UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the fiscal year ended December 31, 2005

OR

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the transition period from  to                    

Commission file number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)

(412) 440-1400

(Registrant’s telephone number, including area code)

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

None

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

Title of Class

Units Representing Limited Liability Company Interests

      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 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 o     No þ

      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (check one):

Large accelerated filer o     Accelerated filer o     Non-accelerated filer þ

      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 our voting and non-voting common equity held by non-affiliates of the registrant was approximately $261.0 million on May 8, 2006 based on $20.00 per unit, the last reported sales price of the units on The Nasdaq National Market on such date. As of May 8, 2006, there were 27,832,500 units outstanding.

Documents Incorporated By Reference: None

TABLE OF CONTENTS

PART I

      As commonly used in the natural gas and oil industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:

GLOSSARY OF TERMS

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

      Bcf. One billion cubic feet.

      Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

      Btu. One 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.

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

      Dth. One decatherm, equivalent to one million British thermal units.

      Developed acres. Acres spaced or assigned to productive wells.

      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.

      Mcf. One thousand cubic feet.

      Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

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

      MMBtu. One million British thermal units.

      MMcf. One million cubic feet.

      MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

      MMcfe/d. One MMcfe per day.

      MMMBtu. One billion British thermal units.

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

      NYMEX. The 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 exceeds 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 natural gas and oil 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 reserves. Proved natural gas and oil reserves are the estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate 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. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units 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.

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

      Standardized Measure. Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) 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%. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Linn Energy Holdings, LLC, which is not subject to income taxes.

      Successful well. A well capable of producing natural gas and/or oil in commercial quantities.

      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 natural gas and oil 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.

Restatement Overview

      This Annual Report on Form 10-K for the year ended December 31, 2005 reports the consolidated financial statements of Linn Energy, LLC (the “Company”) for the year ended December 31, 2005 and amends and restates the prior year consolidated financial statements as of December 31, 2003 and 2004, and for the period March 14, 2003 (inception) to December 31, 2003, the year ended December 31, 2004, and the nine months ended September 30, 2004 and 2005. The restatement also affected production and operational data as restated and included in Item 6, “Selected Financial Data.”

      As previously announced in a Current Report on Form 8-K as filed with the Securities and Exchange Commission on April 3, 2006, the Company identified that certain aspects of the Company’s accounting for the purchase price of acquisitions did not properly recognize the acquisition date for natural gas and oil property acquisitions as required by Statement of Financial Accounting Standards (“SFAS”) No. 141 — Business Combinations. The Company further evaluated its natural gas and oil accounting for both acquisitions and operations and identified that corrections were needed to reflect the purchase accounting as of the appropriate acquisition date for natural gas and oil property acquisitions, capitalize certain expenditures for lease acquisition costs, correct depreciation, depletion and amortization, and properly report accounts receivables and general and administrative expenses for fees charged to third parties.

      This non-cash restatement had the following effect on our net loss:

      This non-cash restatement had the following effect on our Adjusted EBITDA. Please see “Non-GAAP Financial Measure” on page 38.

      We have also determined that control deficiencies related to the accounting for the Company’s natural gas and oil property acquisitions and certain operational costs represent material weaknesses in our internal control over financial reporting as of December 31, 2005. Please read Item 9A, “Controls and Procedures.”

History of Corrections

      As part of its preparation of the consolidated financial statements for the year ended December 31, 2005, the Company undertook a review of its natural gas and oil accounting and identified the following errors which were incorrectly accounted for and needed to be corrected.

      1. Through December 31, 2005 the Company had completed nine acquisitions of natural gas properties and related gathering and pipeline assets. Four of the acquisitions occurred in 2003, two occurred in 2004 and three occurred in 2005. When the Company made the acquisitions of natural gas and oil properties, the stated contractual effective date preceded the closing or settlement date. Within a short period of time after settlement, the Company would receive cash or credit for natural gas and oil produced between the contracted effective date and the acquisition settlement date, and the Company would pay or accrue for operational costs within this same period. For acquisitions occurring in 2003 and 2004, amounts between the contracted effective date and the date of closing were previously recognized in the Company’s consolidated statement of operations instead of being recorded as an adjustment to the purchase price of the related acquisition as required under SFAS No. 141 — Business Combinations. These changes also resulted in corresponding changes to depreciation, depletion and amortization.

      2. Certain expenditures for lease acquisition costs and development drilling costs were previously recognized as an expense instead of being capitalized as required under SFAS No. 19 — Financial Accounting and Reporting by Oil and Gas Producing Companies.

      3. The Company incorrectly recorded the period end accrual and related intercompany elimination for operating and administrative services provided.

      4. The consolidated statements of cash flows have been restated for certain changes in current assets and liabilities that are more accurately reported as investing or financing activities.

      Please see also Note 20 to the Company’s consolidated financial statements in Item 8, “Financial Statements and Supplementary Data” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The restatement had no effect on our reserve data, Standardized Measure, cash and cash equivalents, or Predecessor Data included in Item 6, “Selected Financial Data”, and has no material effect on the Company’s 2006 guidance as previously reported in the Company’s Current Report on Form 8-K filed with the SEC on March 7, 2006.

      All referenced amounts in this Annual Report on Form 10-K for prior periods and prior period comparisons reflect the balances and amounts on a restated basis.

Overview

      Linn Energy, LLC is an independent natural gas and oil development and acquisition company. At December 31, 2005, our reserves were located in the Appalachian Basin, primarily in West Virginia, Pennsylvania, New York and Virginia. From our inception in March 2003 through December 31, 2005, we made nine acquisitions of natural gas properties and related gathering and pipeline assets for a restated aggregate purchase price of $201.5 million, with total proved reserves of 160.1 Bcfe, or a restated acquisition cost of $1.26 per Mcfe. These nine acquisitions included 1,914 producing wells and we have drilled 200 wells since inception, 100% of which were successful in producing natural gas in commercial quantities, resulting in a total of 2,114 wells. As part of our business strategy, we continually evaluate opportunities to acquire additional natural gas and oil properties which complement our asset profile both within the Appalachian Basin and elsewhere in the United States.

      Our proved reserves at December 31, 2005 were 193.2 Bcfe, of which approximately 99% were natural gas and 65% were classified as proved developed, with a Standardized Measure of $552.1 million. At December 31, 2005, we operated 1,922, or 91%, of our 2,114 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 29 years based on our December 31, 2005 reserve report and annualized production for the quarter ended December 31, 2005. As of December 31, 2005, we had identified 905 drilling locations, of which 373 were proved undeveloped locations and 532 were other locations, and we had leasehold interests in 145,686 net acres in the Appalachian Basin. From inception through December 31, 2005, we added 33.1 Bcfe of proved natural gas and oil reserves through our drilling activities, at a finding and development cost of $1.31 per Mcfe, which includes the estimated development costs for proved undeveloped reserves.

      Linn Energy, LLC, a Delaware limited liability company formed in April 2005, is a holding company that conducts its operations through, and its operating assets are owned by, its subsidiaries Linn Energy Holdings, LLC (formed in March 2003 and formerly known as Linn Energy, L.L.C.), Linn Operating, Inc. (formerly Linn Operating, LLC), Penn West Pipeline, LLC (formerly Chipperco, LLC) and Mid Atlantic Well Service, Inc. We own, directly or indirectly, all of the ownership interests in our operating subsidiaries. Linn Energy Holdings owns all of our interests in natural gas and oil properties, all of our employees are employed by Linn Operating or Mid Atlantic Well Service, Penn West Pipeline owns and operates our natural gas gathering assets and Mid Atlantic Well Service conducts our oilfield service operations.

      We completed our initial public offering on January 19, 2006 and our units representing limited liability company interests (“units”) are listed for quotation on The Nasdaq National Market under the symbol “LINE.”

      Unless the context requires otherwise, any reference in this Annual Report on Form 10-K to “Linn Energy,” “we,” “our,” “us,” or the “Company” means Linn Energy, LLC and its consolidated subsidiaries.

Acquisition History

      As of December 31, 2005, we had completed nine acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate restated purchase price of $201.5 million, with total proved reserves of 160.1 Bcfe, or a restated acquisition cost of $1.26 per Mcfe.

Business Strategy

      Our goal is to provide stability and growth in distributions to our unitholders through continued successful drilling, acquisitions, increasing production of existing wells and pursuing operational and administrative efficiencies. The key elements of our business strategy are:

Drilling

      Wells in the Appalachian Basin are typically drilled at relatively low cost due to the shallow drilling depths and the ability to use air drilling. Most of the drilling rigs are small pull-down type rigs that can be set up on very small locations that are typically 60 feet wide and 160 feet long. These small rigs can be transported to the drilling locations at relatively low cost. Further, the use of air drilling greatly reduces the size of any pits for drilling fluids needed on location.

      Most of our wells are relatively shallow, ranging from 2,500 to 5,500 feet, and drill through as many as ten potential producing zones. Our average well cost for 2005 was $227,000. Many of our wells are completed to multiple producing zones and production from these zones may be commingled. In general, our producing wells have stable production profiles and long-lived production, often with total projected economic lives in excess of 50 years. Appalachian wells typically are drilled on relatively close spacing of between 20 to 40 acres per well due to the low permeability of the producing formations. Generally, the distance between wells is less than 1,500 feet and wells are located within 1,000 feet from the closest pipeline. As a result, most of our wells are producing and connected to a pipeline within 30 to 60 days after drilling has commenced. Once drilled and completed, operating and maintenance requirements for producing wells in the Appalachian Basin are generally low and only minimal, if any, capital expenditures are required.

      During the year ended December 31, 2005, we drilled 110 wells, and since inception we have spent $43.3 million to drill and complete 200 wells, all of which are capable of producing natural gas in commercial quantities, with an average finding and development cost of $1.31 per Mcfe, which includes the estimated development costs for proved undeveloped reserves. To carry out our 2006 drilling program, we have contracts in place for four third party drilling rigs. We also are purchasing two drilling rigs, at a cost of approximately $2.2 million per rig, which are anticipated to be delivered in late summer or early fall of 2006. As of December 31, 2005, we had 373 proved undeveloped drilling locations (specific drilling locations as to which our independent reserve engineer, Schlumberger Data and Consulting Services, has assigned proved undeveloped reserves as of such date) and we had identified 532 additional unproved drilling locations (specific drilling locations as to which Schlumberger Data and Consulting Services has not assigned any proved reserves as of such date but which we have identified as future drilling locations that we expect to drill based on our current drilling schedule) on acreage that we have under existing leases. As successful development wells in the Appalachian Basin frequently result in the reclassification of adjacent lease acreage from unproved to proved, we expect that a significant number of our unproved drilling locations will be reclassified as proved drilling locations prior to the actual drilling of these locations.

Appalachian Basin

      The Appalachian Basin is one of the country’s oldest natural gas producing regions characterized by long-lived reserves and predictable decline rates. During the first several years of production, wells in the Appalachian Basin generally experience higher initial production rates and decline rates which are followed by an extended period of significantly lower production rates and decline rates. For example, the initial production rate of our new wells may be as high as 80 to 100 Mcf per day while our average production rate per well during 2005 was 10.1 Mcf per day. The average well production in the Appalachian Basin is 10 Mcf per day or less and decline rates typically range from 2% to 6% per year.

      The Appalachian Basin spans more than seven states in the largest natural gas consuming region of the United States. The close proximity to major natural gas consuming markets in the northeastern United States results in lower transportation costs to these markets relative to natural gas produced in other regions, contributing to the premium pricing for Appalachian production relative to NYMEX.

      Reserves in the Appalachian Basin typically have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most of our wells produce natural gas of pipeline quality which does not require further treatment by us before delivery to the receiving pipeline.

      Our activities are concentrated in the Appalachian Basin in major geologic formations of the Mississippian/ Devonian Sands and Carbonates in West Virginia and southwestern Pennsylvania, and the Oriskany Sands in southwestern Pennsylvania.

Natural Gas Prices

      Natural gas produced in the Appalachian Basin typically sells for a premium to NYMEX natural gas prices due to the proximity to major consuming markets in the northeastern United States. For the year ended December 31, 2005, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin on the Columbia Gas Transmission Corp. Appalachia Pipeline and the Dominion Transmission Inc. Appalachia Pipeline was $0.40 and $0.43 per Mcf, respectively. Most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices.

      We enter into derivative transactions in the form of hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use fixed price swaps and puts to hedge NYMEX natural gas prices, which do not include the additional net premium we typically realize in the Appalachian Basin. By removing the price volatility from a significant portion of our natural gas production, we have

mitigated, but not eliminated, the potential effects of fluctuating natural gas prices on our cash flow from operations for those periods.

      The following table summarizes, as of May 17, 2006, and for the periods indicated, our derivatives presently in place through December 31, 2009. Currently, we use fixed price swaps and puts to manage commodity prices. These transactions are settled based upon the NYMEX price of natural gas at Henry Hub on the final trading day of the month, and settlement occurs on the 3rd day of the production month.

Natural Gas and Oil Data

      The following table presents our estimated net proved natural gas and oil reserves and the present value of our estimated proved reserves at December 31, 2003, 2004 and 2005, based on reserve reports prepared by Schlumberger Data and Consulting Services. The Standardized Measure values shown in the table are not intended to represent the market value of our estimated natural gas and oil reserves at such dates.

      The data in the above table represents estimates only. Natural gas and oil reserve engineering is inherently a subjective process of estimating underground accumulations of natural gas and oil 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 natural gas and oil that are ultimately recovered.

      Future prices received for production may vary, perhaps significantly, from the prices assumed for purposes of our estimate of Standardized Measure. The Standardized Measure shown should not be construed as the

market value of the reserves at the dates shown. The 10% discount factor used to calculate Standardized Measure, which is required by Financial Accounting Standards Board (“FASB”) pronouncements, is not necessarily the most appropriate discount rate. The Standardized Measure, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

      The following table sets forth information regarding net production of natural gas and oil and certain price and cost information for each of the periods indicated:

      The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2005. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

      The following table sets forth information as of December 31, 2005 relating to our leasehold acreage.

      We intend to concentrate our drilling activity on lower risk, development properties. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well and the estimated recoverable reserves attributable to each well.

      The following table sets forth information with respect to wells completed during the years ended December 31, 2004 and 2005. We did not conduct any drilling operations in the period from March 14, 2003 (inception) through December 31, 2003. 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 natural gas, regardless of whether they generate a reasonable rate of return.

Natural Gas Gathering Activities

      We own and operate an extensive network of natural gas gathering systems comprised of approximately 800 miles of pipeline and associated compression and metering facilities which connect to numerous sales outlets on eight interstate and eight intrastate pipelines, which allows us to more efficiently transport our gas to market. The interstate market outlets are Dominion Transmission Inc. (West Virginia and Pennsylvania), Columbia Gas Transmission Corp. (West Virginia and Pennsylvania), Cranberry Pipeline (West Virginia), Texas Eastern Pipeline (Pennsylvania), Transco Pipeline (Pennsylvania), Equitrans (West Virginia and Pennsylvania), Equitable Gas Company (West Virginia and Pennsylvania), and Carnegie Gas Company (West Virginia). The intrastate market outlets are Dominion Peoples (Pennsylvania), Dominion Hope (West Virginia), TW Phillips Oil & Gas Company,

Inc. (Pennsylvania), Equitable Gas Company (West Virginia and Pennsylvania), Cabot Oil & Gas Corporation (West Virginia), Allegheny Power (West Virginia), National Fuel Gas Distribution (New York) and Lumberport Shinnston Gas Company (West Virginia).

      We gather more than 90% of our current production. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to:

Natural Gas Gathering for Others

      We perform limited natural gas gathering activities for others on non-jurisdictional gathering systems through our subsidiary Linn Operating, Inc. We gather for others primarily in Westmoreland and Indiana Counties, Pennsylvania. The fee charged to third party producers is set by contract and ranges from $0.10 to $0.25 per Mcf plus line loss and any compressor fuel. Linn Operating aggregates these volumes with our production and sells all natural gas through its meter(s) to the same purchasers. These revenues are collected and distributed to the third party producers in the normal course of our revenue distribution cycle. Most of Linn Operating’s natural gas gathering lines are not subject to United States Department of Transportation (“US DOT”) safety regulations.

Purchase for Resale

      On November 1, 2004, Penn West purchased the Bessie 8 Pipeline in Indiana County, Pennsylvania and began purchasing and re-selling production from other producers connected to it. Penn West buys this third party production and resells it into a Dominion Peoples transmission line. We intend to reconfigure other Linn Operating natural gas gathering systems to bring online additional volumes, both company owned and third party owned, to the Bessie 8 Pipeline to increase throughput volumes and revenues.

Operations

      In general, we seek to be the operator of wells in which we have an interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. To carry out our 2006 drilling program, we have contracts in place for four third party drilling rigs. We also are purchasing two drilling rigs, at a cost of approximately $2.2 million per rig, which are anticipated to be delivered in late summer or early fall of 2006. In addition, we employ drilling, production and reservoir engineers, geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our natural gas properties.

      The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the lease premises. In the Appalachian Basin this amount is typically 1/8th (12.5%) of revenue resulting in a 87.5% net revenue interest to us for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6th (16.66%) of revenue when leases are taken from larger landowners or mineral owners such as coal and timber companies.

      Because the acquisition of natural gas and oil leases is a very competitive process and involves certain geological and business risks to identify productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32nd to 1/16th (3.125% to 6.25%) of revenue, which further reduces the net revenue interest available to us to between 84.375% and 81.25% of revenue.

      Sometimes these third party owners of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us. Normally the retained interest is a 25% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third party operator. In most other instances we anticipate owning a 100% working interest in newly drilled wells.

      In almost all of the areas we operate in the Appalachian Basin, the surface owner is normally also the mineral owner, allowing us to deal with a single party. This simplifies the research process required to identify the proper owners of the natural gas and oil rights and reduces the per acre lease acquisition cost and the time required to successfully acquire the desired leases.

      For the year ended December 31, 2005, sales of natural gas to Dominion Resources, Inc., Cabot Oil & Gas Corporation, UGI Energy Services, Inc., Amerada Hess Corporation and Equitable Resources, Inc. accounted for approximately 48%, 14%, 10%, 7% and 6%, respectively, of our total volumes, or 85% in the aggregate. If we were to lose any one of our major natural gas purchasers, the loss could temporarily cease or delay production and sale of our 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 these large natural gas purchasers ceased purchasing natural gas altogether, it could have a detrimental effect on the natural gas market in general and on the volume of natural gas that we are able to sell.

      We enter into derivative transactions with unaffiliated third parties with respect to natural gas prices and interest rates to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas prices and interest rates. For a more detailed discussion of our derivative activities, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” and Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” in this Annual Report on Form 10-K.

      The natural gas and oil industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects, than our financial or human resources permit.

      We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the natural gas and oil industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our drilling program. To carry out our 2006 drilling program, we have contracts in place for four third party drilling rigs. We also are purchasing two drilling rigs, at a cost of approximately $2.2 million per rig, which are anticipated to be delivered in late summer or early fall of 2006.

      Competition is also strong for attractive natural gas and oil producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

      As is customary in the natural gas and oil 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. Prior to completing an acquisition of producing natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

      Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region and, as a result, we generally perform the majority of our drilling during the summer months. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

      We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities. To protect against potential environmental risk, we typically obtained Phase I environmental assessment of any properties to be acquired prior to completing each acquisition.

      General. Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. These laws and regulations may:

      These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil 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 clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may impact our properties or operations. For the year ended December 31, 2005, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2006 or that will otherwise have a material impact on our financial position or results of operations.

      Environmental laws and regulations that have a material impact on the natural gas and oil industry include the following:

      National Environmental Policy Act. Natural gas and oil production activities on federal lands are subject to the National Environmental Policy Act (“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 typically prepare an Environmental Assessment to assess 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 development and production activities, as well as proposed development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

      Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency (“EPA”), 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 development and production of crude oil, natural gas or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or recategorize some non-hazardous wastes as hazardous for future regulation.

      We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of natural gas and oil development and production wastes could increase our costs to manage and dispose of such wastes.

      Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on 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 companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable 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 natural gas and oil development and production for many years. Although we believe 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 these 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.

      Federal Water Pollution Control Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, 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 the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe we are in substantial compliance with the requirements of the Clean Water Act.

      Clean Air Act. The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. We believe that we are in substantial compliance with the requirements of the Clean Air Act.

      Other Laws and Regulation. The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current 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.

      The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil 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 natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil 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 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 natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not

possible to accurately estimate the costs we would 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 the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

      State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate development 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 natural gas and oil 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 natural gas and oil 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 Transportation and Pricing. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale of natural gas are 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 occur at market prices.

      State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. 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 natural gas and oil industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal opportunity employment. We do not believe that compliance with these laws will have a material adverse effect upon our results of operations.

      As of May 15, 2006, we had 130 full time employees, including three geologists, six petroleum engineers and eight land professionals. Of our 130 full time employees, 29 work in our Pittsburgh office, three work in our Houston office and 98 work in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Available Information

      Our internet address is http://www.linnenergy.com. We make available free of charge on or through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). The SEC maintains an internet website that contains these reports at http://www.sec.gov. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

Forward-Looking Statements

      This Annual Report on Form 10-K contains forward-looking statements within the meaning of federal securities laws that are subject to a number of risks and uncertainties, many of which are beyond our control. These statements may include statements about our:

      All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in Item 1, “Business;” Item 1A,“Risk Factors;” Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

      The forward-looking statements contained in this Annual Report on Form 10-K 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 beyond our control. In addition, management’s assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking statements or events will occur. Actual results may differ materially from those anticipated or implied in

forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this Annual Report on Form 10-K. The forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Risks Related to Our Business

We may not have sufficient cash flow from operations to pay the quarterly distribution at the current distribution level and future distributions to our unitholders may fluctuate from quarter to quarter.

      We may not have sufficient cash flow from operations each quarter to pay the quarterly distribution at the current distribution level. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our Board of Directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. 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:

      In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

      As a result of these factors, the amount of cash we distribute to our unitholders in any quarter may fluctuate significantly from quarter to quarter and may be significantly less than the initial quarterly distribution amount.

      We will be prohibited from borrowing under our credit facility to pay distributions to unitholders if the amount of borrowings outstanding under our 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 natural gas reserves, which will take into account the prevailing 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.

We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions in the amount of the initial quarterly distribution.

      Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile and we cannot predict the prices we will be able to realize for our production in the future. As a result, we may continue to borrow significant amounts under our credit facility in the future to enable us to pay quarterly distributions at anticipated levels. Significant declines in our production or significant declines in realized natural gas prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.

If commodity prices decline significantly for a prolonged period, our cash flow from operations will decline, and we may have to lower our distribution or may not be able to pay distributions at all.

      Our revenue, profitability and cash flow depend upon the prices and demand for natural gas. The natural gas market is very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

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

      Lower natural gas prices may not only decrease our revenues, but also reduce the amount of natural gas that we can produce economically. 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 natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. 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, which may adversely affect our ability to make cash distributions to our unitholders.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

      Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our December 31, 2005 reserve report, our average decline rate for proved developed producing reserves is 8% during the first five years, 5% in the next five years and less than 4% thereafter. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2005, production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

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

      No one can measure underground accumulations of natural gas in an exact way. Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future 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. Our independent petroleum engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per Mcf, then the Standardized Measure of our proved reserves as of December 31, 2005 would decrease from $552.1 million to $503.8 million. Our Standardized Measure is calculated using unhedged natural gas prices and is determined in accordance with the rules and regulations of the SEC. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from our reserve estimates.

      The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:

      The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Our development operations 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 reserves.

      The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of 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 our financing arrangements. 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 revolving credit facility decrease as a result of lower 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 revolving 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 on terms favorable to us, or at all. 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 development operations, which in turn could lead to a possible decline in our reserves.

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 natural gas we produce and could reduce our revenues and cash available for distribution.

      Although we gather more than 90% of our current production, the marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of natural gas that can be produced and sold is subject to limitation 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. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could reduce our revenues and cash available for distribution.

We depend on certain key customers for sales of our natural gas. To the extent these and other customers reduce the volumes of natural gas they purchase from us, our revenues and cash available for distribution could decline.

      For the year ended December 31, 2005, Dominion Resources, Inc., Cabot Oil & Gas Corporation, UGI Energy Services, Inc., Amerada Hess Corporation and Equitable Resources, Inc. accounted for approximately 48%, 14%, 10%, 7% and 6%, respectively, of our total volumes, or 85% in the aggregate. To the extent these and other customers reduce the volumes of natural gas that they purchase from us, our revenues and cash available for distribution could decline.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

      Higher 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 reduce our revenues and cash available for distribution.

Because we handle natural gas and other petroleum products, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

      The operations of our wells, gathering systems, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

      Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

      There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of our wells or gathering pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance. Please read Item 1, “Business — Operations — Environmental Matters and Regulation” in this Annual Report on Form 10-K.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to increase distributions will be limited.

      Our ability to grow and to increase distributions to unitholders is partially dependent on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because we are:

      In any such case, our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will increase pro forma available cash per unit, these acquisitions may nevertheless result in a decrease in pro forma available cash per unit.

      Any acquisition involves potential risks, including, among other things:

      If we consummate any future acquisitions, our capitalization and results of operations may change significantly. Further, our future acquisition costs may be higher than those we have achieved historically.

We have incurred losses from operations since our inception and may continue to do so in the future, which may impact our ability to pay distributions to our unitholders.

      We incurred restated net losses of $1.7 million in the period from March 14, 2003 (inception) through December 31, 2003 and $4.8 million for the year ended December 31, 2004, respectively. We incurred a net loss of $56.4 million for year ended December 31, 2005. We may generate losses in the future, which may impact our ability to generate sufficient cash flow from operations to pay quarterly distributions to our unitholders at the current distribution level.

Locations that we decide to drill may not yield natural gas in commercially viable quantities.

      The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough natural gas to be commercially viable after drilling, operating and other costs. If we drill future wells that we identify as dry holes, our drilling success rate would decline and may materially harm our business.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

      Our key project areas are located in the most active drilling areas in the Appalachian Basin. As a result, many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

      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, resulting in temporarily lower cash from operations, which may impact our ability to pay distributions.

      Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2005, we had identified 905 drilling locations, of which 373 were proved undeveloped locations and 532 were other locations. 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, natural gas prices, costs and drilling results. In addition, Schlumberger Data and Consulting Services has not assigned any proved reserves to the 532 other drilling locations we have identified and scheduled for drilling and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. 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 natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Drilling for and producing natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay 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 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 certain losses and liabilities arising from our operations. However, it is impossible to insure against all operational risks in the course of our business. 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 activities, financial condition and results of operations.

Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions to our unitholders.

      We will depend on our revolving credit facility for future capital needs and to fund a portion of our distributions. The revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are required 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 credit facility, which could cause all of our existing indebtedness to be immediately due and payable.

      The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the borrowing base requires the consent of all the lenders. If the required lenders do not agree on an increase, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66²/3 % of the commitments. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility.

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 capitalize on opportunistic acquisitions of 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.

Our hedging activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.

      To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas, we currently and may in the future enter into hedging arrangements for a significant portion of our natural gas production. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction of our liquidity. Under our credit facility, we are prohibited from hedging all of our production, and we therefore retain the risk of a price decrease on our unhedged volumes.

We depend on our President and Chief Executive Officer who would be difficult to replace.

      We depend on the performance of Michael C. Linn, our President and Chief Executive Officer. We maintain no key person insurance for Mr. Linn. The loss of Mr. Linn could negatively impact our ability to execute our strategy and our results of operations.

If we fail to develop or 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.

      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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 comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 by our initial compliance date of December 31, 2007. We identified a material weakness in our internal controls during the course of evaluating disclosure controls and procedures as of December 31, 2005. See Item 9A, “Controls and Procedures” for additional information. Any failure to develop or 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 may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

      The natural gas and oil industry is intensely competitive, and we compete with other companies that have greater resources. 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 drill for and produce natural gas and oil, 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 natural gas and oil properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low natural gas and oil 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 impact on our business activities, financial condition and results of operations.

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

      Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

      Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the natural gas and oil

regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our ability to pay distributions to our unitholders. Please read Item 1, “Business — Operations — Environmental Matters and Regulation” and “Business — Operations — Other Regulation of the Natural Gas and Oil Industry” in this Annual Report on Form 10-K for a description of the laws and regulations that affect us.

We face possible delisting from The Nasdaq Stock Market, which could result in a limited trading market for our units, and could negatively affect the price of our units.

      On April 18, 2006 and May 24, 2006, we received Nasdaq Staff Determination letters indicating that we had failed to comply with the filing requirements for continued listing set forth in Marketplace Rule 4310(c)(14) because we had not timely filed our Annual Report on Form 10-K and our Quarterly Report on Form 10-Q. As a result, our units are subject to delisting from The Nasdaq Stock Market. We have been granted a hearing before a Nasdaq Listing Qualifications Panel to appeal the Staff’s determination. The request for a hearing will stay the potential delisting until the appeal has been heard and the Panel has rendered a formal decision. There is no assurance that our appeal of the Staff’s determination will be successful. If our appeal is not successful and our units are delisted, the trading in our units could be conducted in the over-the-counter market known as the NASD OTC Electronic Bulletin Board, the trading market for our units could become limited and the price of our units could be negatively affected. As a result, you may find it difficult to dispose of, or to obtain accurate quotations as to the market value of, our units.

We may face risks related to the recent restatement of our financial statements.

      We restated our financial statements for the period from March 14, 2003 (inception) through December 31, 2003, for the year ended December 31, 2004 and certain financial statement line items for the nine months ended September 30, 2004 and 2005 primarily to correct certain accounting entries related to the acquisition of natural gas and oil properties. As a result of these changes, which primarily affect fiscal 2003 and 2004, revenues were reduced by $944,164 and $1,729,526, respectively, and net loss was increased by $353,305 and $838,018, respectively. Companies that restate their financial statements sometimes face litigation claims and/or SEC proceedings following such a restatement of financial results. Although we are unaware of any pending or threatened claims or proceedings relating to our restatement, if any claim or proceeding were to be commenced and successfully asserted against us, we could face monetary judgments, penalties or other sanctions which could adversely affect our financial condition and could cause the price of our units to decline.

Risks Related to Our Structure

Our management and Quantum Energy Partners own, in the aggregate, a controlling interest in us, with management and Quantum Energy Partners owning approximately 16.2% and 36.4%, respectively, of our units.

      Our management and Quantum Energy Partners own or control an aggregate 52.6% of our outstanding units. Accordingly, management and Quantum Energy Partners, acting together, possess a controlling vote on substantially all matters submitted to a vote of the holders of our units. As long as management and Quantum Energy Partners in the aggregate beneficially own a controlling interest in us, they will have the ability to elect all members of our Board of Directors and to control our management and affairs. Our management and Quantum Energy Partners will be able to cause a change of control of our company. This concentration of ownership may have the effect of preventing or discouraging transactions involving an actual or a potential change of control of our company, regardless of whether a premium is offered over then-current market prices.

Each of management or Quantum Energy Partners, or both, may have conflicts of interest with us. Our limited liability company agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.

      Conflicts of interest may arise between our management or Quantum Energy Partners, and us and our unitholders. These potential conflicts may relate to the divergent interests of our management or Quantum Energy

Partners. Situations in which the interests of our management or Quantum Energy Partners may differ from interests of our non-affiliated unitholders include, among others, the following situations:

We may issue additional units without unitholder approval, which would dilute your existing ownership interests.

      We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.

      The issuance of additional units or other equity securities may have the following effects:

The market price of our units could be volatile for a number of factors, many of which are beyond our control.

      The market price of our units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

      In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our units.

Quantum Energy Partners may sell units in the future, which could reduce the market price of our outstanding units.

      As of May 8, 2006, Quantum Energy Partners controlled an aggregate of 10,144,585 units. In addition, we have agreed, upon demand by Quantum, to register for sale units held by Quantum Energy Partners, certain non-affiliated investors and certain members of our management. These registration rights allow Quantum Energy Partners to request registration of their units and to include any of those units in a registration of other securities by us. If Quantum Energy Partners were to sell a substantial portion of their units, the market price of our outstanding units may decline.

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 entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

      The anticipated after-tax 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 matters.

      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 rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed as corporate dividends, and no income, gain, loss, deduction or credit would flow through to unitholders. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our units.

      Current law or our business may change so as to cause 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, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to unitholders may be reduced.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

      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. 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.

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 cash available for distribution.

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

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 depreciation and amortization positions that may not conform with all aspects of existing U.S. Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain 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.

You may be subject to state and local taxes and return filing requirements.

      In addition to federal income taxes, you will likely be subject to other taxes, including state and local 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. Unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently do business and own assets in West Virginia, Pennsylvania, New York and Virginia. 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, foreign, 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 the units.

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 your tax basis in your units.

      As units are sold, unitholders will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Prior distributions to unitholders in excess of the total net taxable income they were allocated for a unit, which decreased the unitholders’ tax basis in that unit, will, in effect, become taxable income to them if the unit is sold at a price greater than their tax basis in that unit, even if the price you receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder

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 for 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. A constructive termination results in the closing of our taxable year for all unitholders and in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders.

      Not applicable.

      As of December 31, 2005, our producing wells and drilling locations were located as follows:

      All of our proved reserves as of December 31, 2005 were located in the Appalachian Basin. For additional information concerning our proved reserves, production, wells, acreage and related matters, see Item 1,“Business — Natural Gas and Oil Data” in this Annual Report on Form 10-K.

      Our obligations under our credit facility are secured by mortgages on our natural gas and oil properties. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities — Credit Facility” in this Annual Report on Form 10-K for additional information concerning our credit facility.

      We currently lease approximately 13,000 square feet of office space in Pittsburgh, Pennsylvania at 650 Washington Road, where our principal offices are located. The lease for our Pittsburgh office expires in September 2012. We also lease an additional 5,000 square feet of office space in Pittsburgh, Pennsylvania, for which the lease expires in March 2009. We lease approximately 3,000 square feet of office space in Houston, Texas. The lease for our Houston office expires in April 2008. We also have field offices in Bridgeport and Glenville, West Virginia and Indiana, Pennsylvania. Additionally, we have purchased property in Jane Lew, West Virginia where we intend to centralize certain of our West Virginia operations in 2006.

      Effective September 30, 2003, we purchased interests in natural gas and oil wells from Cabot Oil & Gas Corporation for an aggregate restated purchase price of $15.8 million. On September 27, 2005, Power Gas Marketing & Transmission Inc. filed a complaint styled Power Gas Marketing & Transmission, Inc. v. Cabot Oil & Gas Corporation and Linn Energy in the court of common pleas of Indiana County, Pennsylvania against Cabot and Linn Energy alleging that Cabot conveyed such interests to us in breach of purported preferential purchase rights. Power Gas alleges that Linn Energy interfered with Power Gas’ contract rights and demands the right to evaluate whether to exercise its purported preferential purchase rights. We believe that Power Gas’ allegations are without merit, intend to vigorously defend the matter and do not believe that the outcome of the matter would have a material adverse effect on our financial position and results of operations.

      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 various environmental protection statutes or other regulations to which we are subject.

      No matters were submitted to a vote of security holders during the fourth quarter of 2005.

PART II

      Our units are listed on The Nasdaq National Market under the symbol “LINE.” Our units began trading on January 13, 2006, in connection with our initial public offering. On May 8, 2006, the market price for our units was $20.00 per unit. On that date, there were 27,832,500 units outstanding and approximately 9,000 unitholders.

      The Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (the “LLC Agreement”) provides for the distribution of “available cash” (as defined below) on a quarterly basis to our unitholders. Available cash means, for any quarter prior to liquidation:

      The amount of available cash will be determined by our Board of Directors for each calendar quarter of our operations beginning with the quarter ended March 31, 2006.

      The terms of our secured revolving credit facility permit us to borrow under the facility to pay distributions to unitholders as long there has not been a default or event of default and if the amount of borrowings under the facility is less than 90% of the borrowing base. As we identified the need to restate our financial statements, we obtained necessary waivers of certain covenants to remain in compliance with the terms of the credit facility. The credit facility contains covenants limiting our ability to make distributions other than from available cash. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Credit Facility” in this Annual Report on Form 10-K for further information regarding our secured revolving credit facility.

Use of Securities Act Registration Statement Proceeds

      In the first quarter of 2006, Linn Energy, LLC completed its initial public offering of an aggregate of 12,450,000 units representing limited liability company interests (consisting of 11,750,000 units purchased by the underwriters on January 19, 2006 and 700,000 units purchased by the underwriters on February 15, 2006 pursuant to their option to purchase additional units) at an initial public offering price of $21.00 per unit in a firm commitment underwritten initial public offering pursuant to an S-1 Registration Statement (File No. 333-125501) declared effective by the Securities and Exchange Commission on January 12, 2006. RBC Capital Markets Corporation and Lehman Brothers Inc. acted as joint lead-managing underwriters of the offering.

      The aggregate initial public offering price for the units issued in our initial public offering was approximately $261.4 million. Net proceeds to the Company (after underwriting discounts of approximately $18.3 million and estimated offering expenses of approximately $6.7 million) were approximately $236.4 million, of which $122.0 million was used to reduce the Company’s then-existing indebtedness, an aggregate of $111.6 million was used to redeem a portion of the limited liability company membership interests and units held

by certain affiliates, and an aggregate of $2.8 million was used to redeem a portion of the limited liability company interests and units held by certain non-affiliates of the Company. See Item 13,“Certain Relationships and Related Transactions — Stakeholders’ Agreement — Redemption and Exchange” for further information. Estimated offering expenses included one-time bonuses aggregating $2.0 million to certain of our executive officers. See Item 11, “Executive Compensation — Employment Agreements; Change of Control Arrangements” for further information regarding these payments.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

      Set forth below is our selected historical consolidated financial data for the periods indicated for Linn Energy, LLC (Successor). The historical financial data for the periods ended December 31, 2003, 2004 and 2005 and the balance sheet data as of December 31, 2003, 2004 and 2005 have been derived from our audited financial statements.

      On October 31, 2003, we completed a $31.5 million (restated) acquisition of natural gas and oil assets from Waco Oil & Gas (Predecessor). The historical financial data for the period from January 1, 2003 through October 31, 2003 and the year ended December 31, 2002 have been derived from the audited financial statements of the Predecessor entity. The historical financial data for the year ended December 31, 2001 and the balance sheet data as of December 31, 2001 and 2002 have been derived from the unaudited financial statements of the Predecessor entity.

      You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K.

      Because of our rapid growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain other financial data may not be meaningful or indicative of future results.

      The following tables include a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with U.S. generally accepted accounting principles, or GAAP. Please see “Non-GAAP Financial Measure” on page 38.

SUMMARY RESERVE AND OPERATING DATA

      The following tables show estimated net proved reserves, based on reserve reports prepared by Schlumberger Data and Consulting Services, our independent petroleum engineer, and certain summary unaudited information with respect to our production and sales of natural gas and oil. You should refer to Item 1, “Business — Natural Gas and Oil Data — Proved Reserves and Production and Price History,” Item 1A, “Risk Factors,” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in evaluating the material presented below.

NON-GAAP FINANCIAL MEASURE

Adjusted EBITDA

      We define Adjusted EBITDA as net income (loss) plus:

      The costs of cancelling natural gas swaps before their original settlement date are the only adjustments to Adjusted EBITDA that require expenditure of cash. These costs were financed with borrowings under our credit facility, and such long term debt is recognized as an increase in cash flow from financing activities.

      Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any reserves by our Board of Directors) the cash distributions we expect to pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

      The following table presents a reconciliation of our consolidated net loss to Adjusted EBITDA:

      The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial and Operating Data” and the financial statements and related notes included elsewhere in this 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 Annual Report on Form 10-K, particularly in “Risk Factors” contained in Item 1A of this Annual Report on Form 10-K. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

      Linn Energy, LLC is an independent natural gas and oil development and acquisition company. At December 31, 2005, our reserves were located in the Appalachian Basin, primarily in West Virginia, Pennsylvania, New York and Virginia. From our inception in March 2003 through December 31, 2005, we made nine acquisitions of natural gas properties and related gathering and pipeline assets for a restated aggregate purchase price of $201.5 million, with total proved reserves of 160.1 Bcfe, or a restated acquisition cost of $1.26 per Mcfe. These nine acquisitions included 1,914 producing wells and we have drilled 200 wells since inception, 100% of which were successful in producing natural gas in commercial quantities, resulting in a total of 2,114 wells. As part of our business strategy, we continually evaluate opportunities to acquire additional natural gas and oil properties which complement our asset profile both within the Appalachian Basin and elsewhere in the United States.

      Our proved reserves at December 31, 2005 were 193.2 Bcfe, of which approximately 99% were natural gas and 65% were classified as proved developed, with a Standardized Measure of $552.1 million. At December 31, 2005, we operated 1,922, or 91%, of our 2,114 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 29 years based on our December 31, 2005 reserve report and annualized production for the quarter ended December 31, 2005. As of December 31, 2005, we had identified 905 drilling locations, of which 373 were proved undeveloped locations and 532 were other locations, and we had leasehold interests in approximately 145,686 net acres in the Appalachian Basin. From inception through December 31, 2005, we added 33.1 Bcfe of proved reserves through our drilling activities, at a finding and development cost of $1.31 per Mcfe, which includes the estimated development costs for proved undeveloped reserves.

      As of December 31, 2005, we had completed nine acquisitions of natural gas properties and related gathering and pipeline assets for a restated aggregate purchase price of $201.5 million, with total proved reserves of 160.1 Bcfe, or a restated acquisition cost of $1.26 per Mcfe.

      Because of our rapid growth through acquisitions and development of our properties, our 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.

      Our acquisitions were financed with a combination of private equity, proceeds from bank borrowings and cash flow from operations. Our activities are focused on evaluating and developing our asset base, increasing our acreage positions and evaluating potential acquisitions.

      As of December 31, 2005, we had 193.2 Bcfe of estimated net proved reserves with a Standardized Measure of $552.1 million, a 61% increase in reserves over December 31, 2004, when we had 119.8 Bcfe of estimated net proved reserves with a Standardized Measure of $215.0 million. Our December 31, 2005 and 2004 Standardized Measures were determined using a price of $10.08 and $6.18 per Mcf of natural gas, respectively, and $57.98 and $43.36 per Bbl of oil, respectively. Oil accounts for less than 3% of our production.

      Our revenue, 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. Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

      We utilize the successful efforts method of accounting for our natural gas and oil properties. Leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Generally, if a well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense.

      Higher natural gas and oil 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 natural gas prices, which are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices received. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations is dependent on our ability to manage our overall cost structure.

      We face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves 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 costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals.

Our Operations

      Our revenues are highly sensitive to changes in natural gas prices and levels of production. As set forth in “— Cash Flow from Operations” below, we have hedged a significant portion of our expected production, which allows us to mitigate, but not eliminate, natural gas price risk. Our expected increase in levels of production as a result of the anticipated drilling of 139 wells during 2006 is dependent on our ability to quickly and efficiently bring the newly drilled wells online. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of increase in our production, which may have an adverse effect on our revenues and as a result, cash available for distribution. 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 natural gas prices will affect the ability to drill additional wells and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in natural gas prices may have on the value of our proved reserves and their impact, if any, on any redetermination of the borrowing base under our credit facility.

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 lowest possible level. Accordingly, we continuously monitor our production and operating costs per well to determine if any wells should be shut in or sold.

Land and Lease Tracking System

      As a significant amount of our growth is dependent on drilling new wells, we continuously monitor our lease agreements and our drilling locations to avoid delays. Our monitoring system matches our lease agreements to existing wells and sites for future development allowing management to make real time decisions on which acreage to develop and at what point in time. We continually seek to acquire new lease positions to increase potential drilling locations.

Results of Operations

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