UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

 

Form 10-K/A

Amendment No. 2

 

 

Commission file number 1-33249

 

 

 

 

Legacy Reserves LP
(Exact name of registrant as specified in its charter)

 

 

 

 

 

Registrant’s telephone number, including area code:

(432) 689-5200

 

Securities registered pursuant to Section 12(b) of the Act:

Units representing limited partner interests listed on the NASDAQ Stock Market LLC.

 

Securities registered pursuant to 12(g) of the Act:

None.

 

 

 

 

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

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ

 

The aggregate market value of units held by non-affiliates was approximately $459,526,531 based on the average bid and ask price of the units as of June 29, 2007.

 

29,671,470 units representing limited partner interests in the registrant were outstanding as of March 14, 2008.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Parts of the definitive proxy statement for the registrant’s 2008 annual meeting of unitholders are incorporated by reference into Part III of this annual report on Form 10-K.

 

 

Explanatory Note

 

Legacy Reserves LP filed an Annual Report on Form 10-K with the Securities and Exchange Commission on March 14, 2008 for the fiscal year ended December 31, 2007 (the “Original Filing”) and an amendment to its Form 10-K on March 27, 2008. This Amendment No. 2 amends the Original Filing and the Form 10-K/A filed on March 27, 2008, and is being filed solely for the purpose of correcting a typographical error contained in Exhibit 32.1 of the Original Filing. The remainder of the Form 10-K is unchanged and is reproduced in this Amendment No. 2. This Amendment No. 2 speaks as of the file date of the Original Filing and does not reflect events occurring after the filing date of the Original Filing, or modify or update the disclosures therein in any way other than as required to reflect the amendment described above.

 

LEGACY RESERVES LP

 

Table of Contents

 

 

Bbl.  One stock tank barrel or 42 U.S. gallons liquid volume.

 

Bcf.  Billion cubic feet.

 

Boe.  One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

Boe/d.  Barrels of oil equivalent per day.

 

Btu.  British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

 

Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

Development Project.  A drilling or other project which may target proven reserves, but which generally has a lower risk than that associated with exploration projects.

 

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.

 

Dry hole or 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.

 

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.

 

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.

 

MBbls.  One thousand barrels of crude oil or other liquid hydrocarbons.

 

MBoe.  One thousand barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

Mcf.  One thousand cubic feet.

 

MMBbls.  One million barrels of crude oil or other liquid hydrocarbons.

 

MMBoe.  One million barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

MMBtu.  One million British thermal units.

 

MMcf.  One million cubic feet.

 

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

 

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.  Crude oil, condensate and natural gas liquids.

 

Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

 

Proved developed reserves.  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or

after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

 

Proved developed non-producing or PDNP’s.  Proved oil and natural gas reserves that are developed behind pipe, shut-in or can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

 

Proved reserves.  Proved oil and natural gas reserves are the estimated quantities of natural gas, crude oil and natural gas liquids that geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

 

Proved undeveloped drilling location.  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

 

Proved undeveloped reserves or PUDs.  Proved oil and natural gas reserves that are expected to be recovered from new wells on un-drilled acreage or from existing wells where a relatively major expenditure is required for re-completion. Reserves on un-drilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other un-drilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed 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.

 

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

 

Reserve acquisition cost.  The total consideration paid for an oil and natural gas property or set of properties, which includes the cash purchase price and any value ascribed to units issued to a seller adjusted for any post-closing items.

 

R/P ratio (reserve life).  The reserves as of the end of a period divided by the production volumes for the same period.

 

Reserve replacement.  The replacement of oil and natural gas produced with reserve additions from acquisitions, reserve additions and reserve revisions.

 

Reserve replacement cost.  An amount per BOE equal to the sum of costs incurred relating to oil and natural gas property acquisition, exploitation, development and exploration activities (as reflected in our year-end financial statements for the relevant year) divided by the sum of all additions and revisions to estimated proved reserves, including reserve purchases. The calculation of reserve additions for each year is based upon the reserve report of our independent engineers. Management uses reserve replacement cost to compare our company to others in terms of our historical ability to increase our reserve base in an economic manner. However, past performance does not necessarily reflect future reserve replacement cost performance. For example, increases in oil and natural gas prices in recent years have increased the economic life of reserves adding additional reserves with no required capital expenditures. On the other hand, increases in oil and natural gas prices have increased the cost of reserve purchases and reserves added through development projects. The reserve replacement cost may not be indicative of the economic value added of the reserves due to differing lease operating expenses per barrel and differing timing of production.

 

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.

Standardized measure.  The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of 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.

 

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

 

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

CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING INFORMATION

 

This document contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:

 

 

All of these types of statements, other than statements of historical fact included in this document, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

 

The forward-looking statements contained in this document are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this document are not guarantees of future performance, and our expectations may not be realized or the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in Item 1A. under “Risk Factors.” The forward-looking statements in this document speak only as of the date of this document; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly.

 

References in this annual report on Form 10-K to “Legacy Reserves,” “Legacy,” “we,” “our,” “us,” or like terms prior to March 15, 2006 refer to the Moriah Group, Legacy Reserves LP’s predecessor, including the oil and natural gas properties we acquired in exchange for units and cash from the Moriah Group, the Brothers Group, H2K Holdings, MBN Properties (our “Founding Investors”) and certain charitable foundations in connection with our private equity offering on March 15, 2006. When used for periods from March 15, 2006 forward, those terms refer to Legacy Reserves LP and its subsidiaries.

 

Legacy Reserves LP

 

We are an independent oil and natural gas limited partnership headquartered in Midland, Texas, and are focused on the acquisition and development of oil and natural gas properties primarily located in the Permian Basin and Mid-continent regions of the United States. We were formed in October 2005 to own and operate the oil and natural gas properties that we acquired from our Founding Investors and three charitable foundations in connection with the closing of our private equity offering on March 15, 2006. On January 18, 2007, we completed our initial public offering.

 

Our primary business objective is to generate stable cash flows allowing us to make cash distributions to our unitholders and to increase quarterly cash distributions per unit over time through a combination of acquisitions of new properties and development of our existing oil and natural gas properties.

 

We have grown primarily through two activities: the acquisition of producing oil and natural gas properties and the development of producing properties as opposed to higher risk exploration of unproved properties.

 

Our oil and natural gas production and reserve data as of December 31, 2007 are as follows:

 

 

Recent Developments

 

On November 8, 2007 we closed a private placement of 3,642,369 Units for $20.50 per unit for net proceeds of approximately $73.0 million. We used the net proceeds of the private placement primarily to reduce debt outstanding under or revolving credit facility.

 

Acquisition Activities

 

During the year ended December 31, 2007, we invested approximately $200.4 million, including non-cash asset retirement obligations, in 15 acquisitions of proved oil and natural gas properties. Based on reserve data prepared internally at the time of these acquisitions, we added a total of approximately 14.25 MMBoe of proved reserves at an average reserve acquisition cost of $13.59 per Boe, which excludes associated non-cash asset retirement obligations. The recent acquisitions discussed below are also included in the reserve acquisition cost calculation, along with immaterial acquisitions closed during 2007.

 

On April 16, 2007, Legacy purchased certain oil and natural gas properties and other interests in the East Binger (Marchand) Unit in Caddo County, Oklahoma from Nielson & Associates, Inc. for a net purchase price of $44.2 million (“Binger Acquisition”). The purchase price was paid with the issuance of 611,247 units valued at $15.8 million and $28.4 million paid in cash. The effective date of this purchase was February 1, 2007. The $44.2 million purchase price was allocated with $14.7 million recorded as lease and well equipment, $29.4 million

of leasehold costs and $0.1 million as investment in equity method investee related to the 50% interest acquired in Binger Operations, LLC. Asset retirement obligations of $184,636 were recorded in connection with this acquisition. The operations of these Binger Acquisition properties have been included from their acquisition on April 16, 2007.

 

On May 1, 2007, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Ameristate Exploration, LLC for a net purchase price of $5.2 million (“Ameristate Acquisition”). The effective date of this purchase was January 1, 2007. The $5.2 million purchase price was allocated with $0.5 million recorded as lease and well equipment and $4.7 million of leasehold costs. Asset retirement obligations of $51,414 were recorded in connection with this acquisition. The operations of these Ameristate Acquisition properties have been included from their acquisition on May 1, 2007.

 

On May 25, 2007, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Terry S. Fields for a net purchase price of $14.7 million (“TSF Acquisition”). The effective date of this purchase was March 1, 2007. The $14.7 million purchase price was allocated with $1.8 million recorded as lease and well equipment and $12.9 million of leasehold costs. Asset retirement obligations of $99,094 were recorded in connection with this acquisition. The operations of these TSF Acquisition properties have been included from their acquisition on May 25, 2007.

 

On May 31, 2007, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Raven Resources, LLC and Shenandoah Petroleum Corporation for a net purchase price of $13.0 million (“Raven Shenandoah Acquisition”). The effective date of this purchase was May 1, 2007. The $13.0 million purchase price was allocated with $6.0 million recorded as lease and well equipment and $7.0 million of leasehold costs. Asset retirement obligations of $378,835 were recorded in connection with this acquisition. The operations of these Raven Shenandoah Acquisition properties have been included from their acquisition on May 31, 2007.

 

On August 3, 2007, Legacy purchased certain oil and natural gas properties located primarily in the Permian Basin from Raven Resources, LLC and private parties for a net purchase price of $20.0 million (“Raven OBO Acquisition”). The effective date of this purchase was July 1, 2007. The $20.0 million purchase price was allocated with $1.6 million recorded as lease and well equipment and $18.4 million of leasehold costs. Asset retirement obligations of $224,329 were recorded in connection with this acquisition. The operations of these Raven OBO Acquisition properties have been included from their acquisition on August 3, 2007.

 

On October 1, 2007, Legacy purchased certain oil and natural gas properties located in the Texas Panhandle from The Operating Company, et al, for a net purchase price of $60.5 million (“TOC Acquisition”). The effective date of this purchase was September 1, 2007. The $60.5 million purchase price was allocated with $23.7 million recorded as lease and well equipment and $36.8 million of leasehold costs. Asset retirement obligations of $1.6 million were recorded in connection with this acquisition. The operations of these TOC Acquisition properties have been included from their acquisition on October 1, 2007.

 

Also on October 1, 2007, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Summit Petroleum Management Corporation for a net purchase price of $13.4 million (“Summit Acquisition”). The effective date of this purchase was September 1, 2007. The $13.4 million purchase price was allocated with $2.1 million recorded as lease and well equipment and $11.3 million of leasehold cost. Asset retirement obligations of $128,705 were recorded in connection with this acquisition. The operations of these Summit Acquisition properties have been included from their acquisition on October 1, 2007.

 

During November and December, 2007, Legacy purchased certain oil and natural gas properties from multiple parties in the Permian Basin and Texas Panhandle for an aggregate $17.8 million. The acquisitions have various effective dates. The $17.8 million purchase price was allocated with $4.5 million recorded as lease and well equipment and $13.3 million of leasehold cost. The operations of these acquired properties have been included from their acquisition dates over November and December, 2007.

Development Activities

 

We have also added reserves and production through development projects on our existing and acquired properties. Our development projects include accessing additional productive formations in existing well-bores, formation stimulation, artificial lift equipment enhancement, infill drilling on closer well spacing, secondary (waterflood) and tertiary (miscible CO₂ and nitrogen) recovery projects, drilling for deeper formations and completing unconventional and tight formations.

 

As of December 31, 2007, we identified 109 gross (72.8 net) proved undeveloped drilling locations and 43 gross (16 net) re-completion and re-fracture stimulation projects, over 93% of which we intend to drill and execute over the next four years. Excluding acquisitions, we expect to make capital expenditures of approximately $18.2 million during the year ending December 31, 2008, including drilling 24 gross (17.3 net) development wells and executing 12 gross (5.8 net) re-completions and re-fracture stimulations. We believe that drilling rigs will be available to execute our 2008 development program.

 

Oil and Natural Gas Derivative Activities

 

Our strategy includes entering into oil and natural gas derivative contracts which are designed to mitigate price risk for a majority of our oil, NGL and natural gas production over a three to five-year period. We have entered into these derivative contracts for approximately 73% of our expected oil and natural gas production from total proved reserves for the year ending December 31, 2008. We have also entered into these derivative contracts for approximately 54% of our expected oil and natural gas production from total proved reserves for 2009 through 2012. All of our derivative contracts are in the form of fixed price swaps for NYMEX WTI oil, Mont Belvieu OPIS natural gas liquids components, NYMEX Henry Hub natural gas, West Texas Waha natural gas and ANR-Oklahoma natural gas. In July 2006, we entered into basis swaps to receive floating NYMEX Henry Hub natural gas prices less a fixed basis differential and pay prices based on the floating Waha index, a natural gas hub in West Texas. The prices that we receive for our Permian Basin natural gas sales follow Waha more closely than NYMEX Henry Hub. The basis swaps, thereby, provide a better match between our natural gas sales and the settlement payments on our natural gas swaps. We have entered into basis swaps covering approximately 100% of our NYMEX Henry Hub natural gas basis differential risk on our NYMEX Henry Hub natural gas swaps.

 

Business Strategy

 

The key elements of our business strategy are to:

 

 

Marketing and Major Purchasers

 

For the years ended December 31, 2005, 2006 and 2007, Legacy sold oil and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below:

 

 

Our oil sales prices are based on formula pricing and calculated either using a discount to NYMEX WTI oil or using the appropriate buyer’s posted price, plus Platt’s P-Plus monthly average, plus the Midland-Cushing differential less a transportation fee.

 

If we were to lose any one of our oil or natural gas purchasers, the loss could temporarily cause a loss or deferral of production and sale of our oil and natural gas in that particular purchaser’s service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser. However, if one or more of our larger purchasers ceased purchasing oil or natural gas altogether, the loss of such purchasers could have a detrimental effect on our production volumes in general and on our ability to find substitute purchasers for our production volumes in a timely manner.

 

Competition

 

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry.

 

We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which has delayed development drilling and other development projects and has caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our development program.

 

Seasonal Nature of Business

 

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months thereby affecting the price we receive for natural gas. Seasonal anomalies such as mild winters or hotter than normal summers sometimes lessen this fluctuation.

 

Environmental Matters and Regulation

 

General.  Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

 

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our operations are subject.

 

Waste Handling.  The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non- hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

 

Comprehensive Environmental Response, Compensation and Liability Act.  The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

We currently own, lease, or operate numerous properties that have been used for oil and natural gas development and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

 

Water Discharges.  The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

 

Air Emissions.  The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations.

 

National Environmental Policy Act.  Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

 

OSHA and Other Laws and Regulation.  We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in compliance with these applicable requirements and with other OSHA and comparable requirements.

 

Recent studies have suggested that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention of Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil and natural gas, and refined petroleum products, are “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. For example, California adopted the “California Global Warming Solutions Act of 2006,” which required the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states of the United States could adversely affect our operations and demand for our products. Additionally, the U.S. Supreme Court only recently held in a case, Massachusetts, et al. v. EPA, that greenhouse gases fall within the federal Clean Air Act’s definition of “air pollutant,” which could result in the regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

 

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2007. Additionally, as of the date of this document, we are not aware of any environmental issues or claims that require material capital expenditures during 2008. However, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operation.

 

Other Regulation of the Oil and Natural Gas Industry

 

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

 

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

Drilling and Production.  Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

 

 

State laws regulate the size and shape of drilling and spacing units or pro-ration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

 

Natural gas regulation.  The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

 

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

 

State regulation.  The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

 

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

 

Employees

 

As of December 31, 2007, we had 58 full-time employees, including nine petroleum engineers, six accountants and two landmen, none of whom are subject to collective bargaining agreements. We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed. We believe that we have a favorable relationship with our employees.

 

Offices

 

We currently lease approximately 32,153 square feet of office space in Midland, Texas at 303 W. Wall Street, Suite 1400, where our principal offices are located. The lease for our Midland office expires in August 2011.

 

Risks Related to our Business

 

We may not have sufficient available cash to pay the full amount of our current quarterly distribution or any distribution at all following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

 

We may not have sufficient available cash each quarter to pay the full amount of our current quarterly distribution or any distribution at all. The amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than our current quarterly distribution. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserves that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. Further, our debt agreements contain restrictions on our ability to pay distributions. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

 

If we are not able to acquire additional oil and natural gas reserves on economically acceptable terms, our reserves and production will decline, which would adversely affect our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.

 

We will be unable to sustain distributions at the current level without making accretive acquisitions or substantial capital expenditures that maintain or grow our asset base. Oil and natural gas reserves are characterized by declining production rates, and our future oil and natural gas reserves and production and, therefore, our cash flow and our ability to make distributions are highly dependent on our success in economically finding or acquiring additional recoverable reserves and efficiently developing and exploiting our current reserves. Further, the rate of estimated decline of our oil and natural gas reserves may increase if our wells do not produce as expected. We may not be able to find, acquire or develop additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Because we distribute all of our available cash to our unitholders, our future growth may be limited.

 

Since we will distribute all of our available cash as defined in our partnership agreement to our unitholders, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. We will depend on financing provided by commercial banks and other lenders and the issuance of debt and equity securities to finance any significant growth or acquisitions. If we are unable to obtain adequate financing from these sources, our ability to grow will be limited.

If commodity prices decline significantly for a prolonged period, we may be forced to reduce our distribution or not be able to pay distributions at all.

 

A significant decline in oil and natural gas prices over a prolonged period would have a significant impact on the value of our reserves and on our cash flow, which would force us to reduce or suspend our distribution. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

 

In the past, the prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue.

 

If commodity prices decline significantly for a prolonged period, a significant portion of our development projects may become uneconomic, which may adversely affect our ability to make distributions to our unitholders.

 

Lower oil and natural gas prices may not only decrease our revenues, but also reduce the amount of oil and natural gas that we can produce economically. Furthermore, substantial decreases in oil and natural gas prices as were experienced as recently as 2002, when prices of less than $20.00 per Bbl of oil and $2.00 per Mcf of natural gas were received at the wellhead, would render a significant portion of our development projects uneconomic. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility to pay distributions to our unitholders.

 

Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Our credit facility has substantial restrictions and financial covenants, and our borrowing base is subject to redetermination by our lenders which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

We will depend on our revolving credit facility for future capital needs. Our revolving credit facility restricts, among other things, our ability to incur debt and pay distributions, and requires us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under our revolving credit facility could result in a default under our revolving credit facility. A default under our revolving credit facility could cause all of our existing indebtedness to be immediately due and payable. Additionally, our revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion.

 

We are prohibited from borrowing under our revolving credit facility to pay distributions to unitholders if the amount of borrowings outstanding under our revolving credit facility reaches or exceeds 90% of the borrowing base, which is the amount of money available for borrowing, as determined semi-annually by our lenders in their sole discretion. The lenders will redetermine the borrowing base based on an engineering report with respect to our oil and natural gas reserves, which will take into account the prevailing oil and natural gas prices at such time. Any time our borrowings exceed 90% of the then specified borrowing base, our ability to pay distributions to our unitholders in any such quarter is solely dependent on our ability to generate sufficient cash from our operations.

 

Outstanding borrowings in excess of the borrowing base must be repaid, and, if mortgaged properties represent less than 80% of total value of oil and gas properties used to determine the borrowing base, we must pledge other oil and natural gas properties as additional collateral. We may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility.

 

The occurrence of an event of default or a negative redetermination of our borrowing base could adversely affect our business, results of operations, financial condition and our ability to make distributions to our unitholders.

 

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities.”

 

Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the oil and natural gas we produce.

 

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Our development projects require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.

 

We make and expect to continue to make substantial capital expenditures in our business for the development, development, production and acquisition of oil and natural gas reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:

 

 

 

If our revenues or the borrowing base under our credit facility decrease as a result of lower oil and/or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility restricts our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

We do not control all of our operations and development projects and failure of an operator of wells in which we own partial interests to adequately perform could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Much of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas wells.

 

If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The success and timing of our development projects on properties operated by others is outside of our control.

 

The failure of an operator of wells in which we own partial interests to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues and could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Shortages of drilling rigs, equipment and crews could delay our operations, adversely affect our ability to increase our reserves and production and reduce our cash available for distribution to our unitholders.

 

Higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues and cash available for distribution to our unitholders.

 

Increases in the cost of drilling rigs, service rigs, pumping services and other costs in drilling and completing wells could reduce the viability of certain of our development projects.

 

The rig count and the cost of rigs and oil field services necessary to implement our development projects have risen significantly with the increases in oil and natural gas prices. Increased capital requirements for our projects will result in higher reserve replacement costs which could reduce cash available for distribution. Higher project costs could cause certain of our projects to become uneconomic and therefore not to be implemented, reducing our production and cash available for distribution.

 

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.

In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

 

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

 

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Increases in interest rates could adversely affect our business, results of operations, cash flows from operations and financial condition.

 

Since all of the indebtedness outstanding under our credit facility is at variable interest rates, we have significant exposure to increases in interest rates. As a result, our business, results of operations and cash flows may be adversely affected by significant increases in interest rates. Further, an increase in interest rates may cause a corresponding decline in demand for equity investments, in particular for yield-based equity investments such as our units. Any reduction in demand for our units resulting from other more attractive investment opportunities may cause the trading price of our units to decline.

 

We may have assumed unknown liabilities in connection with the formation transactions and our subsequent acquisitions.

 

As part of the formation transactions and subsequent acquisitions, our properties may be subject to existing liabilities, some of which may have been unknown at the closing of such transactions. Unknown liabilities might include liabilities for cleanup or remediation of undisclosed or unknown environmental conditions, claims of vendors or other persons (that had not been asserted or threatened prior to the closing of such transactions), tax liabilities and accrued but unpaid liabilities incurred in the ordinary course of business.

Properties that we buy may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

 

One of our growth strategies is to acquire additional oil and natural gas reserves. However, our reviews of acquired properties are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.

 

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

Our management team has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may be materially different from those presently identified, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Our commodity derivative activities could result in cash losses, could reduce our cash available for distributions and may limit potential gains.

 

We have entered into, and we may in the future enter into, oil and natural gas derivative contracts intended to offset the effects of price volatility related to a significant portion of our oil and natural gas production. Many derivative instruments that we employ require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices.

 

If our actual production and sales for any period are less than our expected production covered by derivative contracts and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our derivative contracts without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in derivative activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the derivative. Under our credit facility, we are prohibited from entering into derivative contracts covering all of our production, and we therefore retain the risk of a price decrease on our volumes not subject to derivative contracts.

 

The inability of one or more of our customers to meet their obligations may adversely affect our financial condition and results of operations.

 

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties.

We depend on a limited number of key personnel who would be difficult to replace.

 

Our operations are dependent on the continued efforts of our executive officers, senior management and key employees. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy.

 

We may be unable to compete effectively with larger companies, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration and development activities during periods of low oil and natural gas market prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

 

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our units.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. All such costs may have a negative effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for and the production of,

oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

 

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

 

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our ability to make cash distributions to our unitholders could be adversely affected.

 

Risks Related to Our Limited Partnership Structure

 

Units eligible for future sale may have adverse effects on our unit price and the liquidity of the market for our units.

 

We cannot predict the effect of future sales of our units, or the availability of units for future sales, on the market price of or the liquidity of the market for our units. Sales of substantial amounts of units, or the perception that such sales could occur, could adversely affect the prevailing market price of our units. Such sales, or the possibility of such sales, could also make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. Factors affecting the likely volume of future sales of our units, and the possible consequences of such sales, include the following:

 

 

Our Founding Investors, including members of our management, own a 43% limited partner interest in us and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest and limited fiduciary duties, which may permit it to favor its own interests to the detriment of our unitholders.

 

Our Founding Investors, including members of our management, own a 43% limited partner interest in us and therefore have the ability to effectively control the election of the entire board of directors of our general partner.

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners, our Founding Investors and their affiliates. Conflicts of interest may arise between our Founding Investors and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

 

Even if unitholders are dissatisfied they cannot remove our general partner without the consent of unitholders owning at least 662/3% of our units, including units owned by our general partner and its affiliates.

 

Currently, the unitholders are unable to remove our general partner without its consent because our general partner’s affiliates own sufficient units to be able to prevent our general partner’s removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Affiliates of our general partner, including members of our management, own 43% of our units.

Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our units.

 

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

Our Founding Investors and their affiliates (other than our executive officers and their affiliates) may compete directly with us.

 

Our Founding Investors and their affiliates, other than our general partner and our executive officers and their affiliates, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our Founding Investors or their affiliates, other than our general partner and our executive officers and their affiliates, may acquire, develop and operate oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to acquire, develop or operate those assets.

 

Cost reimbursements due our general partner and its affiliates will reduce our cash available for distribution to our unitholders.

 

Prior to making any distribution on our outstanding units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Any such reimbursement will be determined by our general partner in its sole discretion. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. The reimbursement of expenses of our general partner and its affiliates could adversely affect our ability to pay cash distributions to our unitholders.

 

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

 

 

Our partnership agreement permits our general partner to redeem any partnership interests held by a limited partner who is a non-citizen assignee.

 

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, our general partner may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, our general partner may elect to treat the limited partner as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

 

We may issue an unlimited number of additional units without the approval of our unitholders, which would dilute their existing ownership interest in us.

 

Our general partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional units. The issuance by us of additional units or other equity securities of equal or senior rank will have the following effects:

 

 

The liability of our unitholders may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. In some states, including Delaware, a limited partner is only liable if he participates in the “control” of the business of the partnership. These statutes generally do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the partnership, the admission or removal of the general partner and the amendment of the partnership agreement. Our unitholders could, however, be liable for any and all of our obligations as if our unitholders were a general partner if:

 

 

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the distribution, limited partners who received an impermissible distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such substitute limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

Tax Risks to Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by states and localities. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of additional entity-level taxation for state or local tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

 

The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35%, and would likely pay state and local income tax at the corporate tax rate of the various states and localities imposing a corporate income tax. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders likely causing a substantial reduction in the value of our units.

 

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are subject to a new entity-level state tax on the portion of our income that is generated in Texas beginning for tax reports due on or after January 1, 2008. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas. If any additional states were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced.

 

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, or Qualifying Income Exception, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income

under Section 7704(d) of the Internal Revenue Code. Legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

 

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

 

Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the costs of any contest will reduce our cash available for distribution to our unitholders.

 

We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions or the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may disagree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and thus will be borne indirectly by our unitholders.

 

Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.

 

Investment in our units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

 

Tax gain or loss on the disposition of our units could be more or less than expected because prior distributions in excess of allocations of income will decrease our unitholders tax basis in their units.

 

If our unitholders sell any of their units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to our unitholders in excess of the total net

taxable income they were allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the unit is sold at a price greater than their tax basis in that unit, even if the price our unitholders receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to our unitholders. In addition, if our unitholders sell their units, our unitholders may incur a tax liability in excess of the amount of cash our unitholders receive from the sale.

 

We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

 

Because we cannot match transferors and transferees of units, we will adopt depletion, depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of units and could have a negative impact on the value of our units or result in audits of and adjustments to our unitholders’ tax returns.

 

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan may recognize gain or loss from the disposition.

 

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where our units are loaned to a short seller to cover a short sale of our units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.

 

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently do business and own assets in Texas, New Mexico, Oklahoma, Alabama, Mississippi, Wyoming, North Dakota, Colorado and Arkansas. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our units.

 

We will be considered to have terminated for tax purposes due to a sale or exchange of 50% or more of our interests within a twelve-month period.

 

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

 

None.

 

 

As of December 31, 2007 we owned interests in producing oil and natural gas properties in 214 fields in the Permian Basin, Texas Panhandle and Anadarko Basin of Oklahoma, operated 1,547 gross productive wells and owned non-operated interests in 2,207 gross productive wells. The following table sets forth information about our proved oil and natural gas reserves as of December 31, 2007. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. For a definition of “standardized measure” please see the glossary of terms at the beginning of this annual report on Form 10-K.

 

 

 

 

Summary of Oil and Natural Gas Properties and Projects

 

Our most significant fields are the Texas Panhandle, Spraberry, East Binger, Denton, Farmer, Langlie Mattix and Howard Glasscock/Iatan/Iatan East Howard. As of December 31, 2007 these seven fields accounted for approximately 56.7% of our total estimated proved reserves.

 

Texas Panhandle Fields.  In October of 2007, Legacy Reserves acquired producing properties in the Texas Panhandle fields located in Carson, Gray, Hartley, Hutchinson, Moore, and Potter Counties, Texas, in two acquisitions. The fields are produced from multiple formations of Permian age which primarily include the Granite Wash, Brown Dolomite, and Red Cave formations from 2,500 to 4,000 feet. Legacy operates 277 wells (263 producing, 14 injecting) in the Texas Panhandle fields with working interests ranging from 81.3% to 100% and net revenue interests ranging from 69.3% to 100.0%. We also own another 271 wells (268 producing, 3 injecting) with a 3.8% average non-operated working interest. As of December 31, 2007, our properties in the Texas Panhandle fields contained 4.6 MMBoe (81% liquids) of net proved reserves with a standardized measure of $86.9 million. The average net daily production from these fields was 1,086 Boe/d in December 2007. The estimated reserve life (R/P) for these fields is 19 years.

 

Spraberry Field.  The Spraberry field is located in Midland, Martin, Reagan and Upton counties, Texas. This field produces from Spraberry and Wolfcamp age formations from 5,000 to 10,200 feet. We operate 127 active wells in this field with working interests ranging from 4.0% to 100% and net revenue interests ranging from 4.0% to 90.8%. We have a 1.3% overriding royalty interest in one non-operated unit in the Spraberry field. We also have three lease line wells outside the non-operated unit with a working interest of 12.5% and a net revenue interest of 9.4%. As of December 31, 2007, our properties in the Spraberry field contained 3.6 MMBoe (67% liquids) of net

proved reserves with a standardized measure of $84.7 million. The average net daily production from this field was 586 Boe/d for the fourth quarter of 2007. The estimated reserve life for this field is 14 years.

 

Six operated and three non-operated wells were drilled on Legacy Reserves’ properties in the Spraberry Field in 2007. We have identified eleven more proved undeveloped projects and eight behind-pipe or proved developed non-producing (“PDNP”) re-completion projects in this field.

 

East Binger Field.  In April 2007, Legacy Reserves acquired producing properties in the East Binger field located in Caddo County, Oklahoma. This field which is on the Northeastern shelf of the Anadarko Basin was discovered in 1935 and through December 31, 2007, our properties in this field had gross cumulative production of 22.0 MMBbls of oil and 130.5 Bcf of natural gas. The Marchand Sand, at depths of 9,700 to 10,100 feet, is the primary reservoir in the East Binger Field. The East Binger Unit, the major property in the field, is an active miscible nitrogen injection project and is operated by Binger Operations, LLC (BOL) of which Legacy owns 50%. BOL operates 91 wells in the East Binger field and Legacy Reserves owns a working interest of 54.5% and net revenue interest of 45.8% in the East Binger Unit. As of December 31, 2007, our properties in the East Binger field contained 3.4 MMBoe (83% liquids) of net proved reserves with a standardized measure of $77.0 million. The average net daily production from this field was 812 Boe/d for the fourth quarter of 2007. The estimated reserve life (R/P) for the field is 13 years.

 

Two infill wells were drilled in the East Binger Unit in 2007 and we have nine more proved undeveloped projects identified in this field.

 

Denton Field.  The Denton field is an oil and natural gas field located in Lea County, New Mexico. The Devonian Formation at depths of 11,000 to 12,700 feet is the primary reservoir in the Denton field. Additional production has been developed in the Wolfcamp Formation at depths of 8,900 to 9,600 feet. We operate 17 wells in the Denton field with working interests ranging from 86% to 100% and net revenue interests ranging from 75.1%to 87.5%. We also own another 6 producing wells with a 15.0% average non-operated working interest. As of December 31, 2007, our properties in the Denton field contained 2.2 MMBoe (87% liquids ) of net proved reserves with a standardized measure of $48.1 million. The average net daily production from this field was 390 Boe/d for the fourth quarter of 2007. The estimated reserve life (R/P) for the field is 16 years.

 

Farmer Field.  The Farmer field is an oil and natural gas field located in Crockett and Reagan counties, Texas. The San Andres Formation at depths of 2,100 to 2,600 feet is the primary reservoir in the Farmer field. We operate 156 wells (148 producing, 8 injecting) in the Farmer field with a 100.0% average working interest and a net revenue interest ranging from 80.8% to 87.5%. As of December 31, 2007, our properties in the Farmer field contained 1.8 MMBoe (66% liquids) of net proved reserves with a standardized measure of $30.9 million. The average net daily production from this field was 275 Boe/d for the fourth quarter of 2007. The estimated reserve life (R/P) for the field is 19 years.

 

The Farmer field has been developed using 20-acre spacing with the exception of a pilot 10-acre spacing area that includes eleven 10-acre wells. We currently have 33 10-acre proved undeveloped locations in this field and an additional 84 unproved 10-acre locations.

 

Langlie Mattix Field.  The Langlie Mattix field is an oil and natural gas field located in Lea County, New Mexico. The Queen Formation at depths of 3,400 to 3,800 feet is the primary reservoir in the Langlie Mattix field. We operate 104 wells (76 producing, 28 injecting) in the Langlie Mattix Penrose Sand Unit, a subdivision of the Langlie Mattix Field, with a 51.7% average working interest and a 44.7% average net revenue interest. We also operate two other properties with 100% and 82.4% working interests and 82.0% and 67.4% net revenue interests. As of December 31, 2007, our properties in the Langlie Mattix field contained 1.3 MMBoe (85% liquids) of net proved reserves with a standardized measure of $29.2 million. The average net daily production from this field was 218 Boe/d for the fourth quarter of 2007. The estimated reserve life (R/P) for the field is 17 years.

 

The Langlie Mattix Penrose Sand Unit was drilled in the late 1930s and early 1940s on 40-acre spacing. Waterflooding commenced in 1958. Prior to 2007 there had been 14 20-acre infill wells drilled on the Unit; five drilled in 1983, three drilled in 1992, and six drilled in 2004. All three 20-acre infill programs were successful. We drilled twelve 20-acre infill wells in 2007 and have 23 more proved undeveloped locations and an additional 55 unproved 20-acre locations.

Howard Glasscock, Iatan and Iatan East Howard Fields.  The Howard Glasscock, Iatan and Iatan East Howard fields adjoin one another and are located in Howard and Mitchell counties, Texas. These fields produce from multiple formations of Permian age which primarily include the San Andres, Yates, Seven Rivers, Queen, Clearfork and Glorieta Formations from 1,000 to 3,700 feet as well as the Wolfcamp and Canyon Formations from 5,100 to 7,400 feet. We operate 125 wells (115 producing, 10 injecting) in these fields with working interests ranging from 62.5% to 100.0% and net revenue interests ranging from 47.3% to 90.0%. As of December 31, 2007, our properties in the Howard Glasscock, Iatan and Iatan East Howard fields contained 1.3 MMBoe (99% liquids) of net proved reserves with a standardized measure of $26.7 million. The average net daily production from these fields was 208 Boe/d for the fourth quarter of 2007. The estimated reserve life (R/P) for these fields is 17 years.

 

Oil and Natural Gas Data

 

Proved Reserves

 

The following table sets forth a summary of information related to our estimated net proved reserves as of the dates indicated based on reserve reports prepared by LaRoche Petroleum Consultants, Ltd. The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency. Standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.

 

 

 

 

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

 

The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. Please read “Risk Factors — Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

 

From time to time, we engage LaRoche Petroleum Consultants, Ltd. to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither LaRoche Petroleum Consultants, Ltd. nor any of its employees has any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties. During 2006 and 2007, we paid LaRoche Petroleum Consultants, Ltd. approximately $246,992 and $143,900, respectively, for such reserve and economic evaluations.

Production and Price History

 

The following table sets forth a summary of unaudited information with respect to our production and sales of oil and natural gas for the periods indicated, including the historical data of Legacy Reserves LP (formerly the Moriah Group) as of December 31, 2005, 2006 and 2007. The 2006 data reflects Legacy’s purchase of the oil and natural gas properties acquired in the formation transactions and the South Justis, Farmer Field and Kinder Morgan acquisitions. The 2007 data reflects Legacy’s purchase of the oil and natural gas properties acquired in the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit acquisitions:

 

 

 

 

Productive Wells

 

The following table sets forth information at December 31, 2007 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.

 

 

Developed and Undeveloped Acreage

 

The following table sets forth information as of December 31, 2007 relating to our leasehold acreage.

 

 

 

 

Drilling Activity

 

The following table sets forth information, on a combined basis, with respect to wells completed by Legacy, the Moriah Group, Brothers Group, H2K, and the charitable foundations, during the years ended December 31, 2005, 2006 and 2007. The drilling activities associated with the PITCO properties are included for all periods subsequent to the acquisition date of September 14, 2005. The drilling activities associated with the properties acquired in the Farmer Field acquisition (June 29, 2006), the South Justis acquisition (June 29, 2006) and the Kinder Morgan acquisition (July 31, 2006) are included for all periods subsequent to those acquisition dates. The drilling activities associated with the properties acquired in the Binger acquisition (April 16, 2007), the Ameristate acquisition (May 1, 2007), the TSF acquisition (May 25, 2007), the Raven Shenandoah acquisition (May 31, 2007), the Raven OBO acquisition (August 3, 2007), the TOC acquisition (October 1, 2007) and the Summit acquisition (October 1, 2007) are included for all periods subsequent to those acquisition dates. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil and natural gas, regardless of whether they produce a reasonable rate of return.

 

 

Summary of Development Projects

 

We are currently pursuing an active development strategy. We estimate that our capital expenditures for the year ending December 31, 2008 will be approximately $18.2 million for development drilling, re-completions and re-fracture stimulation and other development related projects to implement this strategy. We intend to drill 24 gross (17.3 net) development wells and execute 12 gross (5.8 net) re-completions and re-fracture simulations projects. All of these development projects are located in the Permian Basin and the East Binger field in Oklahoma.

 

Operations

 

General

 

We operate approximately 61% of our net daily production of oil and natural gas. We design and manage the development, re-completion or work-over for all of the wells we operate and supervise operation and maintenance activities. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate except for two single pole pulling units used for shallow well work in the Panhandle fields. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ drilling, production, and reservoir engineers, geologists and other specialists who have worked and will work to improve production rates, increase reserves, and lower the cost of operating our oil and natural gas properties. We charge

the non-operating partners an operating fee for operating the wells, typically on a fee per well operated basis. Our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies.

 

Oil and Natural Gas Leases

 

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. In the Permian Basin this amount generally ranges from 12.5% to 33.7% resulting in a 87.5% to 66.3% net revenue interest to us. Most of our leases are held by production and do not require lease rental payments.

 

South Justis Unit Operating Agreement

 

In connection with our acquisition of the South Justis Unit from Henry Holding LP on June 29, 2006, we became the successor in interest to Henry Holding LP as unit operator under the Unit Operating Agreement. As unit operator, we are entitled to receive from the other working interest owners a per well operating fee which we expect to be an aggregate of $1.7 million annually and is subject to an annual cost escalator. Under the terms of the Unit Agreement, we may be removed as unit operator upon default or failure to perform our duties by a vote of two or more working interest owners representing at least 80% of the working interest other than the interest held by us. In the event that we transfer our working interest ownership, we will be removed as unit operator.

 

Derivative Activity

 

We enter into derivative transactions with unaffiliated third parties with respect to oil and natural gas prices to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. All of our derivative transactions in place are NYMEX financial swaps, which do not require option premiums. Our derivatives either swap floating prices for fixed prices indexed on NYMEX for oil, NGL and natural gas or swap the NYMEX index price to an index that reflects a geographical area of production, in our case, the Waha natural gas and ANR-Oklahoma natural gas indices. We enter into derivative transactions with respect to LIBOR interest rates to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in LIBOR interest rates. All of our interest rate derivative transactions are LIBOR interest rate swaps, which do not require option premiums. Our derivatives swap floating LIBOR rates for fixed rates. For a more detailed discussion of our derivative activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations” and “— Quantitative and Qualitative Disclosures About Market Risk.”

 

Title to Properties

 

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title opinions have been obtained on a significant portion of our properties.

 

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

 

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this document.

 

 

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

 

 

None.

 

 

Our units, which were first offered and sold to the public on January 12, 2007, are listed on the NASDAQ Global Select Market under the symbol “LGCY”. As of March 14, 2008, there were 29,670,887 units outstanding, held by approximately 73 holders of record, including units held by our Founding Investors.

 

The following table presents the high and low sales prices for our units during the periods indicated (as reported on the NASDAQ Global Select Market) and the amount of the quarterly cash distributions we paid on each of our units with respect to such periods.

 

 

 

 

 

Distribution Policy

 

We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as available cash, which is defined in our partnership agreement. We currently pay quarterly cash distributions of $0.45 per unit.

 

Recent Sales of Unregistered Securities

 

In October 2005, in connection with the formation of Legacy Reserves LP, we issued to Moriah Resources, Ltd. the 99.9% limited partner interest in Legacy Reserves LP for $999. The issuance was exempt from registration under Section 4(2) of the Securities Act because the transaction did not involve a public offering.

 

In connection with our formation transactions on March 15, 2006, we issued units to our Founding Investors contributing oil and natural gas properties and related assets to us. The issuances of the units described below was exempt from registration under Section 4(2) of the Securities Act because the issuances did not involve a public offering. The following table summarizes the issuance of our units in the formation transactions:

 

 

On March 15, 2006, we issued an aggregate of 52,616 restricted units to certain members of management pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuances of these units were exempt from the registration requirements of the Securities Act pursuant to Rule 701.

 

On March 15, 2006, we issued 5,000,000 units in a private offering for an aggregate consideration of $85 million before the initial purchaser’s discount, placement agent’s fees and expenses to qualified institutional investors and accredited investors in transactions exempt from registration under Section 4(2) of the Securities Act. We paid Friedman, Billings, Ramsey & Co., Inc., who acted as placement agent and initial purchaser in this transaction, $5.95 million in initial purchaser’s discount and placement agent’s fees.

 

On May 1, 2006, we issued 8,750 units in the aggregate to certain of the directors of our general partner pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuances of these units were exempt from the registration requirements of the Securities Act pursuant to Rule 701.

 

On May 5, 2006, we issued 12,500 restricted units to an employee pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuance of these units was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

 

On June 29, 2006, and November 10, 2006 we issued 138,000 units and 8,415 units, respectively, to Henry Holding LP as partial consideration for our acquisition of oil and natural gas producing properties located in Lea County New Mexico and contract operating rights for total consideration of approximately $13.4 million cash and 146,415 units. The issuances of these units were exempt from registration under Section 4(2) of the Securities Act because the issuances did not involve a public offering.

 

On July 17, 2006, we issued options to purchase 251,000 units, at an exercise price of $17.00, to employees and officers pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuance of these options were exempt from the registration requirements of the Securities Act pursuant to Rule 701.

On September 15, 2006, we issued options to purchase 10,000 units, at an exercise price of $17.00, to an employee pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuance of these options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

 

On October 10, 2006 we issued options to purchase 12,000 units, at an exercise price of $17.25, to employees pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuance of these options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

 

On January 11, 2007 we issued options to purchase 9,000 units, at an exercise price of $19.00, to employees pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuance of these options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

 

On January 30, 2007, we issued 95,000 units in consideration for our acquisition of producing oil and natural gas properties in West Texas. The issuance of these units was exempt from registration under Section 4(2) of the Securities Act because the issuance did not involve a public offering.

 

On April 16, 2007, we issued 611,247 units in consideration for our acquisition of producing oil and natural gas properties in the East Binger (Marachand) Unit in Caddo County, Oklahoma. The issuance of these units was exempt from registration under Section 4(2) of the Securities Act because the issuance did not involve a public offering.

 

On November 8, 2007, we issued 3,642,369 units in a private offering for an aggregate consideration of $74.7 million before placement agent’s fees and expenses to qualified institutional investors and accredited investors in transactions exempt from registration under Section 4(2) of the Securities Act.  We paid RBC Capital Markets $1.5 million in placement agent’s fees.

 

 

We were formed in October 2005. Upon completion of our private equity offering and as a result of the related formation transactions on March 15, 2006, we acquired oil and natural gas properties and business operations from the Founding Investors and the three charitable foundations. Although we were the surviving entity for legal purposes, the formation transactions were treated as a purchase with Moriah Properties, Ltd. and its affiliates, or the Moriah Group, being considered, on a combined basis, as the acquiring entity for accounting purposes. As a result, Legacy Reserves LP (formerly the Moriah Group) applied the purchase method of accounting to the separable assets, and the liabilities of the oil and natural gas properties acquired from the Founding Investors (other than the Moriah Group) and the charitable foundations. Our historical financial statements for periods prior to March 15, 2006 only reflect the accounts of the Moriah Group.

 

The following table shows selected historical financial and operating data for Legacy Reserves LP for the periods and as of the dates indicated. Through March 15, 2006, Legacy’s accompanying consolidated historical financial statements reflect the accounts of the Moriah Group, which includes the accounts of Moriah Resources, Inc. as the general partner of Moriah Properties, Ltd., Moriah Properties, Ltd., the oil and natural gas interests individually owned by Dale A. and Rita Brown until October 1, 2005 when those interests were transferred to DAB Resources, Ltd., DAB Resources, Ltd. and the accounts of MBN Properties LP. The Moriah Group consolidated MBN Properties LP as a variable interest entity with the portion of net income (loss) applicable to the other owners’ equity interests being eliminated through a non-controlling interest adjustment. Although MBN Management, LLC, the general partner of MBN Properties LP, is also a variable interest entity, it was accounted for by the Moriah Group using the equity method. From March 15, 2006, Legacy’s historical financial statements also include the results of operations of the oil and natural gas properties acquired from the other Founding Investors and the charitable foundations.

 

The selected historical financial data of the Moriah Group for the years ended December 31, 2003, 2004 and 2005 are derived from the audited consolidated financial statements of Legacy.

 

The operating results of the PITCO properties have been included from their September 14, 2005 acquisition date. The operating results of the Farmer Field, South Justis and Kinder Morgan acquisition properties have been included from their acquisition dates in June and July 2006. The operating results of the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit acquisition properties have been included from their acquisition dates.

You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Legacy’s financial statements and related notes included elsewhere in this annual report on Form 10-K.

 

 

 

 

 

 

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the accompanying financial statements and related notes included elsewhere in annual report on Form 10-K. 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 include, but are not limited to, market prices for natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

 

Overview

 

We were formed in October 2005. Upon completion of our private equity offering and as a result of the related formation transactions on March 15, 2006, we acquired oil and natural gas properties and business operations from our Founding Investors and three charitable foundations (“Legacy Formation”). Although we were the surviving entity for legal purposes, the formation transactions are treated as a purchase with Moriah Properties, Ltd. and its affiliates, or the Moriah Group, being considered, on a combined basis, as the acquiring entity for accounting purposes. Therefore, the accounts reflected in our historical financial statements prior to March 15, 2006 are those of the Moriah Group.

 

The Moriah Group owned and operated oil and natural gas producing properties located primarily in the Permian Basin of West Texas and southeast New Mexico. The Moriah Group included the accounts of Moriah Resources, Inc. as the general partner of Moriah Properties, Ltd., the oil and natural gas interests individually owned by Dale A. and Rita Brown until October 1, 2005 when those interests were transferred to DAB Resources, Ltd., DAB Resources, Ltd. and the accounts of MBN Properties LP. The Moriah Group consolidated MBN Properties LP as a variable interest entity with the portion of net income (loss) applicable to the other owners’ equity interests eliminated through a non-controlling interest adjustment. Although MBN Management, LLC, the general partner of MBN Properties LP, is also a variable interest entity, it was accounted for by the Moriah Group using the equity method.

 

Because of our rapid growth through acquisitions and development of properties, historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results. Since the PITCO properties were not acquired until September 14, 2005, the results of operations only include the operating results for the PITCO properties from September 14, 2005. The operating results of the properties acquired in the formation transactions are included in the results of operations from March 15, 2006, the operating results of the South Justis Unit properties and the Farmer Field properties acquired on June 29, 2006 have been included from July 1, 2006 and the operating results of the Kinder Morgan properties have been included from August 1, 2006. The operating results of the properties acquired in the Binger Acquisition are included in the results of operations from April 16, 2007, the operating results of the Ameristate Acquisition have been included from May 1, 2007, the operating results of the TSF Acquisition have been included from May 25, 2007, the operating results of the Raven Shenandoah Acquisition have been included from May 31, 2007, the operating results of the Raven OBO Acquisition have been included from August 3, 2007 and the operating results from the TOC and Summit Acquisitions have been included from October 1, 2007.

 

Acquisitions have been financed with a combination of proceeds from bank borrowings and issuances of units and cash flow from operations. Post-acquisition activities are focused on evaluating and exploiting the acquired properties and evaluating potential add-on acquisitions.

 

Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future.

Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

 

Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs. Given the inherent volatility of oil and natural gas prices, which are influenced by many factors beyond our control, we plan our activities and budget based on sales price assumptions which historically have been lower than the average sales prices received. We focus our efforts on increasing oil and natural gas production and reserves while controlling costs at a level that is appropriate for long-term operations.

 

We face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. We attempt to overcome this natural decline by utilizing multiple types of recovery techniques such as secondary (water-flood) and tertiary (CO₂) recovery methods to re-pressure the reservoir and recover additional oil, drilling to find additional reserves, re-stimulating existing wells and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on adding reserves through acquisitions and development projects. Our ability to add reserves through acquisitions and development projects is dependent upon many factors including our ability to raise capital, obtain regulatory approvals and contract drilling rigs and personnel.

 

Our revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. As set forth under “Cash Flow from Operations” below, we have hedged a significant portion of our expected production, which allows us to mitigate, but not eliminate, oil and natural gas price risk. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in oil and natural gas prices will affect our ability to execute our capital investment programs and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in oil and natural gas prices may have on the value of our proved reserves and their impact, if any, on any re-determination to our borrowing base under our credit facility.

 

Legacy does not specifically designate derivative instruments as cash flow hedges; therefore, the mark-to-market adjustment reflecting the unrealized gain or loss associated with these instruments is recorded in current earnings.

 

Production and Operating Costs Reporting

 

We strive to increase our production levels to maximize our revenue and cash available for distribution. Additionally, we continuously monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we continuously monitor our production and operating costs per well to determine if any wells or properties should be shut in, re-completed or sold.

 

Such costs include, but are not limited to, the cost of electricity to lift produced fluids, chemicals to treat wells, field personnel to monitor the wells, well repair expenses to restore production, well work-over expenses intended to increase production and ad valorem taxes. We incur and separately report severance taxes paid to the states and counties in which our properties are located. These taxes are reported as production taxes and are a percentage of oil and natural gas revenue. Ad valorem taxes are a percentage of property valuation. Gathering and transportation costs are generally borne by the purchasers of our oil and natural gas as the price paid for our products reflects these costs.

Operating Data

 

The following table sets forth selected financial and operating data of Legacy for the periods indicated.

 

 

 

 

 

Results of Operations

 

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

 

Legacy’s revenues from the sale of oil were $83.3 million and $45.4 million for the years ended December 31, 2007 and 2006, respectively. Legacy’s revenues from the sale of NGL’s were $7.5 million for the year ended December 31, 2007. Legacy had no revenues from NGL sales for the year ended December 31, 2006. Legacy’s revenues from the sale of natural gas were $21.4 million and $14.4 million for the years ended December 31, 2007 and 2006, respectively. The $37.9 million increase in oil revenues reflects an increase in oil production of 430 MBbls (57%) due primarily to Legacy’s purchase of the oil and natural gas properties acquired in the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions while the realized price increased $10.10 per Bbl. The $7.5 million increase in NGL revenues is due to Legacy’s purchase of oil and natural gas properties acquired in the Binger, Ameristate, Raven Shenandoah, Raven OBO and TOC Acquisitions. The $7.0 million increase in natural gas revenues reflects an increase in natural gas production of approximately 852 MMcf (39%) due primarily to Legacy’s purchase of oil and natural gas properties in the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions while the realized price per Mcf increased $0.45 per Mcf.

 

For the year ended December 31, 2007, Legacy recorded $85.2 million of net losses on oil and natural gas swaps comprised of realized gains of $0.2 million from net cash settlements of oil, NGL and natural gas swap contracts and net unrealized losses of $85.4 million. Legacy had unrealized net losses from its oil swaps because the fixed price of its oil swap contracts were below the NYMEX index prices at December 31, 2007. As a point of reference, the NYMEX price for light sweet crude oil for the near-month close at December 31, 2007 was $95.98 per Bbl, a price which is greater than the average contract prices of Legacy’s outstanding oil swap contracts. Legacy had unrealized net losses from its NGL swaps because the fixed price of its NGL swap contracts were below the NYMEX index prices at December 31, 2007. Legacy had unrealized net losses from its natural gas swaps because the fixed prices of its natural gas swap contracts were below the NYMEX index prices at December 31, 2007. As a point of reference, the NYMEX price for natural gas for the near-month close at December 31, 2007 was $7.48 per MMbtu, a price which is greater than the average contract prices of Legacy’s outstanding natural gas swap contracts. For the year ended December 31, 2006, Legacy recorded $2.3 million of net losses on oil swaps comprised of a realized loss of $6.7 million from net cash settlements of oil swap contracts and a net unrealized gain of $4.3 million. For the year ended December 31, 2006, Legacy recorded $11.6 million of net gains on gas swaps comprised of a realized gain of $6.4 million from net cash settlements of gas swap contracts and a net unrealized gain of $5.2 million. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods.

 

Legacy’s oil and natural gas production expenses, excluding production and other taxes, increased to $27.1 million ($14.96 per Boe) for the year ended December 31, 2007, from $15.9 million ($14.28 per Boe) for the year ended December 31, 2006. Production expenses increased primarily because of (i) $2.9 million related to the Binger Acquisition, (ii) $3.4 million related to the Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC

and Summit Acquisitions and (iii) increased production and increased cost of services and certain operating costs that are directly related to higher commodity prices, particularly the cost of electricity, which powers artificial lift equipment and pumps involved in the production of oil.

 

Legacy’s production and other taxes were $7.9 million and $3.7 million for the years ended December 31, 2007 and 2006, respectively. Production and other taxes increased primarily because of (i) approximately $1.0 million of taxes related to the Binger Acquisition, (ii) $1.0 million of taxes related to the Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions and (iii) higher commodity prices in the 2007 period.

 

Legacy’s general and administrative expenses were $8.4 million and $3.7 million for the years ended December 31, 2007 and 2006, respectively. General and administrative expenses increased approximately $4.7 million between periods primarily due to (i) increased employee costs related to business expansion, (ii) $1.4 million of costs incurred in connection with awards granted under the LTIP due to a $1.1 million non-cash expense related to the change in estimated fair value of the unit-based compensation liability related to unit options, unit grants, phantom unit grants and unit appreciation rights and $0.3 million of cash payments to employees exercising unit options and (iii) approximately $0.5 million of costs incurred in connection with the preparation of the 2006 federal income tax return and related form K-1’s.

 

Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $28.4 million and $18.4 million for the years ended December 31, 2007 and 2006, respectively, reflecting primarily (i) $6.3 million of DD&A related to the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions, (ii) $1.1 million to the Legacy Formation and (iii) $1.6 million related to the South Justis, Farmer Field, and Kinder Morgan Acquisitions.

 

Impairment expense was $3.2 million and $16.1 million for the years ended December 31, 2007 and 2006, respectively. In 2007 Legacy recognized impairment expense in 43 separate producing fields, due primarily to performance decline in properties within these fields. In 2006 Legacy recognized impairment expense in 41 separate producing fields, due primarily to the decline in oil and natural gas prices from the dates at which the purchase prices for the PITCO acquisition and the Legacy Formation were allocated among the purchased properties. As a point of reference, the NYMEX closing price for oil was $61.05 per Bbl at December 31, 2006, as compared to $66.63 per Bbl on March 31, 2006 at the time of the Legacy Formation and $66.24 per Bbl on September 30, 2005 at the time of the PITCO acquisition. As a point of reference, the NYMEX closing price for natural gas was $6.30 per MMbtu at December 31, 2006, as compared to $7.21 per MMbtu on March 31, 2006 at the time of the Legacy Formation and $13.92 per MMbtu on September 30, 2005 at the time of the PITCO acquisition.

 

Legacy recorded interest income of $320,968 for the year ended December 31, 2007 and $129,712 for the year ended December 31, 2006. The increase of $191,256 is a result of higher average cash balances during the year ended December 31, 2007.

 

Interest expense was $7.1 million and $6.6 million for the years ended December 31, 2007 and 2006, respectively, reflecting higher average borrowings during the year ended December 31, 2007 and a mark-to-market adjustment related to interest rate swaps of approximately $1.5 million.

 

Legacy recorded equity in income of partnership of $77,144 for the year ended December 31, 2007 and a loss of $317,788 for the year ended December 31, 2006. In 2007, Legacy recorded equity in income of partnership related to its non-controlling interest in Binger Operations LP (“BOL”). This income is primarily derived from BOL’s less than 1% interest in the Binger Unit. In 2006, Legacy recorded equity in loss of partnership related to its investment in MBN Management, LLC, which was formed in July, 2005. Legacy did not acquire any interest in MBN Management, LLC as part of the Legacy Formation. Accordingly, such losses will not be incurred in the future.

 

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

 

Legacy’s revenues from the sale of oil were $45.4 million and $18.2 million for the years ended December 31, 2006 and 2005, respectively. Legacy’s revenues from the sale of natural gas were $14.4 million and $7.3 million for the years ended December 31, 2006 and 2005, respectively. The $27.2 million increase in oil revenues reflects an increase in oil production of 395 MBbls (112%) due primarily to Legacy’s purchase of the oil and natural gas

properties acquired in the March 15, 2006 formation transactions, or the Legacy Formation, the PITCO acquisition and the South Justis, Farmer Field and Kinder Morgan acquisitions while the realized price excluding the effects of hedging increased $9.07 per Bbl. The $7.1 million increase in natural gas revenues reflects an increase in natural gas production of approximately 1,173 MMcf (114%) due primarily to both the Legacy Formation and the PITCO acquisition while the realized price per Mcf excluding the effects of hedging decreased $0.56 per Mcf. Since the Legacy Formation occurred on March 15, 2006, Legacy’s revenues and related volumes for the year ended December 31, 2006 do not reflect the 50 MBbls and 119 MMcf produced by the oil and natural gas properties acquired in that transaction from January 1, 2006 to March 15, 2006. For the year ended December 31, 2006, Legacy recorded $9.3 million of net gains on oil and natural gas swaps comprised of realized losses of $0.3 million from net cash settlements of oil and natural gas swap contracts and net unrealized gains of $9.6 million. Legacy had unrealized net gains from its oil swaps because the fixed price of its oil swap contracts were above the NYMEX index prices at December 31, 2006. As a point of reference, the NYMEX price for light sweet crude oil for the near-month close at December 31, 2006 was $61.05 per Bbl, a price which is less than the average contract prices of Legacy’s outstanding oil swap contracts. Legacy had unrealized net gains from its natural gas swaps because the fixed prices of its natural gas swap contracts were above the NYMEX index prices at December 31, 2006. As a point of reference, the NYMEX price for natural gas for the near-month close at December 31, 2006 was $6.30 per MMbtu, a price which is less than the average contract prices of Legacy’s outstanding natural gas swap contracts. For the year ended December 31, 2005, Legacy recorded $6.2 million of net losses on oil swaps comprised of a realized loss of $3.5 million from net cash settlements of oil swap contracts and a net unrealized loss of $2.6 million. There were no settlements on natural gas swaps during the year ended December 31, 2005. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods.

 

Legacy’s oil and natural gas production expenses, excluding production and other taxes, increased to $15.9 million ($14.28 per Boe) for the year ended December 31, 2006, from $6.4 ($12.14 per Boe) million for the year ended December 31, 2005. Production expenses increased primarily because of (i) $3.6 million related to the PITCO acquisition, (ii) $3.7 million related to the Legacy Formation, (iii) $2.2 million related to the South Justis, Farmer Field and Kinder Morgan acquisitions and (iv) increased production and increased cost of services and certain operating costs that are directly related to higher commodity prices, particularly the cost of electricity, which powers artificial lift equipment and pumps involved in the production of oil.

 

Legacy’s production and other taxes were $3.7 million and $1.6 million for the years ended December 31, 2006 and 2005, respectively. Production and other taxes increased primarily because of (i) approximately $0.8 million of taxes related to the PITCO Acquisition, (ii) $0.9 million of taxes related to the Legacy Formation and (iii) higher commodity prices in the 2006 period.

 

Legacy’s general and administrative expenses were $3.7 million and $1.4 million for the years ended December 31, 2006 and 2005, respectively. General and administrative expenses increased approximately $2.1 million between periods primarily due to increased employee costs related to business expansion and approximately $250,000 of costs incurred in connection with our private equity offering.

 

Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $18.4 million and $2.3 million for the years ended December 31, 2006 and 2005, respectively, reflecting primarily $7.3 million of DD&A related to the PITCO acquisition, $6.8 million to the Legacy Formation and $1.0 million to recent acquisitions.

 

Impairment expense was $16.1 million for the year ended December 31, 2006 involving 41 separate producing fields, due primarily to the decline in oil and natural gas prices from the dates at which the purchase prices for the PITCO acquisition and the Legacy Formation were allocated among the purchased properties. As a point of reference, the NYMEX closing price for oil was $61.05 per Bbl at December 31, 2006, as compared to $66.63 per Bbl on March 31, 2006 at the time of the Legacy Formation and $66.24 per Bbl on September 30, 2005 at the time of the PITCO acquisition. As a point of reference, the NYMEX closing price for natural gas was $6.30 per MMbtu at December 31, 2006, as compared to $7.21 per MMbtu on March 31, 2006 at the time of the Legacy Formation and $13.92 per MMbtu on September 30, 2005 at the time of the PITCO acquisition.

Legacy recorded interest income of $129,712 for the year ended December 31, 2006 and $185,308 for the years ended December 31, 2005. The decrease of $55,596 is a result of lower average cash balances for the current period.

 

Interest expense was $6.6 million and $1.6 million for the years ended December 31, 2006 and 2005, respectively, reflecting higher average borrowings and higher average interest rates in the current period. Legacy borrowed $67.5 million to fund the PITCO acquisition and $65.8 million under its new revolving credit facility at the close of the Legacy Formation.

 

Legacy recorded equity in loss of partnership of $317,788 and $495,295 for the years ended December 31, 2006 and 2005, respectively. In both periods, Legacy recorded equity in loss of partnership related to its investment in MBN Management, LLC, which was formed in July, 2005. Legacy did not acquire any interest in MBN Management, LLC as part of the Legacy Formation. Accordingly, such losses will not be incurred in the future.

 

Capital Resources and Liquidity

 

Legacy’s primary sources of capital and liquidity have been proceeds from bank borrowings, cash flow from operations, its private offering in March 2006, its initial public offering in January 2007 and its private offering in November 2007. To date, Legacy’s primary use of capital has been for the acquisition and development of oil and natural gas properties. During the year ended December 31, 2006, Legacy cancelled (before their original settlement date) a portion of its NYMEX oil swaps covering periods in 2007 and 2008 and realized a loss of $4.0 million. As a result, Legacy’s working capital was reduced by $4.0 million. During the year ended December 31, 2005, Legacy cancelled (before their original settlement date) a portion of its NYMEX WTI oil swaps covering periods in 2006 and realized a loss of $2.0 million. Legacy, through its ownership of MBN Properties LP, paid a $0.8 million premium for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised. As a result, Legacy’s working capital was reduced by $2.8 million at December 31, 2005.

 

As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and planned capital expenditures. Our future success in growing reserves and production will be highly dependent on capital resources available to us and our success in acquiring and exploiting additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we would need to borrow additional amounts under our revolving credit facility, if available, or obtain additional debt or equity financing. Our credit facility imposes certain restrictions on our ability to obtain additional debt financing. Based upon current oil and natural gas price expectations for the year ending December 31, 2008, we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our credit facility will provide us sufficient working capital to meet our planned capital expenditures of $18.2 million and planned cash distributions of $53.5 million, which reflects the $13.4 million of distributions paid in the first quarter of 2008 and $13.4 million of planned distributions during each of the second, third and fourth quarters of 2008. Please read “— Financing Activities — Our Revolving Credit Facility.”

 

Cash Flow from Operations

 

Legacy’s net cash provided by operating activities was $57.1 million and $29.6 million for the year ended December 31, 2007 and 2006, respectively, with the 2007 period being favorably impacted by higher sales volumes and realized oil and natural gas prices, partially offset by higher expenses.

 

Legacy’s net cash provided by operating activities was $29.6 million and $14.4 million for the years ended December 31, 2006 and 2005, respectively, with the 2006 period being favorably impacted by higher sales volumes and realized oil and natural gas prices, partially offset by higher expenses.

 

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 our ability to maintain and increase production through acquisitions and development projects, as well as the prices of oil and natural gas.

We enter into oil, NGL and natural gas derivatives to reduce the impact of oil, NGL and natural gas price volatility on our operations. Currently, we use swaps to offset price volatility on NYMEX oil, NGL and natural gas prices, which do not include the additional net discount that we typically realize in the Permian Basin. At December 31, 2007, we had in place oil, NGL and natural gas swaps covering significant portions of our estimated 2008 through 2012 oil, NGL and natural gas production. As of March 11, 2008 we had derivatives covering approximately 73% of our expected oil, NGL and natural gas production for 2008. As of March 11, 2008 we had also entered into derivative contracts covering approximately 54% of our expected oil, NGL and natural gas production for 2009 through 2012 from existing total proved reserves.

 

By removing the price volatility on our cash flows from a significant portion of our oil, NGL and natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers.

 

The following tables summarize, for the periods indicated, our oil and natural gas swaps as of March 11, 2008 in place through December 31, 2012. We use swaps as our mechanism for hedging commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to hedge the floating prices we are paid by purchasers of our oil and natural gas. These transactions are settled based upon the NYMEX price of oil at Cushing, Oklahoma, and NYMEX price of natural gas at Henry Hub on the average of the three final trading days of the month and settlement occurs on the fifth day of the production month.

 

 

 

In July 2006, we entered into basis swaps to receive floating NYMEX prices less a fixed basis differential and pay prices based on the floating Waha index, a natural gas hub in West Texas. The prices that we receive for our natural gas sales follow Waha more closely than NYMEX. The basis swaps thereby provide a better match between our natural gas sales and the settlement payments on our natural gas swaps. The following table summarizes, for the periods indicated, our NYMEX basis swaps as of March 11, 2008 in place through December 31, 2010.

 

 

On March 30, 2007, we entered into natural gas liquids swaps to hedge the impact of volatility in the spot prices of natural gas liquids. On September 7, 2007, we entered into additional natural gas liquids swaps. These swaps hedge the spot prices for ethane, propane, iso-butane, normal butane and natural gasoline tracked on the Mont

Belvieu, Non-Tet OPIS exchange. The following table summarizes, for the periods indicated, our Mont Belvieu, Non-Tet OPIS natural gas liquids swaps as of March 11, 2008 in place through December 31, 2009.

 

 

On March 13, 2008, we entered into additional oil and natural gas swap contracts as described in Note 18 “Subsequent Events.”

 

Investing Activities — Acquisitions and Capital Expenditures

 

Legacy’s cash capital expenditures were $196.0 million for the year ended December 31, 2007. The total includes $28.5 million, $5.2 million, $14.8 million, $13.5 million, $20.9 million, $62.1 million and $13.5 million for the purchase of producing oil and natural gas properties in the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit Acquisitions, respectively. The balance was expended in smaller individual acquisitions and development projects.

 

Legacy’s capital expenditures were $55.9 million and $66.9 million for the years ended December 31, 2006 and 2005, respectively. The total for the year ended December 31, 2006 includes $7.7 million paid to three charitable foundations in the Legacy formation for oil and natural gas properties, $8.9 million, $5.6 million and $17.2 million for the purchase of producing oil and natural gas properties in the South Justis Unit from Henry Holding, LP, the Farmer Field from Larron Oil Corporation and various oil and natural gas properties from Kinder Morgan, respectively, and $7.0 million of capitalized operating rights related to the South Justis Unit. The balance was invested in development projects.

 

We currently anticipate that our drilling budget, which predominantly consists of drilling, re-completion and re-fracture stimulation projects will be $18.2 million for the year ending December 31, 2008. Our borrowing capacity under our revolving credit facility is $84.4 million as of March 14, 2008. 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 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 upon current oil and natural gas price expectations for the year ending December 31, 2008, we anticipate that we will have sufficient sources of working capital, including our cash flow from operations and available borrowing capacity under our credit facility, to meet our cash obligations including our planned capital expenditures of $18.2 million and planned cash distributions of $53.5 million during the year ending December 31, 2008. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

 

Financing Activities

 

Our Revolving Credit Facility

 

At the closing of our private equity offering on March 15, 2006, we entered into a four-year, $300 million revolving credit facility with BNP Paribas as administrative agent. Borrowings under the facility are due on March 15, 2010. On October 24, 2007, we entered into the third amendment to the revolving credit facility with BNP Paribas, which increased the maximum credit amount to $500 million from $300 million. Our obligations under the credit facility are secured by mortgages on more than 80% of our oil and gas properties as well as a pledge of all of our ownership interests in our operating subsidiaries. The amount available for borrowing at any one time is limited to the borrowing base, which was initially set at $130 million and increased to $225 million in the third amendment dated October 24, 2007. The borrowing base is subject to semi-annual re-determinations on April 1 and October 1 of each year. Additionally, either Legacy or the lenders may, once during each calendar year, elect to re-

determine the borrowing base between scheduled re-determinations. We also have the right, once during each calendar year, to re-determine the borrowing base upon the proposed acquisition of certain oil and gas properties where the purchase price is greater than 10% of the borrowing base. Any increase in the borrowing base requires the consent of all the lenders and any decrease in the borrowing base must be approved by the lenders holding 662/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the credit facility. If the required lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 662/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the credit facility so long as it does not increase the borrowing base then in effect. Outstanding borrowings in excess of the borrowing base must be prepaid, and, if mortgaged properties represent less than 80% of total value of oil and gas properties evaluated in the most recent reserve report, we must pledge other oil and natural gas properties as additional collateral.

 

We may elect that borrowings be comprised entirely of alternate base rate (ABR) loans or Eurodollar loans. Interest on the loans is determined as follows:

 

 

Interest is generally payable quarterly for ABR loans and on the last day of the applicable interest period for any Eurodollar loans.

 

Our revolving credit facility also contains various covenants that limit our ability to:

 

 

Our credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

 

 

If an event of default exists under our revolving credit facility, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following would be an event of default:

 

 

 

Off-Balance Sheet Arrangements

 

None.

 

Contractual Obligations

 

A summary of our contractual obligations as of December 31, 2007 is provided in the following table.

 

 

 

 

 

Critical Accounting Policies and Estimates

 

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Estimates and assumptions are evaluated on a regular basis. Legacy based its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if: