Index to Financial Statements

LINN was formed as a Delaware limited liability company in March 2003 by our President and Chief Executive Officer Michael C. Linn, Quantum Energy Partners and non-affiliated equity investors with an aggregate equity investment of $16.3$16 million. In January 2006, LINN completed its $261 million initial public offering. Since inception, we have made sevenits initial public offering, LINN has successfully executed on its strategy, and substantially grown its asset base and distributions on its units. LINN has increased its quarterly cash distribution by approximately 81% from $0.40 per unit, or $1.60 per unit on an annualized basis, at the time of its initial public offering, to $0.725 per unit, or $2.90 per unit on an annualized basis. At the time of its initial public offering, LINN’s assets consisted primarily of oil and natural gas properties in the Appalachian Basin, mainly in Pennsylvania, West Virginia, New York and Virginia (subsequently sold in 2008) with proved reserves of approximately 190 Bcfe as of September 30, 2005 and average daily production of approximately 13 MMcfe/d for the three months ended September 30, 2005. Since then, LINN has successfully grown and diversified its asset base to include properties across eight operating regions with total Pro Forma Proved Reserves of approximately 5.1 Tcfe and average daily production for the three months ended March 31, 2012 of approximately 471 MMcfe/d.

Business Strategy

LINN’s primary goal is to provide stability and growth of distributions for the long-term benefit of its unitholders. The following is a summary of the key elements of LINN’s business strategy:

LINN’s business strategy is discussed in more detail below.

Grow Through Acquisition of Long-Life, High Quality Properties. LINN’s acquisition program targets oil and natural gas properties that it believes will be financially accretive and offer stable, long-life, and high quality production with relatively predictable decline curves, as well as lower-risk development opportunities. LINN evaluates acquisitions based on decline profile, reserve life, operational efficiency, field cash flow, development costs and rate of return. As part of this strategy, LINN continually seeks to optimize its asset portfolio, which may include the divestiture of non-core assets. This allows LINN to redeploy capital into projects to develop lower-risk, long-life and low-decline properties that are better suited to its business strategy.

Since January 1, 2007, LINN has completed 38 acquisitions of oil and natural gas properties and related gathering and pipeline assets, for an aggregate purchase price of $82.5 million, with totalacquiring proved reserves totaling approximately 3.7 Tcfe at the date of 100.9 Bcfe, or an acquisition, cost of $0.82 per Mcfe. Our seven acquisitions included 1,234 producing wells and we have subsequently drilled 126 wells with a success rate of 100%. At May 31, 2005, our production was approximately 12.8 MMcfe per day from 1,360 wells.

        Our proved reserves at December 31, 2004 were 119.8 Bcfe, of which approximately 98% were natural gas and 62% were classified as proved developed. At May 31, 2005, we operated 1,303, or 96%, of our 1,360 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 30 years based on our 2004 year end reserve report and annualized production for the quarter ended March 31, 2005. As of December 31, 2004, we had identified 235 proved undeveloped drilling locations and 461 additional drilling locations and had a leasehold interest in 104,805 net acres in the Appalachian Basin, 77% of which have additional drilling potential. From inception through December 31, 2004, we added 17.2 Bcfe of proved natural gas and oil reserves through our drilling activities, at a finding and development cost of $0.99 per Mcfe.

Drilling

        Most of our wells are relatively shallow, ranging from 2,500 to 5,500 feet, and many are completed to multiple producing zones. Our average well cost for 2005 is expected to be approximately $200,000, resulting in average net reserves of 200 MMcfe. In general, our producing wells have stable production profiles and long-lived production, often with total projected economic lives in excess of 50 years. 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. 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 60 days (some as quickly as 11 days) after drilling has commenced.

        The Appalachian Basin is a mature producing region with well known geologic characteristics. 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 wells produce dry natural gas, which does not require processing.

        From inception through December 31, 2004, we spent $17.0 million and drilled 90 wells, all of which produce in commercial quantities, with an average finding and development cost of $0.99 per Mcfe. To carry out our active drilling program, we are currently utilizing three drilling rigs that are under contract for our 2005 drilling program. During 2005, we anticipate spending $20.2 million to drill 106 wells, 100 of which we will operate. As of May 31, 2005, we had drilled 36 out of our planned 106 wells.

Acquisition History

        We focus on acquisitions that allow us to:

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Increase production through workovers, addition of equipment, improved field operations as well as additional infill drilling and other development activities; and



•

Implement efficiencies through operational and administrative consolidation.

        Since inception, we have completed seven acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate purchase price of $82.5 million, with total proved reserves of 100.9 Bcfe, or an acquisition cost of $0.82 per Mcfe.

Natural Gas Prices

        Natural gas produced in the Appalachian Basin typically sells for a premium to New York Mercantile Exchange (NYMEX) natural gas prices due to the proximity to major consuming markets in the northeastern United States. For the year ended December 31, 2004, 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 $0.26 and $0.35 per Mcfe, respectively. In addition, most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices. As of December 31, 2004, our average realized natural gas prices, net of gathering fees, represented a $0.67 per Mcfe premium to NYMEX natural gas prices.

        We enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we exclusively use fixed price swaps to hedge NYMEX natural gas prices, which do not include the additional net premium we typically realize in the Appalachian Basin. For the twelve month period ending September 30, 2006, we currently have fixed price swaps in place for a total hedged amount of 4,931 MMMBtu, which represents approximately 79% of our total expected production volume of 6,226 MMcfe. The average hedge price is $7.53 per MMBtu. We currently have entered into fixed price swaps for a total hedged amount of 4,952 MMMBtu at an average price of $7.47 per MMBtu for 2006 and 4,528 MMMBtu at an average price of $7.03 per MMBtu for 2007. By removing the price volatility from a significant portion of our natural gas production, we have mitigated, but not eliminated, the potential effects of changing natural gas prices on our cash flow from operations for those periods.

Natural Gas Gathering

        We own and operate an extensive network of natural gas gathering systems and gather more than 90% of our production, which allows us to more efficiently transport our gas to market. Our gathering assets are comprised of 350 miles of pipeline, associated compression and metering facilities that connect to numerous sales outlets on eight intrastate as well as eight interstate pipelines. Our wholly owned subsidiary Chipperco, LLC owns an aggregate 46 miles of natural gas gathering systems. We transport our natural gas as well as a limited amount for third parties.

Business Strategy

        Our goal is to provide stability and growth in distributions to our unitholders through a combination of continued successful drilling and acquisitions that increase distributable cash per unit. The key elements of our business strategy are:

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Executing low risk, low cost exploitation drilling;



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Focusing on acquisitions that increase distributable cash per unit;



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Creating additional value post-acquisition;



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Maximizing the value and stability of our cash flows through operating control; and



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Reducing commodity price risk through hedging.

Competitive Strengths

        We believe our competitive strengths will result in a sufficient level of cash available for distribution and provide strong growth potential. Our competitive strengths are:

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Low Risk, Low Cost Exploitation Drilling — From inception through May 31, 2005, we drilled 126 wells with a success rate of 100%. From inception through December 31, 2004, our average finding and development cost was $0.99 per Mcfe. Our average well takes five days to drill and is expected to have an average cost of $200,000approximately $2.19 per Mcfe.

LINN continually evaluates potential acquisition opportunities that would further its strategic objectives and engages from time to time in 2005. Most of our wells are producing and connected to a pipeline within 60 days (some as quickly as 11 days) after drilling has commenced.



•

Strong Acquisition Track Record — To date, we have made seven acquisitionsdiscussions with an average purchase price of $0.82 per Mcfe. In addition, we have focused on production enhancement and cost reductions with respect to thepotential sellers. Assets acquired properties. We achieve production increases through well workovers, by installing additional equipment such as pump jacks or by conducting minor repairs on gathering lines to return previously shut-in wells to production. We believe that there is significant potential for future acquisitions in the Appalachian Basin due to the large number of small owner/operators in the region.



•

Large Undeveloped Land Base — At December 31, 2004, we had leases totaling 104,805 net acres with 235 identified proved undeveloped drilling locations and 461 additional identified drilling locations. We continually seek to acquire new lease positions to increase potential drilling locations.



•

Operating Control — As of May 31, 2005, we operated 1,303, or 96%, of our total 1,360 producing wells and we will operate 100 of the 106 wells targeted to be drilled during 2005. During 2004, more than 98% of our revenues were derived from wells we operated. In addition, we gather more than 90% of our existing and expected production. We target acquisitions that allow us to consolidate operational and administrative functions.



•

Experienced Operator in the Appalachian Basin — Michael C. Linn, our President and Chief Executive Officer, and key members of our management team have been involved in the natural gas and oil business in Appalachia for an average of 25 years and have a very successful track record of drilling and acquiring assets in the basin.



•

Long Life Reserves — Our average reserve life is 30 years based on our 2004 year end reserves and annualized production for the quarter ended March 31, 2005.



•

Production Diversification — At May 31, 2005, our production was approximately 12.8 MMcfe per day from 1,360 producing wells from four states in the Appalachian Basin, including 771 wells in Pennsylvania, 517 wells in West Virginia, 61 wells in New York and 11 wells in Virginia. Our largest well accounts for less than 2% of our total production. As a result of the large number of wells, damage to any one well or group of wells or the curtailment of a gathering system in one particular area is not likely toor more of such transactions may have a material adverse effect on our operating results and cash available for distribution.



•

Premium Pricing — As of December 31, 2004, our average realized natural gas prices, net of gathering fees, represented a $0.67 per Mcfe premium to NYMEX natural gas prices due to our proximity to major natural gas consuming markets in the northeastern United States and the relatively high Btu content associated with our production.

Summary of Risk Factors

        An investment in our units involves risks associated with our business, regulatory and legal matters, our limited liability company structure and the tax characteristics of our units. The following list of risk factors is not exhaustive. Please read carefully these and the other risks under the caption "Risk Factors" beginning on page 17.

Risks Related to Our Business


•

We may not have sufficient cash to pay the initial quarterly distribution in each quarter following establishment of cash reserves and payment of fees and expenses.



•

If we are unable to achieve the forecast results set forth in "Cash Available for Distribution," we may be unable to pay the full, or any, amount of the initial quarterly distribution on the units, in which event the market price of our units may decline substantially.



•

Natural gas prices are volatile and a decline in natural gas prices can significantly affect our financial results and impede our growth.



•

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.



•

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



•

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.



•

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.



•

Because we handle natural gas and other petroleum products in our businesses, 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.


Risks Related to Our Structure


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Our management and Quantum Energy Partners will own, in the aggregate, a controlling interest in us, with management and Quantum Energy Partners owning approximately 19.1% and 45.4%, respectively, of our units.



•

Each of our 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 if you have a claim relating to conflicts of interest.



•

You will experience immediate and substantial dilution of $17.92 per unit.



•

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

Tax Risks to Unitholders


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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.



•

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



•

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.



•

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



•

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.

OUR LLC STRUCTURE

        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) and Chipperco, LLC. We own, directly or indirectly, all of the ownership interests in our operating subsidiaries.

        Concurrently with this offering, a portion of our members' existing membership interests will be exchanged for units of Linn Energy, LLC, and we will redeem approximately $60.0 million of membership interests from Quantum Energy Partners, $1.5 million of membership interests from non-affiliated equity investors and $3.0 million of membership interests from Michael C. Linn.

        Following our initial public offering and the application of the related net proceeds and based on an assumed initial public offering price per unit of $20.00:

•

Our management will own 3,064,917 units, representing an aggregate 19.1% membership interest in us;



•

Quantum Energy Partners will own 7,296,038 units, representing an aggregate 45.4% membership interest in us; and



•

the public unitholders will own 5,510,000 units, representing an aggregate 34.3% membership interest in us.

        We will use any net proceeds from the exercise of the underwriters' over-allotment option to redeem the number of units from Quantum Energy Partners and the non-affiliated equity investors equal to the number of units issued upon the exercise of the over-allotment option. If the over-allotment option is exercised in full, Quantum Energy Partners' ownership of units will be reduced from 7,296,038 units to 6,490,286 units, or 40.4% of all then outstanding units, and the ownership interest of the public unitholders will increase to 6,336,500, or 39.5% of all the outstanding units.

        Quantum Energy Partners is a provider of private equity to exploration and production companies as well as midstream, natural gas storage and independent power companies in the United States and Canada with approximately $670 million under management. Affiliates of Quantum Energy Partners have established three energy investment funds and currently manages capital on behalf of over 30 United States and European non-affiliated institutions and individuals.

        Our board of directors has sole responsibility for conducting our business and for managing our operations. Our principal executive offices are located at 1700 North Highland Road, Suite 100, Pittsburgh, Pennsylvania 15241, and our telephone number is (412) 854-0470. We also maintain a corporate office at 600 Travis, Suite 6910, Houston, Texas 77002, and our Houston telephone number is (713) 223-0880.

        The following diagram depicts our organizational structure after our initial public offering:

(1)

Does not include 187,869 units (or 1.2% of all outstanding units) owned by non-affiliated equity investors.

(2)

Includes Michael C. Linn, our President and Chief Executive Officer; Kolja Rockov, our Executive Vice President and Chief Financial Officer; Gerald W. Merriam, our Executive Vice President-Engineering Operations; and Roland P. Keddie, our Executive Vice President-Secretary.

(3)

If the over-allotment option is exercised in full, Quantum Energy Partners' ownership in us will be reduced to 6,490,286 units, or 40.4% of all outstanding units, and the ownership interest of the public unitholders will increase to 6,336,500 units, or 39.5% of all then outstanding units.

THE OFFERING

SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED
FINANCIAL AND OPERATING DATA

        Set forth below is our summary historical and pro forma consolidated financial and operating data for the periods indicated. The historical financial data for the periods ended December 31, 2003 and 2004 and the balance sheet data as of December 31, 2003 and 2004 have been derived from our audited financial statements. The historical financial data for the quarters ended March 31, 2004 and 2005 and the balance sheet data as of March 31, 2005 are derived from our unaudited financial statements included in this prospectus. The pro forma financial data gives effect to the properties acquired from Mountain V Oil & Gas, Inc. and Pentex Energy, Inc. in 2004 as if they occurred on January 1, 2004. 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 prospectus. You should also read the pro forma information together with the Unaudited Pro Forma Financial Statements and related notes included in this prospectus.

        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.

        The following table presents a non-GAAP financial measure, distributable cash flow, which we use in our business. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measure calculated and presented in accordance with GAAP in "— Non-GAAP Financial Measure" beginning on page 16.

(1)

During the quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the money natural gas swaps for the fourth quarter of 2005, and the years ending December 31, 2006 and 2007, and realized a loss of $8.0 million. We subsequently hedged similar volumes at higher prices.

(2)

The natural gas swaps that were established in 2003 and 2004, were not specifically designated as hedges under Statement of Financial Accounting Standards (SFAS) No. 133, even though they reduce our exposure to changes in natural gas prices. Therefore, the mark to market of these instruments was recorded in our current earnings. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. Further, these amounts represent non-cash charges.

(3)

The interest rate swaps that were established in 2003 and 2004 were not specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to changes in interest rates. Therefore, the mark to market of these instruments was recorded in our current earnings. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. Further, these amounts represent non-cash items.

(1)

In December 2003, we borrowed approximately $18 million under our credit facility to pay the remaining purchase price for the Waco acquisition, which amount was paid to Waco on January 2, 2004.

SUMMARY RESERVE AND OPERATING DATA

        The following tables show estimated net proved reserves, based on reserve reports prepared by our independent petroleum engineers (attached to this prospectus as Appendix D) and certain summary unaudited information with respect to our production and sales of natural gas and oil. You should refer to "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business — Natural Gas and Oil Data — Proved Reserves and Production and Price History" and the reserve report included in this prospectus in evaluating the material presented below.

(1)

Excludes estimated proved reserves as of December 31, 2004 of 3.8 Bcfe associated with the Columbia Natural Resources properties we purchased on April 27, 2005.

(2)

PV-10 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 Securities and Exchange Commission (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%. PV-10 does not give effect to derivative transactions. For a description of our derivative transactions, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations" beginning on page 54.

(3)

Natural gas and oil prices as of each period end were based on NYMEX prices per MMBtu and Bbl at such date, with these representative prices adjusted by field to arrive at the appropriate net price. As of December 31, 2004, our average realized natural gas prices, net of gathering fees, represented a $0.67 per Mcfe premium to NYMEX natural gas prices.

(4)

In the period ended December 31, 2003, production commenced on May 30, 2003 following the purchase of natural gas properties from Emax Oil Company.

NON-GAAP FINANCIAL MEASURE

Distributable Cash Flow

        We define distributable cash flow as net income (loss) plus:

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Depreciation, depletion and amortization;



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Amortization of deferred financing fees;



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(Gain) loss on sale of assets;



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(Gain) loss from equity investment;



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Accretion of asset retirement obligation;



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Unrealized (gain) loss on natural gas swaps;



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Unrealized (gain) loss on interest rate swaps; and



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Realized (gain) loss on cancelled natural gas swaps.

        Distributable cash flow 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. Distributable cash flow 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 income to distributable cash flow:

(1)

During the quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the-money natural gas swaps for the fourth quarter of 2005, and for the years ending December 31, 2006 and 2007, and realized a loss of $8.0 million. We subsequently hedged similar volumes at higher prices.

RISK FACTORS

Membership interests in a limited liability company are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our units.

The following risks could materially and adversely affect our business, financial condition or results of operations. If any of the events described below were to occur, we may not be able to pay the initial quarterly distribution on our units, the trading price of our units could decline and you could lose part or all of your investment in our company.

Risks Related to Our Business

We may not have sufficient cash to pay the initial quarterly distribution in each quarter following establishment of cash reserves and payment of fees and expenses.

        We may not have sufficient available cash each quarter to pay the initial quarterly distribution. 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:

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the amount of natural gas we produce;



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the price at which we are able to sell our natural gas production;



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the level of our operating costs;



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the level of our interest expense which depends on the amount of our indebtedness and the interest payable thereon; and



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the level of our maintenance and drilling expenditures.

        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:

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the level of capital expenditures we make;



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the cost of acquisitions, if any;



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our debt service requirements;



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fluctuations in our working capital needs;



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timing and collectibility of receivables;



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restrictions on distributions contained in our credit facility;



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our ability to make working capital borrowings under our credit facility to pay distributions;



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prevailing economic conditions; and

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the amount of cash reserves established by our board of directors for the proper conduct of our business.

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

        The amount of available cash we will need to pay the initial quarterly distribution for four quarters on the units to be outstanding immediately after this offering is approximately $    million. If we had completed the transactions contemplated in this prospectus on January 1, 2004, pro forma available cash generated during the year ended December 31, 2004 would have been approximately $10.3 million. The amount of pro forma cash available for distribution during 2004 would have been sufficient to allow us to pay approximately    % of the initial quarterly distributions on our units during this period. For a calculation of our ability to make distributions to you based on our pro forma results for the year ended December 31, 2004, please read "Cash Available for Distribution" and Appendix C included elsewhere in this prospectus.

        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. Giving effect to the use of the net proceeds from this offering, our borrowings under the credit facility as of May 31, 2005 would have been approximately $63.5 million, or 58% of our current borrowing base of $109 million.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not directly on profitability.

        The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings. Cash available for distribution is not dependent directly on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

If we are unable to achieve the forecast results set forth in "Cash Available for Distribution," we may be unable to pay the full, or any, amount of the initial quarterly distribution on the units, in which event the market price of our units may decline substantially.

        The summarized forecast results set forth in "Cash Available for Distribution" are for the 12 months ending September 30, 2006. Our management has prepared the forecast information and we have not received an opinion or report on it from any independent accountants. In addition, "Cash Available for Distribution" includes a calculation of distributable cash flow. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full, or any, amount of the initial quarterly distribution, in which event the market price of our units may decline substantially.

Natural gas prices are volatile and a decline in natural gas prices can significantly affect our financial results and impede our growth.

        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:

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the domestic and foreign supply of and demand for natural gas;



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the price and level of foreign imports;



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the level of consumer product demand;



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weather conditions;



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overall domestic and global economic conditions;



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political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;



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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;



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the impact of the U.S. dollar exchange rates on natural gas and oil prices;



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technological advances affecting energy consumption;



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domestic and foreign governmental regulations and taxation;



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the impact of energy conservation efforts;



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the proximity and capacity of natural gas pipelines and other transportation facilities; and



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the price and availability of alternative fuels.

        In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the 12 months ended December 31, 2004, the NYMEX natural gas index price ranged from a high of $8.14 per MMBtu to a low of $4.40 per MMBtu.

        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 business, financial condition and results of operations.

        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, 2004 reserve report, our average decline rate for proved reserves is 7.5% during the first five years, 4.5% in the next five years and less than 4% thereafter. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2004, 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 ourLINN’s business, financial condition and results of operations.

Efficiently Operate and Develop Acquired Properties. LINN has centralized the operation of its acquired properties into defined operating regions to minimize operating costs and maximize production and capital efficiency. LINN maintains a large inventory of drilling and optimization projects within each operating region to achieve organic growth from its capital development program. LINN generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects that not only replace production, but add value through reserve and production growth and future operational synergies. LINN’s development program is focused on lower-risk, repeatable drilling opportunities to maintain and/or grow cash flow. Many of the wells

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are completed in multiple producing zones with commingled production and long economic lives. In addition, LINN’s experienced workforce and scalable infrastructure facilitate the efficient development of its properties.

Reduce Cash Flow Volatility Through Hedging. LINN seeks to hedge a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to pay distributions, service debt and manage its business. By removing a significant portion of the price volatility associated with future production, LINN expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices.

These commodity hedging transactions are primarily in the form of swap contracts and put options that are designed to provide a fixed price (swap contracts) or fixed price floor with the opportunity for upside (put options) that LINN will receive as compared to floating market prices. As of May 31, 2012, LINN had derivative contracts in place for 2012 through 2017 at average prices ranging from a low of $91.04 per Bbl to a high of $98.56 per Bbl for oil and from a low of $4.53 per MMBtu to a high of $5.43 per MMBtu for natural gas. Additionally, LINN has derivative contracts in place covering a substantial portion of its natural gas basis exposure to Panhandle, MichCon and Permian differentials through 2015 and Houston Ship Channel differentials through 2016 and its timing risk exposure on Mid-Continent, Hugoton Basin and Permian Basin oil sales through 2017. LINN also intends to enter into additional derivatives contracts in connection with the Jonah Acquisition.

In addition, LINN may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. Currently, LINN has no outstanding interest rate swaps.

Competitive Strengths

LINN believes the following strengths provide significant competitive advantages:

Large and High Quality Asset Base with a Long Reserve Life. LINN’s reserve base is characterized by lower geologic risk and well-established production histories and exhibits low production decline rates. Based on LINN’s total proved reserves at December 31, 2011, and annualized production for the three months ended December 31, 2011, LINN had an average reserve-life index of approximately 22 years. LINN’s Pro Forma Proved Reserves are also diversified by product with approximately 25% oil, 55% natural gas and 20% natural gas liquids (“NGL”), with approximately 66% classified as proved developed.

Significant Inventory of Lower-Risk Development Opportunities. LINN has a significant inventory of projects in its core areas that it believes will support its development activity. At December 31, 2011, LINN had approximately 6,450 identified drilling locations, of which approximately 2,300 were proved undeveloped drilling locations and the remainder were unproved drilling locations. During the year ended December 31, 2011, LINN drilled a total of 294 gross wells with an approximate 99% success rate.

Significant Scale of Operations. As of June 1, 2012, LINN had interests in approximately 15,000 gross productive wells (approximately 71% operated) and approximately 1.8 million net acres across seven regions in the U.S. The Mid-Continent, Hugoton Basin and Permian Basin regions account for approximately 69% of LINN’s Pro Forma Proved Reserves. The scale of operations allows LINN to benefit from economies of scale in both drilling and production operations and capitalize on acquired technical knowledge to lower production costs and maintain a high success rate on its drilling program. Furthermore, LINN owns integrated gathering and transportation infrastructure in the Mid-Continent and Hugoton Basin regions, which improves LINN’s cost structure.

Multi-Year Organic Growth Opportunities. In addition to growth through acquisitions, LINN’s asset base provides significant opportunities to grow production organically. Key drivers of LINN’s organic growth potential include its properties in the Granite Wash play in the Mid-Continent region and the Wolfberry trend in

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the Permian Basin region. LINN has approximately 95,000 net acres in the Granite Wash play, which covers a trend extending from the Texas Panhandle eastward into southwestern Oklahoma. The Granite Wash play is characterized by liquids-rich multi-layer reservoirs which provide for attractive horizontal development opportunities. Since the inception of LINN’s horizontal drilling program in the Granite Wash in 2009, LINN has increased production to approximately 137 MMcfe/d (43% liquids). As of March 31, 2012, LINN had identified more than 600 horizontal drilling locations in the Granite Wash and multiple vertical infill drilling locations, representing a 10-plus year drilling inventory. LINN is also evaluating several oil-bearing intervals in the Texas Panhandle including the Hogshooter, Lansing, Cleveland and Tonkawa formations. As a result of technical mapping, LINN has already identified approximately 50 additional well locations in the Hogshooter interval. In the Permian Basin region, LINN owns 31,000 net acres in the Wolfberry trend (targeting the liquids-rich Spraberry and Wolfcamp zones). The Wolfberry trend offers significant growth potential driven primarily by infill drilling and downspacing. Since entering the Permian Basin in the fall of 2009, LINN has increased production to approximately 14,800 Boepd as of the first quarter of 2012 through a combination of organic development and acquisitions. LINN estimates that it has a four-year drilling inventory with approximately 400 future drilling locations in the Wolfberry trend.

High Percentage of Production Hedged. Currently, LINN hedges its production with swap contracts and put options to minimize its cash flow volatility while maintaining optionality for future upward movement in commodity prices. Swap contracts provide a fixed price and put options provide a fixed price floor with opportunity for upside that LINN will receive as compared to floating market prices. Based on current production estimates, LINN is approximately 100% hedged on expected natural gas production through 2017 and 100% hedged on expected oil production through 2016. LINN also intends to enter into additional derivatives contracts in connection with the Jonah Acquisition.

High Percentage of Operated Properties. For the year ended December 31, 2011, approximately 82% of LINN’s production came from wells over which it had operating control. Maintaining control of its properties allows LINN to use its technical and operational expertise to manage overhead, production, drilling costs and capital expenditures and to control the timing of development activities.

Competitive Cost of Capital and Financial Flexibility. Unlike many master limited partnerships, LINN does not have any incentive distribution rights, or IDRs, that entitle the IDR holders to increasing percentages of cash distributions as unit distributions grow. LINN believes that its lack of IDRs provides it with a lower cost of equity, thereby enhancing its ability to compete for future acquisitions.

Additionally, LINN has regularly and successfully raised significant capital throughout different financial cycles. Since LINN’s initial public offering in January 2006, it has raised approximately $5.2 billion in follow-on equity offerings and approximately $5.4 billion in debt offerings. Furthermore, as of March 31, 2012, LINN’s revolving credit facility had a $2.6 billion borrowing base, subject to a maximum commitment of $2 billion. LINN believes this financial flexibility and access to the capital markets provides LINN with a substantial competitive advantage in consummating acquisitions.

Recent Developments

Acquisitions

Jonah Acquisition. On June 21, 2012, LINN entered into a purchase agreement in connection with the Jonah Acquisition for a contract price of approximately $1.025 billion. LINN anticipates the Jonah Acquisition will close on or before July 31, 2012, and will be financed with the proceeds from borrowings under its revolving credit facility. In addition to customary closing conditions, the Jonah Acquisition is subject to a preferential right of purchase that encompasses substantially all of the properties. The expiry period for waiver or acceptance of

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the preferential right of purchase is anticipated during the first week of July 2012. The Jonah Acquisition includes approximately 753 Bcfe of estimated proved reserves. The estimated proved reserves for the Jonah Acquisition were based on LINN’s preliminary internal evaluation of information provided by the seller.

East Texas Acquisition. On May 1, 2012, LINN completed the East Texas Acquisition for total consideration of approximately $168 million. The properties acquired in east Texas include (1) proved reserves of approximately 110 Bcfe, all of which are proved developed producing; (2) approximately 430 producing wells on approximately 19,800 contiguous acres; and (3) average daily production of approximately 24 MMcfe/d (97% natural gas).

Hugoton Acquisition. On March 30, 2012, LINN completed the Hugoton Acquisition for total consideration of approximately $1.17 billion. The properties acquired in the Hugoton Acquisition included: (1) proved reserves of approximately 701 Bcfe, of which 100% is proved developed; (2) approximately 2,400 producing wells with average daily production of approximately 110 MMcfe/d, of which approximately 63% is natural gas and 37% is NGL; (3) more than 800 future drilling locations, including over 400 proved locations; and (4) the JayHawk Natural Gas Processing Plant, which processes substantially all of the production from the acquired properties, with 450 MMcf/d of processing capacity.

Joint Venture

Anadarko Joint Venture. On April 3, 2012, LINN entered into the Anadarko Joint Venture, whereby LINN will participate as a partner in the CO₂-enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming. Anadarko assigned LINN 23% of its interest in the field in exchange for future funding by LINN of $400 million of Anadarko’s development costs. LINN expects to invest a total of $600 million in the joint venture over the next three to six years, which includes the $400 million of Anadarko’s costs and $200 million net to LINN’s assigned interest. Anadarko has been utilizing CO₂ to develop this field since 2004. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the agreement date.

The acquisitions and joint venture described above are referred to in this prospectus as the “2012 Acquisitions.”

Questions and Answers About LinnCo

Why is LinnCo being created?

LinnCo is being created to enhance LINN’s ability to raise additional equity capital to execute on its acquisition and growth strategy. As LINN continues to grow, the size of individual acquisitions it pursues and its related financing needs are expected to increase. LINN believes that the LinnCo structure will allow LINN to expand its investor base through offerings of LinnCo shares, the proceeds of which will go to LINN for use in executing its strategy, in return for a number of LINN units equal to the number of LinnCo shares sold.

Why does LINN believe that LinnCo will enhance LINN’s ability to raise equity?

LinnCo will be taxed as a corporation, which will enable holders of LinnCo shares to invest indirectly in LINN without the associated tax-related obligations of owning a LINN unit. For example, holders of LinnCo shares will receive a Form 1099-DIV rather than a Schedule K-1, will generally not have unrelated business taxable income, or UBTI, and will not be required to file state income tax returns as a result of owning LinnCo shares. LINN believes that this structure will appeal to investors that would like to invest in a dividend-paying oil and natural gas exploration and production company, but currently do not invest in LINN units because of UBTI consequences and more onerous tax reporting requirements.

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Why doesn’t LINN just increase the size of its LINN unit offerings?

While LINN has been one of the most active energy-focused master limited partnership equity issuers in recent years, we believe that expanding the investor base to include institutions, individual retirement accounts, foreign investors and tax-exempt investors will provide LINN with equity-raising opportunities significantly beyond its current capacity.

How will LinnCo quarterly dividends be determined?

LinnCo will own a number of LINN units equal to the number of LinnCo shares outstanding and will receive the same distribution per LINN unit as all other LINN unitholders. When LinnCo receives a quarterly distribution from LINN, it will reserve an amount equal to LinnCo’s estimated income tax liability, and will distribute the balance as a dividend to LinnCo shareholders. We currently estimate that for the periods ending December 31, 2012, 2013, 2014 and 2015, LinnCo’s income tax liability will not exceed         % of the cash LINN distributes to us. Accordingly, if LINN were to maintain its current annualized distribution of $2.90 per unit through 2015, the annual LinnCo dividend would not be less than $             per share.

What rights will LinnCo shareholders have with respect to the governance of LINN and LinnCo?

LinnCo will submit to a vote of its shareholders any matter submitted by LINN to a vote of its unitholders, which will include the annual election of the LINN board of directors. LinnCo will vote the LINN units it holds in the same manner as our shareholders vote on those matters. Our shareholders will also be entitled to vote on certain fundamental matters affecting LinnCo, but will not have the right to elect the LinnCo board of directors. LINN holds the sole voting share in LinnCo, and therefore will elect the LinnCo board. LinnCo’s initial board of directors will be composed of the same members as LINN’s board of directors.

Will there be future offerings of LinnCo shares?

As LINN continues to execute on its acquisition and growth strategy, it expects to continue to require additional equity capital. LinnCo may make future sales of LinnCo shares to facilitate this strategy, and such future sales may be made separately or in tandem with future sales of LINN units depending on, among other factors, the amount of equity capital to be raised and the relative trading prices of the LinnCo shares and the LINN units. Any proceeds from the sale of both LinnCo shares and LINN units will ultimately be used by LINN to execute its strategy.

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Risk Factors

An investment in our shares involves risks. You should carefully consider the risks described in “Risk Factors” beginning on page 29 of this prospectus and the other information in this prospectus before deciding whether to invest in our shares.

Risks Related to LINN’s Business

Risks Inherent in an Investment in LinnCo

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Tax Risks to Shareholders

Management of LinnCo

LINN owns our sole voting share (the “voting share,” and collectively with any additional shares of the same class issued in the future, the “voting shares”) and will be entitled to elect our entire board of directors.

Our initial board of directors will be identical to LINN’s board of directors, and all of our officers are also officers of LINN. Our shareholders will be able to indirectly vote on matters on which LINN unitholders are entitled to vote. Our shareholders are not entitled to vote to elect our directors. Under NASDAQ’s listing rules, we are considered a “controlled company” such that our board of directors will be exempt from the requirement that it have a majority of independent directors meeting the NASDAQ’s independence standards. We will, however, be required to have an audit committee of the board of directors composed entirely of independent directors. At the completion of this offering, our board of directors will be comprised of seven directors, including five independent directors constituting our audit committee. For information about our executive officers and directors, please read “Management” beginning on page 106.

Comparison of LINN Units with LinnCo Shares

You should be aware of the following ways in which an investment in LINN units is different from an investment in our shares. The table below should be read together with “Description of Our Shares,” “Description of the LINN Units,” Description of the Limited Liability Company Agreements,” and “Material U.S. Federal Income Tax Consequences.”

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Ownership of LINN

The following diagram depicts LINN’s simplified organizational and ownership structure after giving effect to this offering and to the subsequent purchase of LINN units by us.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 600 Travis, Suite 5100, Houston, Texas 77002, and our telephone number is (281) 840-4000. Our website is located atwww..com and will be activated immediately following this offering. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

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The Offering

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Summary Historical and Pro Forma Financial and Operating Data of LINN

The following table shows summary historical and pro forma financial and operating data of LINN as of the dates and for the periods indicated. The selected historical financial data presented as of December 31, 2010 and 2011 and for the years ended December 31, 2009, 2010 and 2011 are derived from the historical audited financial statements that are included elsewhere in this prospectus. The selected historical financial data of LINN presented as of March 31, 2012 and for the three months ended March 31, 2011 and 2012 are derived from the unaudited interim financial statements that are included elsewhere in this prospectus. The summary pro forma financial data presented for the year ended December 31, 2011 and the three months ended March 31, 2012 are derived from the unaudited pro forma condensed combined financial statements that are included elsewhere in this prospectus. The pro forma financial data presented for the year ended December 31, 2011 and the three months ended March 31, 2012 give effect to the Hugoton Acquisition and certain other 2011 acquisitions. The following table should be read together with, and is qualified in its entirety by reference to, the historical and unaudited financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The unaudited pro forma financial statements do not purport to represent what LINN’s results of operations would have actually been had the Hugoton Acquisition occurred on the dates noted above, or to project LINN’s results of operations as of any future date or for any future periods. The pro forma adjustments are based on available information and certain assumptions that LINN believes are reasonable. The adjustments are directly attributable to the acquisition of oil and natural gas properties from the Hugoton Acquisition included and are expected to have a continuing impact on LINN’s results of operations. In our opinion, all adjustments necessary to present fairly the unaudited pro forma condensed combined financial statements have been made.

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Because of rapid growth through acquisitions and development of properties, LINN’s 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 results of LINN’s Appalachian Basin and Mid Atlantic Well Service, Inc. operations, which were disposed of in 2008, are classified as discontinued operations, due to post-closing adjustments, for the year ended December 31, 2009. Unless otherwise indicated, results of operations information presented herein relates only to continuing operations.

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Summary Reserve and Operating Data

The following table presents summary unaudited operating data with respect to LINN’s production and sales of oil and natural gas for the periods presented and summary information with respect to LINN’s estimated proved oil and natural gas reserves at year end. DeGolyer and MacNaughton, independent petroleum engineers, provided the estimates of LINN’s proved oil and natural gas reserves as of December 31, 2009, 2010 and 2011 set forth below.