Amplify Energy 8K Memorial Production Partners LP | AMPYW 21 Apr 15

Exhibit 99.1

MEMORIAL PRODUCTION PARTNERS LP

RECAST OF CERTAIN SECTIONS OF THE 2014 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

		Page
	PART I
	Glossary of Oil and Natural Gas Terms	1
Recast Item 6.	Selected Financial Data	5
Recast Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	7

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.

BOEM: Bureau of Ocean Energy Management.

BSEE: Bureau of Safety and Environmental Enforcement.

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

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

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

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

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

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

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

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

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

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

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

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

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

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

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

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

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

OPIS: Oil Price Information Service.

Play: A geographic area with hydrocarbon potential.

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

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

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

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

Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to reflect property acquisitions and dispositions.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

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

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

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

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

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

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

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

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

WTI: West Texas Intermediate.

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, 2014, 2013, 2012, 2011 and 2010 have been derived from our consolidated financial statements and our predecessor and/or the previous owners’ combined financial statements. The combined financial statements of our predecessor are those of BlueStone and the Classic Carve-Out through December 13, 2011 and the WHT Assets for periods after April 8, 2011 through December 13, 2011. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, the consolidated financial statements of REO from February 3, 2009 (inception) through December 11, 2012, the Cinco Group from inception through October 1, 2013 and the Property Swap for periods after common control commenced through the date of acquisition. 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:

·	The acquisition of interests in certain oil and gas properties in Southwestern Wyoming for approximately $62.9 million in January 2010;

·	The acquisition of interests in certain oil and gas properties in South Texas for approximately $65.9 million in June 2010;

·	Two separate acquisitions of assets in East Texas in January and March 2010, respectively, for a net purchase price of approximately $27.0 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 third party oil and gas producer for a net purchase price of approximately $66.5 million;

·	The acquisition of assets in East Texas in January 2011 from a third party for a purchase price of approximately $12.5 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 in East Texas from a third party in April 2011 for a total purchase price of approximately $302.0 million;

Multiple acquisitions of operating and non-operating interests in certain oil and natural gas properties located primarily in the Permian Basin and offshore Louisiana completed by the previous owners during 2011 for an aggregate purchase price of $85.8 million, including the 2012 divestiture of the offshore Louisiana properties;

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

·	The acquisition of working interests, royalty interests and net revenue interests located in the Permian Basin from a third party in July 2012 for a net purchase price of approximately $74.7 million;

·	Multiple acquisitions of operating and non-operating interests in certain oil and natural gas properties throughout 2012 primarily located in the Permian Basin for an aggregate net purchase price of $75.9 million;

·	The acquisition of certain oil and natural gas liquids properties in Wyoming from a third party in July 2014 for a total purchase price of approximately $906.1 million; and

·	The acquisition of certain oil and natural gas producing properties the Eagle Ford from a third party in March 2014 for a total purchase price of approximately $168.1 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.

	For Year Ended December 31,
	2014			2013			2012			2011			2010
	($ in thousands, except per unit data)
Statement of Operations Data:										(Unaudited)			(Unaudited)
Revenues:
Oil & natural gas sales	$	531,853		$	370,062		$	289,912		$	270,923		$	131,015
Pipeline tariff income and other		4,366			3,075			3,253			3,463			3,394
Total revenues		536,219			373,137			293,165			274,386			134,409

Costs and expenses:
Lease operating		143,733			96,433			87,972			72,191			42,031
Pipeline operating		2,068			1,835			2,114			2,526			1,896
Exploration		2,750			1,322			9,340			1,126			246
Production and ad valorem taxes		33,141			18,447			15,354			13,532			5,984
Depreciation, depletion, and amortization		185,955			113,814			101,624			84,420			47,219
Impairment of proved oil and natural gas properties		407,540			4,072			22,994			29,356			11,838
General and administrative		49,124			54,947			35,112			31,101			18,112
Accretion of asset retirement obligations		5,773			4,988			4,458			4,121			3,202
(Gain) loss on commodity derivative instruments		(492,254	)		(26,133	)		(24,405	)		(71,748	)		(18,239	)
Gain on sale of properties		—			(2,848	)		(9,759	)		(63,033	)		(239	)
Other, net		(11	)		647			38			1,988			860
Total costs and expenses		337,819			267,524			244,842			105,580			112,910
Operating income		198,400			105,613			48,323			168,806			21,499
Other income (expense):
Interest expense, net		(83,550	)		(44,302	)		(24,955	)		(19,323	)		(6,751	)
Other income (expense)		(657	)		2			1			9			—
Amortization of investment premium		—			—			(194	)		(606	)		(907	)
Total other income (expense)		(84,207	)		(44,300	)		(25,148	)		(19,920	)		(7,658	)
Income (loss) before income taxes		114,193			61,313			23,175			148,886			13,841
Income tax benefit (expense)		1,421			(308	)		(108	)		(928	)		(932	)
Net income		115,614			61,005			23,067			147,958			12,909
Net income (loss) attributable to noncontrolling interest		32			267			104			(146	)		(8	)
Net income attributable to Memorial Production Partners LP	$	115,582		$	60,738		$	22,963		$	148,104		$	12,917

Limited partners’ interest in net income:
Net income (loss) attributable to Memorial Production Partners LP	$	115,582		$	60,738		$	22,963		$	148,104		$	12,917
Net (income) loss allocated to predecessor		—			—			—			(75,740	)		11,317
Net (income) loss allocated to previous owners		2,465			(52,012	)		(22,842	)		(65,772	)		(24,234	)
Net (income) loss allocated to general partner		(206	)		(49	)		—			(7	)		—
Net (income) loss allocated to NGP IDRs		(88	)		—			—			—			—
Limited partners’ interest in net income	$	117,753		$	8,677		$	121		$	6,585		$	—

Earnings per unit attributable to limited partners:
Basic and diluted earnings per unit	$	1.66		$	0.19		$	0.01		n/a			n/a
Supplemental basic and diluted EPU (1)	$	1.63		$	1.32		$	1.00		n/a			n/a

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

Cash Flow Data:										(Unaudited)			(Unaudited)
Net cash flow provided by operating activities	$	254,273		$	201,703		$	183,983		$	121,695		$	63,163
Net cash used in investing activities		1,386,109			214,559			417,831			460,784			196,476
Net cash provided by financing activities		1,111,108			5,969			237,233			335,754			143,288

Balance Sheet Data:										(Unaudited)			(Unaudited)
Working capital (deficit)	$	152,715		$	(1,385	)	$	64,662		$	39,539		$	28,453
Total assets		3,189,760			1,849,368			1,737,862			1,522,290			859,477
Total debt		1,595,413			792,067			710,182			440,501			262,901
Total equity		1,296,314			863,021			864,863			891,483			465,610

(1)	See Note 10 of the Notes to Supplemental Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data for more information.

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 on Form 8-K, which we refer to as 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 2014 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 2014 Form 10-K.

Overview

We are a Delaware limited partnership focused on the ownership, acquisition and development of oil and natural gas properties in North America. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming, New Mexico and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. As of December 31, 2014:

·	Our total estimated proved reserves were approximately 1,683 Bcfe, of which approximately 43% were natural gas and 58% were classified as proved developed reserves;

·	We produced from 3,568 gross (2,087 net) producing wells across our properties, with an average working interest of 58%, and the Partnership or Memorial Resource is the operator of record of the properties containing 94% of our total estimated proved reserves; and

·	Our average net production for the three months ended December 31, 2014 was 251 MMcfe/d, implying a reserve-to-production ratio of approximately 18 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.

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, realized prices are heavily influenced by product quality and location relative to consuming and refining markets.

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

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

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

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

The oil produced from our onshore properties is a combination of sweet and sour oil, varying by location. This oil is typically sold at the NYMEX-WTI price, which is adjusted for quality and transportation differential, depending primarily on location and purchaser. The oil produced from our Beta properties is sour oil. Volumes produced from our Beta properties are currently based on refiners’ posted prices for California Midway-Sunset deliveries in Southern California, which is adjusted primarily for quality and a negotiated market differential. Since 2010, production from our Beta properties has more closely tracked the ICE Brent price, and we have been able to successfully hedge this production through an ICE Brent priced hedge with a corresponding Midway-Sunset basis hedge through 2016.

Price Volatility. In the past, and particularly in the second half of 2014 and the beginning of 2015, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. The following table shows the low and high commodity future index prices for the periods indicated:

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

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

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

Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, compression, water injection and disposal, the cost of CO₂ injection and materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed.

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

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

Production Taxes and Ad Valorem Taxes

Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties or, in the case of Wyoming, the gross products for production. Valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

General and Administrative Expenses

We and our general partner are parties to an omnibus agreement with a wholly-owned subsidiary of Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. During the year ended December 31, 2012, Memorial Resource allocated its general and administrative costs based on the relative size of our proved and probable reserves in comparison to Memorial Resource’s proved and probable reserves. In January 2013, Memorial Resource began to allocate its general and administrative costs based on our relative production in comparison to Memorial Resource’s production. During 2014, Memorial Resource began to allocate its direct general and administrative costs based on estimated time spent on each entity, which it believes 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.”

Adjusted EBITDA

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

Plus:

·	Interest expense, including gains and 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”);

·	Loss on commodity derivative instruments;

·	Cash settlements received on commodity derivative instruments;

·	Losses on sale of assets and other, net;

·	Unit-based compensation expenses;

·	Exploration costs;

·	Acquisition related costs;

·	Amortization of investment premium; and

·	Other non-routine items that we deem appropriate.

Less:

·	Interest income;

·	Income tax benefit;

·	Gain on commodity derivative instruments;

·	Cash settlements paid on commodity derivative instruments;

·	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.

Calculation of Adjusted EBITDA

	For the Twelve Months Ended
	December 31,
	2014			2013			2012
Net income (loss)	$	115,614		$	61,005		$	23,067
Interest expense, net		83,550			44,302			24,955
Income tax expense (benefit)		(1,421	)		308			108
DD&A		185,955			113,814			101,624
Impairment of proved oil and gas properties		407,540			4,072			22,994
Accretion of AROs		5,773			4,988			4,458
(Gains) losses on commodity derivative instruments		(492,254	)		(26,133	)		(24,405	)
Cash settlements received (paid) on commodity derivative instruments		13,522			23,638			53,559
(Gain) loss on sale of properties		—			(2,848	)		(9,759	)
Acquisition related costs		4,363			6,729			4,135
Unit-based compensation expense		7,874			3,558			1,423
Non-cash compensation expense		—			1,057			—
Exploration costs		2,750			1,322			9,340
Non-cash loss on office lease		1,442			—			—
Amortization of investment premium		—			—			194
Provision for environmental remediation		2,852			—			—
Adjusted EBITDA	$	337,560		$	235,812		$	211,693

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

	For the Twelve Months Ended
	December 31,
	2014			2013			2012
Net cash provided by operating activities	$	254,273		$	201,703		$	183,983
Changes in working capital		(5,669	)		(13,448	)		1,238
Interest expense, net		83,550			44,302			24,955
Premiums paid for derivatives		—			—			411
Gain (loss) on interest rate swaps		151			548			(4,839	)
Cash settlements paid on interest rate derivative instruments		1,829			960			1,804
Amortization of deferred financing fees		(4,227	)		(6,013	)		(2,706	)
Accretion of senior notes discount		(1,921	)		(504	)		—
Acquisition related expenses		4,363			6,729			4,135
Income tax expense - current portion		127			308			285
Exploration costs		790			1,227			2,427
Non-cash loss on office lease		1,442			—			—
Provision for environmental remediation		2,852			—			—
Adjusted EBITDA	$	337,560		$	235,812		$	211,693

Outlook

In 2015, we plan to maintain our focus on adding reserves through acquisitions and development projects and improving the economics of producing oil and natural gas from our properties. We expect acquisition opportunities may come from Memorial Resource, the Funds, and their respective affiliates, as well as from unrelated third parties. Our ability to add reserves through acquisitions and development projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

In 2015, excluding potential acquisitions, we anticipate spending approximately 74% of our capital budget in East Texas, 11% in the Rockies, 7% in California and the balance in South Texas and the Permian Basin focused primarily on drilling, on-site maintenance, recompletions and capital workovers.

Oil prices declined significantly in the second half of 2014 and have continued to drop in early 2015. This decline in oil prices stems in large part from decreased demand due to weak economic activity and increased efficiency, an excess of supply due to sustained high output from North America, and the Organization of Petroleum Exporting Countries’ failure to reach agreement on production curbs in November 2014. The continuation of low prices for oil or natural gas could

materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Although we cannot predict the occurrence of events or factors that will affect future commodity prices, such as the supply of, and demand for, oil, natural gas, and NGLs, and general domestic or foreign economic conditions and political developments, or the degree to which these prices will be affected, the prices for any oil, natural gas or NGLs that we produce will generally approximate market prices in the geographic region of the production.

The U.S. Energy Information Administration, or EIA, forecasts that Brent crude oil prices will average $58 per Bbl in 2015 and $75 per Bbl in 2016. North Sea Brent crude oil spot prices averaged $62 per Bbl in December 2014, the lowest monthly average Brent price since May 2009, down $17 per Bbl from the November average. The combination of robust world crude oil supply growth and weak global demand has contributed to rising global inventories and falling crude oil prices. EIA expects global oil inventories to continue to build in 2015, keeping downward pressure on oil prices. Like Brent crude oil prices, WTI prices have decreased considerably, with monthly average prices falling by more than 44% as of December 2014 after reaching their 2014 peak of $106 per Bbl in June. EIA expects WTI crude oil prices to average $55 per Bbl in 2015 and $71 per Bbl in 2016.

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

Commodity hedging remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of our 2014 Form 10-K for additional information.

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. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

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

Proved Oil and Natural Gas Reserves

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

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment.

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, 2014 or 2013.

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.

Results of Operations

The results of operations for the years ended December 31, 2014, 2013, and 2012 have been derived from both our consolidated financial statements and our previous owners’ combined financial statements. The previous owners combined financial statements reflect: (i) the Tanos/Classic Properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective date of acquisition on a combined basis, (ii) the consolidated financial statements of REO for periods after common control commenced through the date of acquisition, (iii) the WHT Properties from February 2, 2011 (inception) through the date of acquisition, (iv) the financial statements of the Cinco Group on a combined basis for periods after common control commenced through the date of acquisition, and (v) certain oil and gas properties primarily located in East Texas and West Louisiana acquired from Memorial Resource in February 2015 for periods after common control commenced through the date of acquisition. The results of operations

attributable to the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods.

Factors Affecting the Comparability of the Combined Historical Financial Results

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

·	The 2012 divestiture of the offshore Louisiana properties by the previous owners.

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

·	The acquisition of working interests, royalty interests and net revenue interests located in the Permian Basin from a third party in July 2012 for a net purchase price of approximately $74.7 million.

·	Multiple acquisitions of operating and non-operating interests in certain oil and natural gas properties throughout 2012 primarily located in the Permian Basin for an aggregate net purchase price of $75.9 million.

·	The acquisition of certain oil and natural gas liquids properties in Wyoming from a third party in July 2014 for a purchase price of approximately $906.1 million.

·	The acquisition of certain oil and natural gas producing properties the Eagle Ford from a third party in March 2014 for a total purchase price of approximately $168.1 million.

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

	For the Twelve Months Ended
	December 31,
	2014			2013			2012
Revenues:
Oil & natural gas sales	$	531,853		$	370,062		$	289,912
Pipeline tariff income and other		4,366			3,075			3,253
Total revenues		536,219			373,137			293,165

Costs and expenses:
Lease operating		143,733			96,433			87,972
Pipeline operating		2,068			1,835			2,114
Exploration		2,750			1,322			9,340
Production and ad valorem taxes		33,141			18,447			15,354
Depreciation, depletion, and amortization		185,955			113,814			101,624
Impairment of proved oil and natural gas properties		407,540			4,072			22,994
General and administrative		49,124			54,947			35,112
Accretion of asset retirement obligations		5,773			4,988			4,458
(Gain) loss on commodity derivative instruments		(492,254	)		(26,133	)		(24,405	)
(Gain) loss on sale of properties		—			(2,848	)		(9,759	)
Other, net		(11	)		647			38
Total costs and expenses		337,819			267,524			244,842
Operating income (loss)		198,400			105,613			48,323
Other income (expense):
Interest expense, net		(83,550	)		(44,302	)		(24,955	)
Other income (expense)		(657	)		2			1
Amortization of investment premium		—			—			(194	)
Total other income (expense)		(84,207	)		(44,300	)		(25,148	)
Income before income taxes		114,193			61,313			23,175
Income tax benefit (expense)		1,421			(308	)		(108	)
Net income (loss)		115,614			61,005			23,067
Net income (loss) attributable to noncontrolling interest		32			267			104
Net income (loss) attributable to Memorial Production Partners LP	$	115,582		$	60,738		$	22,963

Oil and natural gas revenue:
Oil sales	$	266,216		$	174,296		$	149,381
NGL sales		74,003			56,551			29,972
Natural gas sales		191,634			139,215			110,559
Total oil and natural gas revenue	$	531,853		$	370,062		$	289,912

Production volumes:
Oil (MBbls)		3,135			1,797			1,565
NGLs (MBbls)		2,498			1,806			830
Natural gas (MMcf)		48,721			41,287			38,130
Total (MMcfe)		82,520			62,907			52,503
Average net production (MMcfe/d)		226.0			172.3			143.5

Average sales price:
Oil (per Bbl)	$	84.92		$	96.99		$	95.45
NGL (per Bbl)		29.62			31.31			36.11
Natural gas (per Mcf)		3.93			3.37			2.90
Total (Mcfe)	$	6.45		$	5.88		$	5.52

Average unit costs per Mcfe:
Lease operating expense	$	1.74		$	1.53		$	1.68
Production and ad valorem taxes	$	0.40		$	0.29		$	0.29
General and administrative expenses	$	0.60		$	0.87		$	0.67
Depletion, depreciation, and amortization	$	2.25		$	1.81		$	1.94

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Net income of $115.6 million was generated for the year ended December 31, 2014, primarily due to significant gains on commodity derivatives which were mostly offset by impairment charges. Net income was $61.0 million for the year ended December 31, 2013, of which $52.0 million was attributable to the previous owners.

Revenues. Oil, natural gas and NGL revenues for the year ended December 31, 2014 totaled $531.9 million, an increase of $161.8 million compared with the year ended December 31, 2013. Production increased 19.6 Bcfe (approximately 31%), primarily from volumes associated with third party acquisitions. The average realized sales price increased $0.57 per Mcfe primarily due to an increase in oil volumes relative to other commodities related to our acquisitions in 2014. The favorable volume and pricing variance contributed to an approximate $115.4 million and $46.4 million increase in revenues, respectively.

Lease Operating. Lease operating expenses were $143.7 million and $96.4 million for the year ended December 31, 2014 and 2013, respectively. In our Wyoming Acquisition, we acquired more oil weighted properties which are generally more expensive to operate compared to natural gas properties (on a per Mcfe basis). On a per Mcfe basis, lease operating expenses increased to $1.74 for 2014 from $1.53 for 2013 due to 2014 oil acquisitions.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the year ended December 31, 2014 totaled $33.1 million, an increase of $14.7 million compared with the year ended December 31, 2013 primarily due to an increase in production volumes and ad valorem tax rates. On a per Mcfe basis, production and ad valorem taxes increased to $0.40 per Mcfe for the year ended December 31, 2014 from $0.29 per Mcfe for the year ended December 31, 2013 due to higher production tax rates on a per Mcfe basis for production from our new Wyoming properties.

Depreciation, Depletion and Amortization. DD&A expense for the year ended December 31, 2014 was $186.0 million compared to $113.8 million for the year ended December 31, 2013, a $72.2 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and the Partnership’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $35.5 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $36.7 million.

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

General and Administrative. General and administrative expenses for the year ended December 31, 2014 were $49.1 million. General and administrative expenses for the year ended December 31, 2014 included $7.9 million of non-cash unit-based compensation expense, $4.4 million of acquisition-related costs and a $1.8 million allocated loss on a previous corporate office lease. General and administrative expenses for the year ended December 31, 2013 totaled $54.9 million, of which $26.2 million was attributable to the previous owners. General and administrative expenses for 2013 included $3.6 million of non-cash unit-based compensation expense and $6.7 million of acquisition-related costs. The $5.8 million decrease in general and administrative expenses consisted of $5.8 million of one-time compensation expense related to the Tanos management buyout and approximately $8.3 million of one-time compensation expense related to the Classic management buyout during the year ended December 31, 2013 offset by increased salaries and employee count between periods.

Gain/Loss on Commodity Derivative Instruments. Net gains on commodity derivative instruments of $492.3 million were recognized during the year ended December 31, 2014, consisting of $13.6 million of cash settlements received in addition to a $478.7 million increase in the fair value of open positions. Net gains on commodity derivative instruments of $26.1 million were recognized during 2013, of which $23.6 million consisted of cash settlements received.

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

Interest Expense, Net. Interest expense, net totaled $83.6 million during the year ended December 31, 2014, including amortization of deferred financing fees of approximately $4.2 million and accretion of net discount associated with our senior notes of $1.9 million. Interest expense, net totaled $44.3 million during the year ended December 31, 2013, including gains on interest rate swaps of approximately $1.5 million, amortization of deferred financing fees of approximately $6.0 million

(including write-offs associated with the previous owner’s revolving credit facility at the time their debt was repaid and terminated in March 2013) and accretion of net discount associated with our senior notes of $0.5 million. The $39.2 million increase in interest expense is primarily due to a higher aggregate principal amount of our senior notes issued and outstanding for the year ended December 31, 2014 compared to the year ended December 31, 2013. During the year ended December 31, 2014, interest of $3.0 million was capitalized and included in our capital expenditures.

Average outstanding borrowings under the Partnership’s revolving credit facility were $413.6 million during the year ended December 31, 2014 compared to $184.7 million during the year ended December 31, 2013. Average outstanding borrowings under the previous owners’ revolving credit facilities were $101.3 million during the year ended December 31, 2013, which included $80.0 million in borrowings related to Classic. For the year ended December 31, 2014, the Partnership had an average of $950.7 million aggregate principal amount of our senior notes issued and outstanding. For the year ended December 31, 2013, the Partnership had an average of $342.2 million aggregate principal amount of our senior notes issued and outstanding.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Net income was $61.0 million for the year ended December 31, 2013, of which $52.0 million was attributable to the previous owners. Net income was $23.1 million for the year ended December 31, 2012, of which $22.8 million was attributable to the previous owners.

Revenues. Oil, natural gas and NGL revenues for 2013 totaled $370.1 million, an increase of $80.2 million compared with 2012. Production increased 10.4 Bcfe (approximately 20%) and the average realized sales price increased $0.36 per Mcfe. The favorable volume and pricing variance contributed to an approximately $57.5 million and $22.7 million increase in revenues, respectively.

Lease Operating. Lease operating expenses for 2013 were $96.4 million compared to $88.0 million for 2012, an $8.4 million year-to-year increase. Lease operating expenses increased primarily due to costs associated with properties acquired during 2012 and increased drilling activities. On a per Mcfe basis, lease operating expenses decreased to $1.53 for 2013 from $1.68 for 2012.

Production and Ad Valorem Taxes. Production and ad valorem taxes for 2013 totaled $18.4 million, an increase of $3.0 million compared with 2012. The increase was largely due to an $8.4 million increase in production taxes primarily due to increased production levels. Ad valorem taxes are property taxes generally assessed and levied at the local level. Production taxes imposed at the state level are usually based on either volume or revenue. There is no production and ad valorem tax assessed for our Beta properties. On a per Mcfe basis, production and ad valorem taxes remained relatively flat at approximately $0.29 per Mcfe for each of the years ended December 31, 2013 and 2012.

Depreciation, Depletion and Amortization. DD&A expense for 2013 was $113.8 million compared to $101.6 million for 2012, a $12.2 million year-to-year increase primarily due to increased production volumes related to acquisitions in 2012 and 2013 as well as results from drilling. DD&A expense per Mcfe was $1.81 for 2013 compared to $1.94 for 2012. Increased production volumes caused DD&A expense to increase by approximately $20.2 million, while the 7% change in the DD&A rate between periods caused DD&A expense to decrease by $8.0 million. An increase in proved reserve volumes more than offset the impact of increases to the depletable cost base.

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

Impairment of Proved Oil and Natural Gas Properties. During 2013, we recorded $4.1 million of impairments related to certain properties in South Texas. For the South Texas properties, a downward revision of estimated proved reserves based on pricing terms specific to these properties triggered the impairment. During 2012, we recorded impairments of $23.0 million related to proved oil and natural gas properties which were a part of the Cinco Group of assets and certain oil and natural gas properties in East Texas. The $10.5 million of impairments related to the Cinco Group assets were a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area. The $12.5 million of impairments related to the East Texas properties were a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties.

General and Administrative. General and administrative expenses for 2013 were $54.9 million, of which $26.2 million was attributable to the previous owners. Tanos recorded $5.8 million of general and administrative expenses related to a management buyout. Classic also recorded approximately $8.3 million of general and administrative expenses related to the Classic management buyout. General and administrative expenses for 2013 included $3.6 million of non-cash unit-based

compensation expense and $6.7 million of acquisition-related costs. General and administrative expenses for 2012 were $35.1 million, of which $23.8 million was attributable to the previous owners. General and administrative expenses for 2012 included $1.4 million of non-cash unit-based compensation expense and $4.1 million of acquisition-related costs.

Gain/Loss on Commodity Derivative Instruments. Net gains on commodity derivative instruments of $26.1 million were recognized during 2013, of which $23.6 million consisted of cash settlements received. Net gains on commodity derivative instruments of $24.4 million were recognized during 2012, of which $53.6 million consisted of cash settlements received.

Gain on Sale of Properties. Our previous owners recognized a net gain on the sale of properties of $2.8 million during 2013. This gain was primarily related to the sale of a natural gas gathering pipeline and certain non-operated oil and gas properties in East Texas. For more information, see Note 3 of the Notes to Supplemental Consolidated and Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Report. The Cinco Group recognized a net gain on sale of properties of $9.8 million during 2012. In July 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. In September 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Ector County, Texas to third party for $4.7 million and recognized a gain of approximately $2.2 million.

Interest Expense. Net interest expense totaled $44.3 million during 2013, including gains on interest rate swaps of approximately $1.5 million and amortization of deferred financing fees of approximately $6.0 million. Net interest expense totaled $25.0 million during 2012, of which $10.4 million was attributable to the Partnership’s revolving credit facility, including losses on interest rate swaps of approximately $4.0 million and amortization of deferred financing fees of approximately $0.6 million.

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. Any volatility in the debt markets would likely increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

Crude oil, NGL and natural gas prices are volatile. In an effort to reduce the variability of our cash flows, we have hedged the commodity prices associated with a portion of our expected crude oil, NGL and natural gas volumes through 2019 by entering into derivative financial instruments including floating for fixed crude oil, NGL and natural gas swaps. With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” of our 2014 Form 10-K. The current market conditions may also impact our ability to enter into future commodity derivative contracts. A significant reduction in commodity prices could reduce our operating margins and cash flow from operations.

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

We may borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. In addition, we hedge a significant portion of our production. We generally are required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and natural gas industry, we do not generally receive the proceeds from the sale of our hedged production until 30 to 45 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, we are required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions. Because we will distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production and as a result, we may not grow as quickly as other oil and natural gas entities or at all.

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Some of the lenders, or certain of their affiliates, under our revolving credit facility are counterparties to our derivative contracts. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could result in losses.

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

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

As of February 23, 2015, our liquidity of $843.0 million consisted of $1.0 million of cash and cash equivalents and $842.0 million of available borrowings under our revolving credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we monitor events and circumstances surrounding each of the lenders in our revolving credit facility. As of December 31, 2014, the borrowing base under our revolving credit facility was $1.44 billion and we had $412.0 million of outstanding borrowings. The borrowing base under our revolving credit facility is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. A continuing decline in oil and natural gas prices or a prolonged period of lower oil and natural gas prices could result in a reduction of our borrowing base under our revolving credit facility and could trigger mandatory principal repayments.

A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands. As of December 31, 2014, we had letters of credit with an outstanding aggregate amount of approximately $6.7 million.

Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including credit facility borrowings and debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 8 and Note 9 of the Notes to Supplemental 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, 2014, we had a working capital balance of $152.7 million, which includes a $205.3 million net asset derivative position.

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.

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our revolving credit facility will exceed our planned capital expenditures and other cash requirements for 2015. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, generally. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures. See “— Outlook” for additional information regarding our capital spending program.

Revolving Credit Facility

OLLC is party to a $2.0 billion revolving credit facility, with a current borrowing base of $1.44 billion, that matures in March 2018 and is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). As of December 31, 2014, we had $412.0 million of outstanding borrowings and $6.7 million of outstanding letters of credit under our revolving credit facility. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts; however, we may seek an interim redetermination if the need arises. 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 an unfavorable borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

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

Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our other assets including personal property.

Borrowings under our revolving credit facility bear interest, at our option, at either: (i) the Alternate Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100^th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index Rate plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

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

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

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

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

As of December 31, 2014, we believe we were in compliance with all of the financial and other covenants under our revolving credit facility.

2022 Senior Notes

In January 2015, we repurchased a principal amount of approximately $3.0 million at an average price of 83.000% of the face value of the 2022 Senior Notes. We used available cash and funds under our revolving credit facility to pay for these repurchases. See “—2014 Developments” under “Item 1. Business” of our 2014 Form 10-K for additional information regarding the issuance of the 2022 Senior Notes.

2021 Senior Notes

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

For information regarding the 2021 Senior Notes and 2022 Senior Notes, see Note 8 of the Notes to Supplemental Consolidated and Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report.

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, 2014, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” of our 2014 Form 10-K. As of December 31, 2014, the fair value of our open derivative contracts was a net asset of $517.1 million. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. We have rights of offset against the borrowings under our revolving credit facility. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” of our 2014 Form 10-K for additional information.

Interest Rate Derivative Contracts

Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Interest Rate Risk” of our 2014 Form 10-K for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the years ended December 31, 2014, 2013 and 2012 is presented on a combined basis, consisting of the consolidated financial information of the Partnership and the combined financial information of the previous owners. For information regarding the individual components of our cash flow amounts, see the Statements of Supplemental Consolidated and Combined Cash Flows included under “Recast Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report.

	For the Twelve Months Ended
	December 31,
	2014		2013		2012
Net cash provided by operating activities	$	254,273	$	201,703	$	183,983
Net cash used in investing activities		1,386,109		214,559		417,831
Net cash provided by financing activities		1,111,108		5,969		237,233

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net income increased by $54.6 million and net cash provided by operating activities increased by $52.6 million. Production increased 19.6 Bcfe (approximately 31%) and the average realized sales price increased to $6.45 per Mcfe as previously discussed under “—Results of Operations.” Cash paid for interest during the year ended December 31, 2014 was $63.7 million compared to $42.6 million during the year ended December 31, 2013. Net cash provided by operating activities included $11.7 million of cash receipts on derivative instruments and we had a $7.8 million decrease in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during the year ended December 31, 2014 compared to the year ended December 31, 2013.

Investing Activities. Net cash used in investing activities during the year ended December 31, 2014 was $1.38 billion, of which $1.08 billion was used to acquire oil and natural gas properties from third parties and $298.3 million was used for additions to oil and gas properties. Cash used in investing activities during the year ended December 31, 2013 was $214.6 million, of which $38.7 million was used to acquire oil and natural gas properties from third parties and $174.8 million was used for additions to oil and gas properties. See Note 3 of the Notes to Supplemental 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 acquisitions and divestitures.

years ended December 31, 2014 and 2013, additions to restricted investments were $4.0 million and $5.4 million, respectively. See Note 7 of the Notes to Supplemental Consolidated and Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data” for additional information regarding our restricted investments.

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

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

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

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

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

The Partnership had borrowings of $1.45 billion under its revolving credit facility during 2014 that were used primarily to fund the Eagle Ford and Wyoming Acquisitions and to fund its drilling program. The Partnership had net payments of $268.0 million under its revolving credit facility during the year ended December 31, 2013. The previous owners had net repayments of $339.2 million under their revolving credit facilities during the year ended December 31, 2013. Deferred financing costs of approximately $11.5 million were incurred during the year ended December 31, 2014 compared to approximately $20.9 million during the year ended December 31, 2013.

The previous owners received contributions of $6.0 million and $96.8 million during 2014 and 2013, respectively, to partially fund their development and property acquisition program, to repay indebtedness and terminate the revolving credit facility attributable to Classic in December 2013 and to fund the $8.3 million related to the Classic management buyout in November 2013. During 2014, the previous owners made distributions of $9.9 million related to Classic. During 2013, the previous owners made distributions of $31.1 million, all of which was attributable to the Cinco Group.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash flows provided by operating activities increased during 2013 primarily due to an increase in production volumes. Production increased 10.4 Bcfe (approximately 20%) and the average realized sales price increased to $5.88 per Mcfe as previously discussed under “—Results of Operations.” Cash paid for interest during the year ended December 31, 2013 was $42.6 million compared to $18.0 million during the year ended December 31, 2012. Net cash provided by operating activities included $22.6 million of cash receipts on derivative instruments for the year ended December 31, 2013 compared to $9.4 million of cash receipts on derivative instruments for the year ended December 31, 2012. In addition, we had an $18.9 million period-to-period decrease in impairments offset by a $14.6 million increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during the year ended December 31, 2013

compared to the year ended December 31, 2012. We used cash flows provided by operating activities primarily to fund distributions to our partners and additions to oil and gas properties. The previous owners primarily used cash flows provided by operating activities to fund its exploration and development expenditures.

Investing Activities. Cash used in investing activities during 2013 was $214.6 million, of which $38.7 million was used to acquire oil and natural gas properties and $174.8 million was used for additions to oil and gas properties. Cash used in investing activities during 2012 was $417.8 million, of which $277.6 million was used to acquire oil and natural gas properties and $168.4 million was used for additions to oil and gas properties.

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. For the years ended December 31, 2013 and 2012, additions to restricted investments were $5.4 million and $4.6 million, respectively.

Financing Activities. As discussed above, we sold common units in two separate public equity offerings during 2013. The net proceeds from the March 2013 equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT. The net proceeds from the October 2013 equity offering, including our general partner’s proportional capital contribution, were used to repay a portion of outstanding borrowings under our revolving credit facility. In December 2012, we sold 11,975,000 common units in a public offering generating total net proceeds of approximately $194.1 million after deducting underwriting discounts and offering related expenses. The net proceeds from the offering, including our general partner’s proportionate capital contribution, were used to fund a portion of the purchase price of the Beta acquisition and to repay indebtedness under our revolving credit facility. We distributed approximately $242.2 million as partial consideration to Rise Energy Partners, LP and repaid $28.5 million of indebtedness under the previous owners’ credit facility.

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

Distributions to partners were $96.6 million for the year ended December 31, 2013 compared to $34.4 million for the year ended December 31, 2012 due to increases in both declared distribution rates per unit and increases in the number of outstanding units. Distributions to Memorial Resource increased to $151.7 million for 2013 compared to $18.5 million for 2012 as a result of additional acquisitions from Memorial Resource in 2013. Distributions to NGP affiliates were $355.5 million related to the Cinco Group acquisition for 2013 compared to $242.2 million for 2012 related to the Beta acquisition.

The net proceeds from the 2021 Senior Notes, as noted above, were used to repay borrowings outstanding under our revolving credit facility. There were no senior notes issued during 2012. The Partnership had net payments of $268.0 million under its revolving credit facility during 2013. The previous owners had net repayments of $339.2 million under their revolving credit facilities during 2013. The Partnership incurred loan origination fees of approximately $20.9 million during 2013 primarily related to the 2021 Senior Notes. The Partnership had net borrowings of $251.0 million under its revolving credit facility during 2012 that were used primarily to fund the acquisitions of oil and gas properties. The previous owners had net borrowings of $18.2 million under their revolving credit facilities during 2012. The Partnership and the previous owners incurred loan origination fees of approximately $1.4 million and $0.8 million, respectively, during 2012.

The previous owners received contributions of $96.8 million and $64.6 million during 2013 and 2012, respectively, to partially fund their development and property acquisition program, to repay indebtedness and terminate the revolving credit facility attributable to Classic in December 2013 and to fund the $8.3 million related to the Classic management buyout in November 2013. The previous owners made distributions of $31.1 million during 2013, all of which was attributable to the Cinco Group. The previous owners made distributions of $28.4 million during 2012, including $20.6 million attributable to the Cinco Group and $7.8 million attributable to REO.

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

Capital Requirements

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

In 2015, we intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4750 per unit per quarter on all common and general partner units ($1.90 per unit on an annualized basis). On February 12, 2015, we paid a $46.3 million cash distribution for the fourth quarter 2014 to our unitholders, our general partner and the holders of our IDRs. This distribution represented an annualized amount of $2.20 per common unit. Assuming no further changes in the distribution rate and the number of common units and general partner units currently outstanding, the aggregate distribution paid to all of our unitholders in 2015 would total approximately $185.2 million.

We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisition of oil and natural gas properties in 2015 through a combination of cash from operations, borrowings under our revolving credit facility and the issuance of equity or debt securities.

Contractual Obligations

In the table below, we set forth our contractual obligations as of December 31, 2014. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

			Payment or Settlement due by Period
Contractual Obligation	Total		2015		2016 - 2017		2018-2019		Thereafter
			(in thousands)
Revolving credit facility (1)	$	412,000	$	—	$	—	$	412,000	$	—
Senior Notes (2)
2021 Senior Notes		1,046,938		53,375		106,750		106,750		780,063
2022 Senior Notes		776,719		36,094		68,750		68,750		603,125
Estimated interest payments (3)		47,512		11,179		22,359		13,974		—
Asset retirement obligations (4)		112,702		—		5,266		3,765		103,671
Decommissioning Trust Agreement (5)		10,350		4,140		6,210		—		—
CO₂ minimum purchase commitment (6)		50,495		9,608		20,330		14,055		6,502
Operating leases (7)		3,665		788		621		410		1,846
Compression services		6,526		6,526		—		—		—
Total	$	2,466,907	$	121,710	$	230,286	$	619,704	$	1,495,207

(1)	Represents the scheduled future maturities of principal amount outstanding for the periods indicated. See Note 8 of the Notes to Supplemental Consolidated and Combined Financial Statements included under Item 8 of this annual report for information regarding our revolving credit facility.
(2)	Represents the scheduled future interest payments on the 2021 Senior Notes and 2022 Senior Notes and principal payments. Interest accrues per annum and is payable semi-annually in arrears. See Note 8 of the Notes to Supplemental Consolidated and Combined Financial Statements included under Item 8 of this annual report for additional information.
(3)	Estimated interest payments are based on the principal amount outstanding under our revolving credit facility at December 31, 2014. In calculating these amounts, we applied the weighted-average interest rate during 2014 associated with such debt. See Note 8 of the Notes to Supplemental Consolidated and Combined Financial Statements included under Item 8 of this annual report for the weighted-average variable interest rate charged during 2014 under our revolving credit facility. In addition, our estimate of payments for interest gives effect to interest rate swap agreements that were in place at December 31, 2014.
(4)	Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2014 balance sheet. See Note 6 of the Notes to Supplemental Consolidated and Combined Financial Statements included under Item 8 of this annual report for additional information regarding our asset retirement obligations.
(5)	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 13 of the Notes to Supplemental Consolidated and Combined Financial Statements included under Item 8 of this annual report for additional information.
(6)	Represents a firm agreement, which we assumed in the Wyoming Acquisition, to purchase CO2 volumes.
(7)	Primarily represents leases for offshore Southern California right-of-way use and office space. See Note 13 of the Notes to Supplemental Consolidated and Combined Financial Statements included under Item 8 of this annual report for information regarding our operating leases.

Off–Balance Sheet Arrangements

As of December 31, 2014, 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 Supplemental Consolidated and Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Report.

Amplify Energy (AMPYW) Inactive 8-KMemorial Production Partners LP