predecessor and previous owners.

Investing Activities. During 2011, our predecessor and the previous owners spent $318.7 million on several acquisitions, the largest of which was the purchase of certain oil and natural gas properties in East Texas from a third party for approximately $302.0 million. An additional $52.2 million was used for additions to oil and gas properties. Our predecessor participated in the drilling of 6 gross wells in 2011 with a success rate of 100%. Acquisition and development expenditures were offset by proceeds from the sale of properties for $3.2 million. Additions to restricted investments associated with the Beta properties were $5.3 million.

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

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

Our predecessor and the previous owners had net advances of $19.5 million under their revolving credit facilities during 2011. Our predecessor had net advances of $53.5 million under its revolving credit facilities during 2010. Capital contributions of $135.5 million were used to fund the development and property acquisition program of both our predecessor and the previous owners during 2011. Capital contributions of $62.0 million were used to fund the development and property acquisition program of both our predecessor and the previous owners during 2010. The previous owners made distributions of $65.0 million during 2011 compared to $4.4 million during 2010. Loan origination fees incurred by our predecessor and the previous owners were approximately $2.8 million during 2011 compared to $1.6 million during 2010.

Capital Requirements

See “— Outlook” continued in Part II — Item 7 of our 2012 Form 10-K for additional information regarding our capital spending program for 2013.

In 2013, we intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4750 per unit per quarter on all common, subordinated and general partner units ($1.90 per unit on an annualized basis). On February 13, 2013, we paid a $17.4 million cash distribution for the fourth quarter 2012 to our unitholders and our general partner. This distribution represented an annualized amount of $2.03 per unit. Assuming no further changes in the distribution rate and the number of common units, subordinated units and general partner units currently outstanding, the aggregate distribution paid to all of our unitholders in 2013 would total approximately $69.7 million.

We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisition of oil and natural gas properties in 2013 through a combination of cash from operations, borrowings under our revolving credit facility and the issuance of equity or debt securities.

Contractual Obligations

Our contractual obligations are limited in scope because Memorial Resource provides management, administrative and operating services to us under an omnibus agreement as discussed under “Item 13. Certain Relationships and Related Transactions, and Director Independence — Related Party Agreements — Omnibus Agreement” contained in our 2012 Form 10-K. In the table below, we set forth our contractual obligations as of December 31, 2012. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

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	Payments Due by Period (in thousands)
Contractual Obligations	Total		2013		2014 - 2015		2016 - 2017		Beyond 2017
Revolving credit facility (1)	$	460,300	$	—	$	—	$	460,300	$	—
Estimated interest payments (2)		57,895		13,999		28,080		15,816		—
Asset retirement obligations (3)		78,286		—		926		2,014		75,346
Decommissioning Trust Agreement (4)		16,560		4,140		8,280		4,140		—
Operating leases (5)		3,835		475		925		531		1,904
Compression services		3,711		3,324		387		—		—
Drilling services		2,768		2,768		—		—		—
Total	$	623,355	$	24,706	$	35,598	$	482,801	$	77,250

(1) Represents the scheduled future maturities of principal amounts outstanding for the periods indicated. See Note 8 of the Notes to Consolidated and Combined Financial Statements included under Recast Item 8 contained under Exhibit 99.2 of this Current Report for information regarding our revolving credit facilities.

(2) Estimated interest payments are based on the principal amount outstanding under our revolving credit facilities at December 31, 2012. In calculating these amounts, we applied the weighted-average interest rate during 2012 associated with such debt. See Note 8 of the Notes to Consolidated and Combined Financial Statements included under Recast Item 8 contained under Exhibit 99.2 of this Current Report for the weighted-average variable interest rate charged during 2012 under these credit facilities. In addition, our estimate of payments for interest gives effect to interest rate swap agreements that were in place at December 31, 2012.

(3) Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2012 balance sheet. See Note 6 of the Notes to Consolidated and Combined Financial Statements included under Recast Item 8 contained under Exhibit 99.2 of this Current Report for additional information regarding our asset retirement obligations.

(4) Pursuant to a BOEM decommissioning trust agreement, we are required to fund a trust account to comply with supplemental regulatory bonding requirements related to our decommissioning obligations for our offshore Southern California production facilities. See Note 14 of the Notes to Consolidated and Combined Financial Statements included under Recast Item 8 contained under Exhibit 99.2 of this Current Report for additional information.

(5) Primarily represents leases for offshore Southern California right-of-way use and office space. See Note 14 of the Notes to Consolidated and Combined Financial Statements included under Recast Item 8 contained under Exhibit 99.2 of this Current Report for information regarding our operating leases.

Off–Balance Sheet Arrangements

As of December 31, 2012, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Consolidated and Combined Financial Statements included under Recast Item 8 contained under Exhibit 99.2 of this Current Report.

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RECAST ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

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

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

Basis Swaps. These instruments are arrangements that guarantee a price differential to 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.

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The following table summarizes our derivative contracts as of December 31, 2012 and the average prices at which the production will be hedged:

	2013			2014			2015		2016		2017		2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		857,672			1,252,125			1,156,112		1,113,275		1,020,067		900,000
Weighted-average fixed price	$	4.30		$	4.34		$	4.28	$	4.53	$	4.30	$	4.75
Collar contracts:
Average Monthly Volume (MMBtu)		855,000			300,000			200,000		—		—		—
Weighted-average floor price	$	4.81		$	5.08		$	5.25	$	—	$	—	$	—
Weighted-average ceiling price	$	5.87		$	6.31		$	6.75	$	—	$	—	$	—
Call spreads (1):
Average Monthly Volume (MMBtu)		430,000			120,000			80,000		—		—		—
Weighted-average sold strike price	$	4.59		$	5.08		$	5.25	$	—	$	—	$	—
Weighted-average bought strike price	$	5.84		$	6.31		$	6.75	$	—	$	—	$	—
Basis swaps:
Average Monthly Volume (MMBtu)		813,432			1,318,750			—		—		—		—
Spread	$	(0.11	)	$	(0.09	)	$	—	$	—	$	—	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		49,623			20,102			12,031		11,013		10,000		—
Weighted-average fixed price	$	106.79		$	94.06		$	90.29	$	90.39	$	88.30	$	—
Collar contracts:
Average Monthly Volume (Bbls)		10,750			43,958			45,000		44,000		42,000		—
Weighted-average floor price	$	88.74		$	94.43		$	90.00	$	85.00	$	85.00	$	—
Weighted-average ceiling price	$	118.33		$	109.87		$	104.34	$	103.40	$	99.00	$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		30,805			16,300			—		—		—		—
Weighted-average fixed price	$	53.19		$	58.91		$	—	$	—	$	—	$	—

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

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

	2012			2013			2014		2015		2016
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		357,498			451,052			772,740		781,578		865,165
Weighted-average fixed price	$	5.09		$	4.67		$	4.44	$	4.44	$	4.70
Collar contracts:
Average Monthly Volume (MMBtu)		964,500			854,000			300,000		200,000		—
Weighted-average floor price	$	4.53		$	4.81		$	5.08	$	5.25	$	—
Weighted-average ceiling price	$	5.82		$	5.87		$	6.31	$	6.75	$	—
Put options:
Average Monthly Volume (MMBtu)		70,000			—			—		—		—
Weighted-average strike price	$	4.80		$	—		$	—	$	—	$	—
Basis swaps:
Average Monthly Volume (MMBtu)		353,633			405,932			—		—		—
Spread	$	(0.14	)	$	(0.16	)	$	—	$	—	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		1,790			1,540			2,250		—		—
Weighted-average fixed price	$	92.00		$	92.00		$	87.90	$	—	$	—
Collar contracts:
Average Monthly Volume (Bbls)		49,900			40,750			8,000		—		—
Weighted-average floor price	$	79.68		$	92.12		$	90.00	$	—	$	—
Weighted-average ceiling price	$	106.15		$	115.77		$	117.72	$	—	$	—
NGL Derivative Contracts:
Collar contracts:
Average Monthly Volume (Bbls)		9,500			—			—		—		—
Weighted-average floor price	$	75.16		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	93.57		$	—		$	—	$	—	$	—

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

Interest Rate Risk

At December 31, 2012, we had $371.0 million of debt outstanding under our revolving credit facility, with a weighted average interest rate of LIBOR plus 2.50%, or 2.72%. Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At December 31, 2012, WHT also had $89.3 million of variable rate debt outstanding under its revolving credit facility. 

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

Period Covered		Notional ($ in  thousands)		Floating Rate		Fixed Rate
1/17/2012	1/17/2013	$	100,000		1 Month LIBOR		0.600	%
1/17/2013	12/14/2016	$	100,000		1 Month LIBOR		1.305	%
5/17/2012	1/17/2013	$	50,000		1 Month LIBOR		0.600	%
1/17/2013	12/14/2016	$	50,000		1 Month LIBOR		0.970	%
4/14/2011	4/14/2014	$	50,000		1 Month LIBOR		1.510	%
4/18/2011	4/18/2014	$	25,000		1 Month LIBOR		1.510	%

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

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

Period Covered		Notional ($ in  thousands)		Floating Rate		Fixed Rate
1/17/2012	1/17/2013	$	100,000		1 Month LIBOR		0.600	%
1/17/2013	12/14/2016	$	100,000		1 Month LIBOR		1.305	%
4/14/2011	4/14/2014	$	50,000		1 Month LIBOR		1.510	%
4/18/2011	4/18/2014	$	25,000		1 Month LIBOR		1.510	%

Counterparty and Customer Credit Risk

Joint interest billings receivable represent amounts receivable for lease operating expenses and other costs due from third party working interest owners in the wells that the Partnership operates. The receivable is recognized when the cost is incurred. We have limited ability to control participation in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. Each of the counterparties to our derivative contracts is a lender in our credit agreement. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $20.0 million against amounts outstanding under our revolving credit facility at December 31, 2012.

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

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