Amplify Energy Corp - FORM 8-K - EX-99.1 - RECAST OF ITEMS 6, 7 AND 7A OF ANNUAL REPORT ON FORM 10-K

Attached files

file	filename
8-K - FORM 8-K - Amplify Energy Corp	d440170d8k.htm
EX-99.3 - REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Amplify Energy Corp	d440170dex993.htm
EX-23.1 - CONSENT OF KPMG LLP - Amplify Energy Corp	d440170dex231.htm
EX-23.2 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Amplify Energy Corp	d440170dex232.htm
EX-99.2 - RECAST OF ITEM 8 OF ANNUAL REPORT ON FORM 10-K - Amplify Energy Corp	d440170dex992.htm

Exhibit 99.1

MEMORIAL PRODUCTION PARTNERS LP

RECAST OF CERTAIN SECTIONS OF THE 2011 ANNUAL REPORT ON FROM 10-K

TABLE OF CONTENTS


		Page
	Glossary of Oil and Natural Gas Terms	2
Item 6.	Selected Financial Data.	6
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	7
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	24

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

Bbl/d: One Bbl per day.

Bcf: One billion cubic feet of natural gas.

Bcfe: One billion cubic feet of natural gas equivalent.

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

Boe/d: One Boe per day.

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

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

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

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

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

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

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

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

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

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

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

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

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

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

MBtu/d: One thousand Btu per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

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

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 based on annualized fourth quarter production and are adjusted, if necessary, to reflect property acquisitions and dispositions.

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

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

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

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

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

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

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

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

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

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

WTI: West Texas Intermediate.

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, 2011, 2010, 2009, 2008 and 2007 have been derived from our consolidated financial statements subsequent to the closing of our IPO and our predecessor’s combined financial statements. The selected financial data for the year ended December 31, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor for the year ended December 31, 2011 and the consolidated financial information of the Partnership for the period from December 14, 2011 to December 31, 2011. The selected financial data covering periods prior to the closing of our IPO and our acquisitions from Memorial Resource in April and May 2012 may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods.


	For Year Ended December 31,
	2011		2010		2009		2008		2007

	($ in thousands, except per unit data)
Statement of Operations Data:							(Unaudited)		(Unaudited)
Revenues:
Oil & natural gas sales	$	84,058	$	47,435	$	32,032	$	56,418	$	12,199
Other income		825		1,433		319		622		153

Total revenues		84,883		48,868		32,351		57,040		12,352


Costs and expenses:
Lease operating		24,474		14,878		12,191		9,239		2,890
Exploration		56		39		2,690		374		--
Production taxes		4,790		2,838		2,032		3,604		1,188
Depreciation, depletion, and amortization		30,052		24,543		19,011		13,835		18,144
Impairment of proved oil and natural gas properties		15,141		11,800		3,480		18,564		--
General and administrative		10,399		7,102		5,845		4,400		2,937
Accretion of asset retirement obligations		1,069		672		326		226		319
(Gain) loss on commodity derivative instruments		(33,325)		(11,213)		(11,121)		(9,815)		734
Gain on sale of properties		(63,024)		(1)		(7,851)		(7,395)		--
Other, net		1,908		1,194		448		50		744

Total costs and expenses		(8,460)		51,852		27,051		33,082		26,956

Operating income (loss)		93,343		(2,984)		5,300		23,958		(14,604)
Interest expense		7,268		4,438		2,937		3,138		1,135

Income (loss) before income taxes		86,075		(7,422)		2,363		20,820		(15,739)
Income tax expense		122		225		--		--		--

Net income (loss)		85,953		(7,647)		2,363		20,820		(15,739)
Net income (loss) attributable to predecessor		79,361		(7,647)		2,363		20,820		(15,739)

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


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

General partner	$	7	$	--	$	--	$	--	$	--


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


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


Cash Flow Data:
Net cash flow provided by operating activities	$	42,706	$	27,496	$	17,433	$	38,455	$	6,992
Net cash used in investing activities		169,652		135,081		42,138		63,614		100,034
Net cash provided by financing activities		122,380		107,942		28,419		24,069		95,514

Balance Sheet Data:						(Unaudited)
Working capital (deficit)	$	25,541	$	4,116	$	9,494	$	(966)	$	(1,684)
Total assets		493,246		292,433		174,826		160,383		101,639
Total debt		120,000		115,428		61,784		62,536		46,726
Total equity		354,021		149,114		101,445		69,346		39,072

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 “Recast Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained under Item 1A of our 2011 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 2011 Form 10-K.

Overview

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

Our oil and natural gas properties are located primarily in South and East Texas. Based on proved reserves volumes at December 31, 2011, we or Memorial Resource operate 94% of the properties in which we have interests, and we own an average working interest of 47% across these oil and natural gas properties. As of December 31, 2011, we had interests in 1,401 gross (635 net) producing wells across our properties, with an average working interest of 45%. As of December 31, 2011, we had estimated proved reserves of 383 Bcfe, of which approximately 75% were classified as proved developed reserves including approximately 12% classified as proved developed non-producing, and a standardized measure of $463.9 million.

Our Initial Public Offering

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

Acquisitions of Oil & Gas Properties – Common Control

On April 2, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $18.5 million, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of certain commodity derivative positions with effective dates 2012 through 2013. The transaction was approved by the board of directors of our general partner (the “Board”) and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas. Memorial Resource will continue to operate 84% of the acquired properties and the remaining 16% will continue to be operated by third parties.

On May 14, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $27.0 million, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of certain commodity derivative positions with effective dates 2012 through 2014. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Cotton Valley and Travis Peak fields in Panola and Shelby counties in East Texas.

Acquisitions of oil and gas properties from Memorial Resource are accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired are recorded at Memorial Resource’s carrying value and certain financial and other information are retrospectively revised to give effect to such acquisitions as if the Partnership had owned the assets beginning on the dates Memorial Resource originally acquired them. For information about the Partnership’s basis of presentation, see Note 1 of the Notes to Consolidated and Predecessor Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data” contained in Exhibit 99.2 of this Current Report.

Entry into Definitive Purchase and Sale Agreement

On November 19, 2012, we entered into a definitive purchase and sale agreement with Rise Energy Partners, LP (“Rise”) to acquire Rise Energy Operating, LLC, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, for a purchase price of $271.0 million, which includes $3.0 million of working capital and other customary adjustments (the “Beta Acquisition”). We have the ability to finance this transaction through borrowings under our revolving credit facility and promissory notes payable to Rise. The Beta Acquisition is expected to close in December 2012. Terms of the transaction were approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. On November 19, 2012, the Board also approved, subject to the completion of the Beta Acquisition, an increase in our distribution rate attributable to the fourth quarter of 2012 to $0.5075 per unit.

Business Environment and Operational Focus

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

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

•

production volumes;

•

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

•

lease operating expenses;

•

general and administrative expenses; and

•

Adjusted EBITDA (defined below).

Production Volumes

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

Realized Prices on the Sale of Oil and Natural Gas

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

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

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

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

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

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

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

Commodity Derivative Contracts. Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into commodity derivative contracts covering approximately 65% to 85% of our targeted average net production over a three-to-five year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we intend to individually identify these non-speculative hedges as “designated hedges” for U.S. federal income tax purposes as we enter into them, resulting in ordinary income treatment of our realized hedge activity.

Lease Operating Expenses

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

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

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

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

General and Administrative Expenses

We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource currently intends to allocate its expected general and administrative costs based on the relative size of our proved and probable reserves in comparison to Memorial Resource’s proved and probable reserves. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf. For a detailed description of the omnibus agreement, please read “Item 13. Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreement” contained within the Partnership’s 2011 Form 10-K.

Adjusted EBITDA

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

Plus:

•

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

•

Income tax expense;

•

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

•

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

•

Accretion of asset retirement obligations (“AROs”);

•

Unrealized losses on commodity derivative contracts;

•

Losses on sale of assets and other, net;

•

Unit-based compensation expenses;

•

Exploration costs;

•

Acquisition related costs;

•

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

•

Other non-routine items that we deem appropriate.

Less:

•

Interest income;

•

Income tax benefit;

•

Unrealized gains on commodity derivative contracts;

•

Gains on sale of assets and other, net; and

•

Other non-routine items that we deem appropriate.

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

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

•

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

•

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

In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

The following tables present our calculation of Adjusted EBITDA as well as a reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.

Calculation of Adjusted EBITDA


	For Year Ended December 31,
	2011		2010		2009

	($ in thousands)

Net income (loss)	$	85,953	$	(7,647)	$	2,363
Interest expense		7,268		4,438		2,937
Income tax expense		122		225		--
DD&A		30,052		24,543		19,011
Impairment		15,141		11,800		3,480
Accretion of AROs		1,069		672		326
Unrealized (gains) losses on commodity derivative instruments		(25,381)		(3,919)		6,453
Acquisition related costs		1,045		890		304
Gain on sale of properties		(63,024)		(1)		(7,851)
Exploration costs		56		39		2,690

Adjusted EBITDA	$	52,301	$	31,040	$	29,713

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA


	For Year Ended December 31,
	2011		2010		2009

	($ in thousands)

Net cash provided by operating activities	$	42,706	$	27,496	$	17,433
Changes in working capital		684		(743)		8,838
Interest expense		7,268		4,438		2,937
Unrealized gain (loss) on interest rate swaps		(776)		(296)		310
Premiums paid for derivatives		2,847		--		--
Premiums received for derivatives		(1,008)		--		--
Acquisition related costs		1,045		890		304
Amortization of deferred financing fees		(465)		(745)		(109)
Net operating cash flow from acquisitions, effective date through closing date		--		--		--

Adjusted EBITDA	$	52,301	$	31,040	$	29,713

Critical Accounting Policies and Estimates

Oil and Natural Gas Properties

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

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

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

Proved Oil and Natural Gas Reserves

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

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

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

Impairments

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

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

Asset Retirement Obligations

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

Revenue Recognition

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

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, floors, collars, and forward sales) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statements of operations. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. There were no derivatives designated as hedges for financial accounting purposes at December 31, 2011 or 2010.

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

Results of Operations

The results of operations for the years ended December 31, 2011, 2010 and 2009 have been derived from our consolidated financial statements subsequent to the closing of our IPO and our predecessor’s combined financial statements. The results of operations for the year ended December 31, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor for the year ended December 31, 2011 and the consolidated financial information of the Partnership for the period from December 14, 2011 to December 31, 2011. The results of operations covering periods prior to the closing of our IPO and our acquisitions from Memorial Resource in April and May 2012 may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods.

Factors Affecting the Comparability of the Historical Financial Results of Our Predecessor

The historical financial data of our predecessor consists of the combined financial data of (a) BlueStone Natural Resources Holdings, LLC and its wholly-owned subsidiaries in addition to certain oil and natural gas properties owned by Classic for all periods prior to the closing of our initial public offering, (b) certain oil and natural gas properties owned by WHT Energy Partners LLC, a subsidiary of Memorial Resource, from April 8, 2011 through the closing of our initial public offering, and certain oil and natural gas properties the Partnership acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates. Our predecessor did not contribute all of its properties to us. The comparability of our predecessor’s results of operations among the periods presented is impacted by:

•

The following significant acquisitions by our predecessor:

^¡

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

^¡

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

^¡

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

^¡

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

^¡

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

^¡

Oil and natural gas properties and related assets acquired from BP America Production Company (“BP”) in May 2011, including the related disposition to BP of certain assets previously acquired from Forest Oil.

^¡

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

•

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

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

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


	For Year Ended December 31,
	2011		2010		2009

	(in thousands, except operating and per unit amounts)
Revenues:
Oil & natural gas sales	$	84,058	$	47,435	$	32,032
Other income		825		1,433		319

Total revenues	$	84,883	$	48,868	$	32,351


Costs and expenses:
Lease operating		24,474		14,878		12,191
Exploration		56		39		2,690
Production taxes		4,790		2,838		2,032
Depreciation, depletion, and amortization		30,052		24,543		19,011
Impairment of proved oil and natural gas properties		15,141		11,800		3,480
General and administrative		10,399		7,102		5,845
Accretion of asset retirement obligations		1,069		672		326
Gain on derivative instruments		(33,325)		(11,213)		(11,121)
Gain on sale of properties		(63,024)		(1)		(7,851)
Other, net		1,908		1,194		448

Total costs and expenses		(8,460)		51,852		27,051

Operating income (loss)		93,343		(2,984)		5,300
Interest expense		7,268		4,438		2,937

Income (loss) before income taxes		86,075		(7,422)		2,363
Income tax expense		122		225		--

Net income (loss)		85,953		(7,647)		2,363
Net income (loss) attributable to predecessor		79,361		(7,647)		2,363

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


Oil and natural gas revenue:
Oil sales	$	8,864	$	4,680	$	4,359
NGL sales		9,392		2,838		1,332
Natural gas sales		65,802		39,917		26,341

Total oil and natural gas revenue	$	84,058	$	47,435	$	32,032


Production Volumes:
Oil (MBbls)		97		62		75
NGLs (MBbls)		182		69		44
Natural gas (MMcf)		15,936		9,151		7,027

Total (MMcfe)		17,608		9,940		7,738

Average net production (MMcfe/d)		48.2		27.2		21.2


Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	91.43	$	75.90	$	58.37
NGL (per Bbl)		51.70		40.95		30.50
Natural gas (per Mcf)		4.13		4.36		3.75

Total (Mcfe)	$	4.77	$	4.77	$	4.14


Average unit costs per Mcfe:
Lease operating expense	$	1.39	$	1.50	$	1.58
Production taxes	$	0.27	$	0.29	$	0.26
General and administrative expenses	$	0.59	$	0.71	$	0.76
Depletion, depreciation, and amortization	$	1.71	$	2.47	$	2.46

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

Net income was $86.0 million for the year ended December 31, 2011, of which $79.4 was attributable to our predecessor. Our predecessor recorded a net loss of $7.6 million for the year ended December 31, 2010, none of which was attributable to the Partnership. Our predecessor recorded an aggregate gain on the sale of properties of $63.0 million during 2011 with no comparable gain recorded during 2010.

Revenues. Oil, natural gas and NGL revenues for 2011 totaled $84.1 million, an increase of $36.7 million compared with 2010. The increase was primarily the result of increased production of 7,668 MMcfe, or 77%, primarily related to the 2010 acquisitions of certain oil and gas assets in both East and South Texas that were fully integrated in 2011, the acquisition of properties from BP in May 2011 and the acquisition of certain oil and gas assets in April 2011. The average realized sales price (excluding realized gain on derivatives) in both 2011 and 2010 was $4.77 per Mcfe.

Lease Operating. Lease operating expenses increased by approximately $9.6 million or 64% to approximately $24.5 million for the year ended December 31, 2011, from approximately $14.9 million for the year ended December 31, 2010. Lease operating expenses increased primarily due to costs associated with the both the East and South Texas properties acquired in 2010 which were fully integrated in 2011, the BP properties acquired in May 2011 and the acquisition of certain oil and gas assets in April 2011.

Production Taxes. Production taxes for 2011 totaled $4.8 million, an increase of $2.0 million compared with 2010. The increase in production taxes was primarily due to higher oil, natural gas and NGL revenues during 2011. Production taxes were 5.7% and 6.0% as a percentage of oil and natural gas revenue in 2011 and 2010, respectively.

Depreciation, Depletion and Amortization. DD&A expense increased from approximately $24.5 million for the year ended December 31, 2010 to approximately $30.1 million for the year ended December 31, 2011 due to increased production from 9,940 MMcfe to 17,608 MMcfe related to acquisitions that took place in 2010 and 2011. DD&A expense per Mcfe decreased from $2.47 to $1.71 between 2010 and 2011 due to a higher proportional increase in proved reserve volumes when compared to the increase in capitalized costs subject to DD&A.

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

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

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

General and Administrative. General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to Memorial Resource, professional fees and other costs not directly associated with field operations. General and administrative expenses for 2011 totaled $10.4 million, of which only $0.2 million was attributable to the Partnership. For 2010, general and administrative expenses were $7.1 million. Increased production volumes in 2011 drove general and administrative expenses lower on a per Mcfe basis from approximately $0.71 per Mcfe in 2010 to $0.59 per Mcfe in 2011.

Gain on Derivative Instruments. We and our predecessor recognized gains on commodity derivative instruments of $33.3 million in 2011, as compared to $11.2 million that our predecessor generated in 2010. For 2011, the $33.3 million gain was comprised of realized gains of $7.9 million and unrealized gains of $25.4 million. For 2010, the $11.2 million gain was comprised of realized gains of $7.3 million and unrealized gains of $3.9 million.

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

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

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

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

Our predecessor generated a net loss of $7.6 million during 2010 compared to net income of $2.4 million for the year ended December 31, 2009. Despite a $15.4 million increase in oil and natural gas sales revenues between the periods, net income decreased approximately $10.0 million primarily related to a $5.5 million increase in DD&A, an $8.3 million increase in impairment charges and a $7.9 million decrease in gains on the sale of properties.

Revenues. Our predecessor’s oil and natural gas sales revenues increased 48% from $32.0 million for the year ended December 31, 2009 to $47.4 million for the year ended December 31, 2010. Approximately $9.1 million of this increase was driven by increased production, which increased approximately 28% to 9,940 MMcfe for the year ended December 31, 2010. The remainder of the increase in revenues was due to higher oil and natural gas commodity prices received, which averaged $4.14 per Mcfe during 2009 and $4.77 per Mcfe during 2010. Other income revenues related to the predecessor properties increased from $0.3 million for the year ended December 31, 2009 to $1.4 million for the year ended December 31, 2010, primarily due to the settlement of litigation that occurred in 2010.

Lease Operating. Lease operating expenses increased from $12.2 million for the year ended December 31, 2009 to $14.9 million in 2010, primarily as a result of the increase in our predecessor’s production volumes described above. Lease operating expenses per Mcfe decreased period to period approximately 5% from $1.58 per Mcfe in 2009 to $1.50 per Mcfe in 2010, primarily related to the increase in production.

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

Production Taxes. Production taxes increased from $2.0 million in 2009 to $2.8 million in 2010, which is primarily due to higher oil and natural gas revenues received during 2010 compared to 2009.

Depreciation, Depletion and Amortization. Our predecessor’s DD&A expense increased from approximately $19.0 million in 2009 to $24.5 million in 2010, primarily due to an increase in production from 7,738 MMcfe to 9,940 MMcfe.

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

General and Administrative. General and administrative expenses totaled $5.8 million and $7.1 million for the years ended December 31, 2009 and 2010, respectively. General and administrative expenses include the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production. The change in general and administrative expenses during 2010 resulted primarily from an increase of approximately $0.5 million in payroll related costs and an increase of approximately $0.6 million in professional services fees paid.

Gain on Derivative Instruments. Gains on commodity derivative instruments of $11.1 million were recognized in 2009, as compared to $11.2 million generated in 2010. For 2009, the $11.1 million gain was comprised of realized gains of $17.6 million and unrealized losses of $6.5 million. For 2010, the $11.2 million gain was comprised of realized gains of $7.3 million and unrealized gains of $3.9 million.

Gain on Sale of Properties. During 2009, our predecessor recognized a gain of approximately $7.9 million on two separate sales of interests in the Nueces Mineral Company lease, located in South Texas and primarily undeveloped, for net proceeds of $11.7 million.

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

Liquidity and Capital Resources

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

Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We may also have the ability to issue additional equity and debt as needed. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to current credit conditions includes our revolving credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

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

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

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

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

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

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

As of December 31, 2011, our liquidity of $181.1 million consisted of $1.1 million of available cash, and $180.0 million of available borrowings under our revolving credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility. As of December 31, 2011, our revolving credit facility had borrowing capacity of $180.0 million ($300.0 million borrowing base less $120.0 million of outstanding borrowings). The borrowing base will be redetermined semi-annually, beginning on April 1, 2012, by the administrative agent of our revolving credit facility based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. See Note 7 of the Notes to Consolidated and Predecessor Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data” in Exhibit 99.2 of this Current Report for additional information regarding our increased borrowing base that became effective September 28, 2012.

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

Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 7 and Note 8 of the Notes to Consolidated and Predecessor Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data” in 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, 2011, we had a positive working capital balance of $25.5 million.

Capital Expenditures

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

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

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

Revolving Credit Facility

Concurrently with the closing of our IPO, OLLC entered into a new senior secured revolving credit facility, which facility is guaranteed by us and all of our current and future subsidiaries. This revolving credit facility is a five-year, $1.0 billion revolving credit facility with an initial borrowing base of $300.0 million. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In the future, we may be unable to access sufficient capital under our revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations. See Note 7 of the Notes to Consolidated and Predecessor Combined Financial Statements included under “Recast Item 8. Financial Statements and Supplementary Data” in Exhibit 99.2 of this Current Report for additional information regarding our increased borrowing base that became effective September 28, 2012 and the ability to incur second lien indebtedness.

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

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

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

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

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

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

As of December 31, 2011, we were in compliance with all of the financial and other covenants under our revolving credit facility. At December 31, 2011, we had $120.0 million outstanding under our revolving credit facility.

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 targeted average net production over a three-to-five year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range.

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

Interest Rate Derivative Contracts

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. At December 31, 2011, we had the following fixed-for floating interest rate swap open positions:

Period Covered

Notional
($ in thousands)

Floating Rate

Fixed Rate

1/17/2012

1/16/2013

100,000

1 Month LIBOR

0.600%

1/17/2013

12/14/2016

100,000

1 Month LIBOR

1.305%

Counterparty Exposure

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

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


	Gross

Assets		39,206
Liabilities		(3,869)

Net		35,337

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the year ended December 31, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor for year ended December 31, 2011 and the consolidated financial information of the Partnership for the period from December 14, 2011 to December 31, 2011. For information about the individual components of our cash flow amounts, see the Statements of Consolidated and Predecessor Combined Cash Flows, which is included under “Recast Item 8. Financial Statements and Supplementary Data” contained in Exhibit 99.2 of this Current Report.


	For Year Ended December 31,

	2011		2010		2009

	(in thousands)
Net cash provided by operating activities	$	42,706	$	27,496	$	17,433
Net cash used in investing activities		169,652		135,081		42,138
Net cash provided by financing activities		122,380		107,942		28,419

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

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash flows provided by operating activities increased for the year ended December 31, 2011 primarily due to an increase in production volumes as a result of our predecessor’s acquisition activities. Cash flows provided by operating activities were primarily used to fund our predecessor’s exploration and development expenditures.

Investing Activities. During 2011, our predecessor spent $138.2 million on several acquisitions, the largest of which was the purchase of oil and natural gas properties in East Texas from a third party for $120.8 million. Our predecessor incurred capital expenditures of $33.5 million in conjunction with the drilling of 6 gross wells in 2011, none of which were dry holes, for a success rate of 100%. Our predecessor’s acquisition and development expenditures were offset by proceeds from the sale of properties for $2.4 million.

During 2010, $119.5 million was spent on several acquisitions, the largest of which was the purchase of oil and natural gas properties in South Texas from Forest Oil for $65.9 million. Capital expenditures of $16.6 million were incurred in conjunction with the drilling of 4 gross wells in 2010, none of which were dry holes, for a success rate of 100%. Our predecessor’s acquisition and development expenditures were partially offset by proceeds from the sale of properties for $1.4 million.

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

During 2011, net advances of $82.8 million under our predecessor’s revolving credit facilities and capital contributions of $52.8 million were used to fund our predecessor’s development and property acquisition program. During 2010, net advances of $53.5 million under our predecessor’s revolving credit facilities and capital contributions of $55.3 million were used to fund our predecessor’s development and property acquisition program. Loan origination fees incurred by our predecessor were $0.9 million during 2011 compared to $1.0 million during 2010.

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

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash flows provided by operating activities increased for the year ended December 31, 2010, despite a decrease in net income, primarily due to an increase in production volumes as a result of our predecessor’s acquisition activities as well as their continued drilling success. Cash flows provided by operating activities were primarily used to fund our predecessor’s exploration and development expenditures.

Investing Activities. During 2010, $119.5 million was spent on several acquisitions, the largest of which was the purchase of oil and natural gas properties in South Texas from Forest Oil for $65.9 million. Capital expenditures of $16.6 million were incurred in conjunction with the drilling of 4 gross wells in 2010, none of which were dry holes, for a success rate of 100%. Acquisition and development expenditures were offset by proceeds from the sale of properties for $1.4 million.

During 2009, $17.5 million was spent on several acquisitions of oil and natural gas properties in South Texas. Capital expenditures of $36.2 million were incurred in conjunction with the drilling of 11 gross wells in 2009, one of which was a dry hole, for a success rate of 91%. Acquisition and development expenditures were partially offset by proceeds from the sale of properties for $11.8 million.

Financing Activities. During 2010, net advances of $53.5 million under our predecessor’s revolving credit facilities and capital contributions of $55.3 million were used to fund our predecessor’s development and property acquisition program. During 2009, capital contributions of $29.7 million were partially offset by net repayments of $0.8 million under our predecessor’s revolving credit facilities. These capital contributions were used to fund our predecessor’s development and property acquisition program.

Capital Requirements

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

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

Contractual Obligations

Our contractual obligations are limited in scope because Memorial Resource provides management, administrative and operating services to us under an omnibus agreement as discussed under “Item 13. Certain Relationships and Related Transactions, and Director Independence —Omnibus Agreement” contained within the Partnership’s 2011 Form 10-K. In the table below, we set forth our contractual obligations as of December 31, 2011. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.


	Payments Due by Period (in thousands)
Contractual Obligations		Total			Less than 1 year			1-3 years			3-5 years			More than 5 years

Revolving credit facility (1)	$		120,000	$		--	$		--	$		120,000	$		--
Estimated interest payments (2)			21,331			3,739			8,885			8,707			--
Asset retirement obligations (3)			14,113			--			1,094			811			12,208
Operating leases (4)			734			682			52			--			--

Total	$		156,178	$		4,421	$		10,031	$		129,518	$		12,208

(1)

Represents the scheduled future maturities of principal amount outstanding for the periods indicated. For information regarding our revolving credit facility, see Note 7 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this Current Report contained in Exhibit 99.2.

(2)

Estimated interest payments are based on the principal amount outstanding under our revolving credit facility at December 31, 2011. In calculating these amounts, we applied the weighted-average interest rate during 2011 associated with such debt. For the weighted-average variable interest rate charged during 2011 under this credit facility, see Note 7 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this Current Report contained in Exhibit 99.2. In addition, our estimate of payments for interest gives effect to interest rate swap agreements that were in place at December 31, 2011.

(3)

Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2011 balance sheet. For additional information regarding our asset retirement obligations, see Note 6 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this Current Report contained in Exhibit 99.2.

(4)

Primarily represents operating leases for certain equipment such as compressors and office space. For information regarding our operating leases, see Note 12 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this Current Report contained in Exhibit 99.2.

Off–Balance Sheet Arrangements

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

Recently Issued Accounting Pronouncements

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

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

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

Commodity Price Risk

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

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

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

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

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

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

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


	2012		2013		2014		2015		2016
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		357,498		451,052		772,740		781,578		865,165
Weighted-average fixed price	$	5.09	$	4.67	$	4.44	$	4.44	$	4.70

Collar contracts:
Average Monthly Volume (MMBtu)		664,500		633,000		120,000		80,000		--
Weighted-average floor price	$	4.75	$	4.78	$	5.08	$	5.25	$	--
Weighted-average ceiling price	$	5.85	$	5.82	$	6.31	$	6.75	$	--

Put options:
Average Monthly Volume (MMBtu)		70,000		--		--		--		--
Weighted-average strike price	$	4.80	$	--	$	--	$	--	$	--

Basis swaps:
Average Monthly Volume (MMBtu)		353,633		405,932		--		--		--
Spread	$	(0.14)	$	(0.16)	$	--	$	--	$	--

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		1,790		1,540		2,250		--		--
Weighted-average fixed price	$	92.00	$	92.00	$	87.90	$	--	$	--

Collar contracts:
Average Monthly Volume (Bbls)		4,500		4,750		3,200		--		--
Weighted-average floor price	$	86.67	$	87.16	$	90.00	$	--	$	--
Weighted-average ceiling price	$	115.12	$	116.94	$	117.72	$	--	$	--

NGL Derivative Contracts:
Collar contracts:
Average Monthly Volume (Bbls)		3,800		--		--		--		--
Weighted-average floor price	$	75.16	$	--	$	--	$	--	$	--
Weighted-average ceiling price	$	93.57	$	--	$	--	$	--	$	--

Interest Rate Risk

At December 31, 2011, we had $120 million of debt outstanding under our revolving credit facility, with a weighted average interest rate of LIBOR plus 2.0%, or 2.28%. Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Following the closing of our IPO, we entered into the following interest rate swap arrangements:

•

$100,000,000 notional amount fixed-for-floating swap for the period beginning January 17, 2012 and ending January 16, 2013 at a fixed annual rate of 0.60%; and

•

$100,000,000 notional amount fixed-for-floating swap for the period beginning January 17, 2013 and ending December 14, 2016 at a fixed annual rate of 1.305%.

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

Counterparty and Customer Credit Risk

Joint interest billings receivable represent amounts receivable for lease operating expenses and other costs due from third party working interest owners in the wells that the Partnership operates. The receivable is recognized when the cost is incurred. We have limited ability to control participation in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. See Note 7 of the Notes to Consolidated and Predecessor Combined Financial Statements included under Item 8 of this Current Report contained in Exhibit 99.2 for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative contracts may expose us to credit risk in the event of nonperformance by counterparties.

While we do not require our customers to post collateral and do not have a formal process in place to evaluate and assess the credit standing of our significant customers or the counterparties on its derivative contracts, we do evaluate the credit standing of our customers and such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating and latest financial information or, in the case of a customer with which we have receivables, reviewing its historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative contracts currently in place are lenders under our revolving credit facility, with investment grade ratings and we are likely to enter into any future derivative contracts with these or other lenders under our revolving credit facility that also carry investment grade ratings. Master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had our counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $35.6 million against amounts outstanding under our revolving credit facility. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

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