**UNITEDSTATES SECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

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**FORM10-K**

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| x                                                     |   | **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d)  OF THE SECURITIES EXCHANGE ACT OF 1934**     |
|-------------------------------------------------------|--------|------------------------------------------------------------------------------------------------|
|                                                  |   | ** **                                                                                     |
| **For the  fiscal year ended December 31, 2006** |   |
| ** **                                            |   | ** **                                                                                     |
| o                                                     |   | **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15  (d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
|                                                  |   | ** **                                                                                     |
|                                                       |        |                                                                                                |  |

**Commissionfile number:  000-51719**

**LINN ENERGY, LLC**

(Exact name of registrant as specified in its charter)

| **Delaware**                              |   | **65-1177591**       |
|-------------------------------------------|--------|----------------------|
| (State or other  jurisdiction of          |   | (I.R.S. Employer     |
|  incorporation or organization)      |   | Identification  No.) |
| * *                                  |   | * *             |
| **600  Travis Street, Suite 7000**        |   | ** **           |
| **Houston,  Texas**                       |   | **77002**            |
| (Address of  principal executive offices) |   | (Zip Code)           |

 

Registrant’s telephonenumber, including area code

**(281)605-4100**

Securitiesregistered pursuant to Section 12(b) of the Act:

| Title of each class                                     | ** ** | **Name of each exchange on which registered** |
|---------------------------------------------------------|------------|-----------------------------------------------|
| Units  Representing Limited Liability Company Interests |       | The NASDAQ Stock  Market LLC                  |

 

Securities registeredpursuant to Section 12(g) of the Act:

**None**

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

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

Indicate by checkmark whether registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days.    Yes    **x**       No    o

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to thebest of registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or anyamendment to this Form 10-K.     o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer.  See definition of“accelerated filer and large accelerated filer” in Rule 12b-2 of the ExchangeAct.  (check one):

Large acceleratedfiler    o            Accelerated filer    o            Non-accelerated filer    x

Indicate by check-markwhether the registrant is a shell company (as defined in Rule 12b-2 of theAct).

Yes    o       No   **x**

The aggregatemarket value of our voting and non-voting common equity held by non-affiliatesof the registrant was approximately $276,160,952 million on June 30, 2006,based on $20.95 per unit, the last reported sales price of the units on TheNASDAQ Global Market on such date.

As of February 28, 2007,there were 50,303,019 units outstanding.

As of February 28,2007, there were 7,465,946 Class C units outstanding.

**DocumentsIncorporated By Reference:**

Certain information called for in Items 10, 11, 12, 13 and 14 of Part IIIare incorporated by reference from the registrant’s definitive proxy statementfor the annual meeting of unitholders to be held on June 19, 2007.

 

 

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**TABLE OF CONTENTS**
|           | ** ** | ** **                                                                                                         | ** ** | **Page** | ** ** |
|-----------|------------|--------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
|      | ** ** | **Glossary of Terms**                                                                                              |       |     | ii         |   |   |
|      |       |                                                                                                               |       |     |       |   |   |
|      | ** ** | **Part I**                                                                                                         |       |     |       |   |   |
|      | ** ** | ** **                                                                                                         |       |     |       |   |   |
| Item  1.  |       | Business and Properties                                                                                            |       |     | 1          |   |   |
| Item  1A. |       | Risk  Factors                                                                                                      |       |     | 17         |   |   |
| Item 1B.  |       | Unresolved Staff Comments                                                                                          |       |     | 28         |   |   |
| Item 2.   |       | Properties                                                                                                         |       |     | 29         |   |   |
| Item  3.  |       | Legal  Proceedings                                                                                                 |       |     | 29         |   |   |
| Item 4.   |       | Submission of Matters to a Vote of Security Holders                                                                |       |     | 29         |   |   |
|      |       |                                                                                                               |       |     |       |   |   |
|      | ** ** | **Part II**                                                                                                        |       |     |       |   |   |
|      | ** ** | ** **                                                                                                         |       |     |       |   |   |
| Item 5.   |       | Market for Registrant’s Common Equity, Related  Stockholder Matters and Issuer Purchases of Equity Securities |       |     | 30         |   |   |
| Item  6.  |       | Selected  Financial Data                                                                                           |       |     | 33         |   |   |
| Item 7.   |       | Management’s Discussion and Analysis of Financial  Condition and Results of Operation                         |       |     | 37         |   |   |
| Item 7A.  |       | Quantitative and Qualitative Disclosures About Market  Risk                                                        |       |     | 56         |   |   |
| Item 8.   |       | Financial Statements and Supplementary Data                                                                        |       |     | 57         |   |   |
| Item 9.   |       | Changes in and Disagreements With Accountants on  Accounting and Financial Disclosure                              |       |     | 94         |   |   |
| Item 9A.  |       | Controls and Procedures                                                                                            |       |     | 94         |   |   |
| Item 9B.  |       | Other  Information                                                                                                 |       |     | 95         |   |   |
|      |       |                                                                                                               |       |     |       |   |   |
|      | ** ** | **Part III**                                                                                                       |       |     |       |   |   |
|      | ** ** | ** **                                                                                                         |       |     |       |   |   |
| Item 10.  |       | Directors, Executive Officers and Corporate Governance                                                             |       |     | 96         |   |   |
| Item 11.  |       | Executive  Compensation                                                                                            |       |     | 96         |   |   |
| Item 12.  |       | Security  Ownership of Certain Beneficial Owners and Management and Related Stockholder  Matters                   |       |     | 96         |   |   |
| Item 13.  |       | Certain  Relationships and Related Transactions, and Director Independence                                         |       |     | 96         |   |   |
| Item 14.  |       | Principal  Accounting Fees and Services                                                                            |       |     | 96         |   |   |
|      |       |                                                                                                               |       |     |       |   |   |
|      | ** ** | **Part IV**                                                                                                        |       |     |       |   |   |
|      | ** ** | ** **                                                                                                         |       |     |       |   |   |
| Item 15.  |       | Exhibits and  Financial Statement Schedules                                                                        |       |     | 97         |   |   |
|      |       |                                                                                                               |       |     |       |   |   |
|      | ** ** | **Signatures**                                                                                                     |       |     | 98         |   |   |

 

i

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**GLOSSARY OFTERMS**

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

*Bbl. *One stock tank barrel or 42United States gallons liquid volume.

*Bcf.*  One billion cubic feet.

*Bcfe.*  One billion cubic feet equivalent, determinedusing a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gasliquids.

*Btu.*  One British thermal unit, which is the heatrequired to raise the temperature of a one-pound mass of water from 58.5 to59.5 degrees Fahrenheit.

*Development well.*  A well drilled within the proved area of anoil or gas reservoir to the depth of a stratigraphic horizon known to beproductive.

*Dth.*  One decatherm, equivalent to one millionBritish 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 sufficientquantities such that proceeds from the sale of such production would exceedproduction expenses and taxes.

*Field.*  An area consisting of a single reservoir ormultiple reservoirs all grouped on or related to the same individual geologicalstructural feature and/or stratigraphic condition.

*FERC. *FederalEnergy Regulatory Commission.

*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 oil or other liquidhydrocarbons.

*Mcf.*  One thousand cubic feet.

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

*MMBbls.*  One million barrels of oil or other liquidhydrocarbons.

*MMboe.*  One million barrels of oil equivalentdetermined using a ratio of six Mcf of gas to one Bbl of oil, condensate ornatural gas liquids.

*MMBtu.*  One million British thermal units.

*MMcf.*  One million cubic feet.

*MMcfe.*  One million cubic feet equivalent, determinedusing a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gasliquids.

*MMcfe/d.* One MMcfe per day.

*MMMBtu.*  One billion British thermal units.

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

*NGLs.*  Natural gas liquids, which are thehydrocarbon liquids contained within gas.

*NYMEX.*  The New York Mercantile Exchange.

*Oil.*  Crude oil, condensate and natural gasliquids.

*Productive well.*  A well that is found to be capable ofproducing hydrocarbons in sufficient quantities such that proceeds from thesale of such production exceeds production expenses and taxes.

*Proved developed reserves.*  Reserves that can be expected to be recoveredthrough existing wells with existing equipment and operating methods.  Additional oil and gas expected to beobtained through the application of fluid injection or other improved recoverytechniques for supplementing the natural forces and mechanisms of primaryrecovery are included in “proved developed reserves” only after testing by apilot project or after the operation of an installed program has confirmedthrough production response that increased recovery will be achieved.

ii

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*Proved reserves.*  Proved oil and gas reserves are the estimatedquantities of gas, natural gas liquids and oil which geological and engineeringdata demonstrate with reasonable certainty to be recoverable in future yearsfrom known reservoirs under existing economic and operating conditions, i.e., prices and costs as of thedate the estimate is made.  Pricesinclude consideration of changes in existing prices provided only bycontractual arrangements, but not on escalations based on futureconditions.  The definition of provedreserves is in accordance with the Securities and Exchange Commission’sdefinition set forth in Regulation S-X Rule 4-10 (a) and its subsequent staff interpretations and guidance.

*Proved undeveloped drilling location.*  A site on which a development well can bedrilled consistent with spacing rules for purposes of recovering provedundeveloped reserves.

*Proved undeveloped reserves* or*PUDs. *Reservesthat are expected to be recovered from new wells on undrilled acreage or fromexisting wells where a relatively major expenditure is required forrecompletion.  Reserves on undrilledacreage are limited to those drilling units offsetting productive units thatare reasonably certain of production when drilled.  Proved reserves for other undrilled units areclaimed only where it can be demonstrated with certainty that there iscontinuity of production from the existing productive formation.  Estimates for proved undeveloped reserves arenot attributed to any acreage for which an application of fluid injection orother improved recovery technique is contemplated, unless such techniques havebeen proved effective by actual tests in the area and in the same reservoir.

*Recompletion.*  The completion for production of an existingwellbore in another formation from that which the well has been previouslycompleted.

*Reservoir.*  A porous and permeable underground formationcontaining a natural accumulation of economically productive oil and/or gasthat is confined by impermeable rock or water barriers and is individual andseparate from other reserves.

*Standardized Measure.*  Standardized Measure, or standardized measureof discounted future net cash flows relating to proved oil and gas reservequantities, is the present value of estimated future net revenues to begenerated from the production of proved reserves, determined in accordance withthe rules and regulations of the Securities and Exchange Commission (using pricesand costs in effect as of the date of estimation) without giving effect tonon-property related expenses such as general and administrative expenses, debtservice and future income tax expenses or to depreciation, depletion andamortization and discounted using an annual discount rate of 10%.  Our Standardized Measure does not includefuture income tax expenses because our reserves are owned by our subsidiaryLinn Energy Holdings, LLC, which is not subject to income taxes.

*Successful well.*  A well capable of producing oil and/or gas incommercial quantities.

*Undeveloped acreage.*  Lease acreage on which wells have not beendrilled or completed to a point that would permit the production of commercialquantities of oil and gas regardless of whether such acreage contains provedreserves.

*Unproved reserves.*  Lease acreage on which wells have not beendrilled and where it is either probable or possible that the acreage containsreserves.

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

*Workover.*  Operations on a producing well to restore orincrease production.

 

iii

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**Part I**

**Item 1.  Business and Properties**

This Annual Report on Form 10-K containsforward-looking statements based on expectations, estimates and projections asof the date of this filing.  Thesestatements by their nature are subject to risks, uncertainties and assumptionsand are influenced by various factors. As a consequence, actual results may differ materially from thoseexpressed in the forward-looking statements. For more information see “Forward-Looking Statements” included at theend of this Item 1.  “Business andProperties” and see also Item 1A.  “RiskFactors.”

**References to Linn**

When referring to Linn Energy, LLC (“Linn” or the “Company”)and using phrases such as “we,” “our,” “us,” or the “Company,” our intent is torefer to Linn and its consolidated subsidiaries as a whole or on a divisionalbasis, depending on the context in which the statements are made.

**Overview**

Linn is an independent oil and gas company focused onthe development and acquisition of long-lived properties in the United Statesthat began operations in March 2003 and was formed as a Delaware limitedliability company in April 2005.  Linn isa holding company that conducts its operations through, and its operatingassets are owned by, its wholly-owned subsidiaries.  We completed our initial public offering (“IPO”)on January 13, 2006 and our units representing limited liability companyinterests (“units”) are listed on The NASDAQ Global Market under the symbol “LINE.”

Our strategy focuses on building core areas ofoperations in multiple regions within the United States with long-lived gas oroil reserves.  Our core areas include:

·                  Appalachian Basin, which includes West Virginia,Pennsylvania, New York and Virginia;

·                  Western, which includes the Brea Olinda Field inthe Los Angeles Basin of California;

·                  Mid-Continent, which includes the Sooner Trend ofnorth central Oklahoma; and

·                  Texas Panhandle, which includes the Texas portionof the Hugoton-Panhandle Field (acquired in February 2007).

During the year ended December 31, 2006, wecompleted five acquisitions of oil and gas properties and related gathering andpipeline assets with total proved reserves of 263.7 Bcfe, for an aggregatepurchase price of approximately $454.9 million, or an acquisition cost ofapproximately $1.72 per Mcfe.  Frominception in March 2003 through December 31, 2006, we completed 14 acquisitions of oil and gasproperties and related gathering and pipeline assets, with total provedreserves of approximately 441.5 Bcfe, for an aggregate purchase price of approximately$656.4 million, or, including the amounts allocated to unprovedleasehold, an acquisition cost ofapproximately $1.49 per Mcfe.  Aspart of our business strategy, we continually evaluate opportunities to acquireadditional oil and gas properties which complement our asset profile.  See “Acquisitions” below for details aboutour most recent acquisitions in Texas and West Virginia, which are not includedin our reserves at December 31, 2006.

Our proved reserves at December 31, 2006 were454.1 Bcfe, of which approximately 60.3% were gas and 39.7% were oil.  Approximately 69.2% were classified as proveddeveloped, with a total proved Standardized Measure value of $552.3million.  At December 31, 2006, weoperated 2,683, or 73.3%, of our 3,659 productive wells.  Our average proved reserves-to-productionratio, or average reserve life, is approximately 29.5 years, based on ourDecember 31, 2006 reserve report and annualized production for the fourthquarter ended December 31, 2006.

1

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**Item 1. Business and Properties - Continued**

**Acquisitions**

The following table provides a summary of the oil andgas properties we have acquired from inception through the date of this report:
| **Year**   | ** ** | **# of  Acquisitions** | ** ** | **Gross  Wells** | ** ** | **Location**                                       | ** ** | **Aggregate  Contract  Price** |
|------------|------------|-----------------------------|------------|------------------|------------|----------------------------------------------------|------------|--------------------------------|
| ** ** | ** ** | ** **                  | ** ** | ** **       | ** ** | ** **                                         | ** ** | **(in millions)**              |
|       |       |                        |       |             |       |                                               |       |                           |
| 2003       |       | 4                           |       | 498              |       | West Virginia, Virginia, New York and Pennsylvania |       | $                              | 52.0 |
| 2004       |       | 2                           |       | 698              |       | Pennsylvania                                       |       | 25.9                           |
| 2005       |       | 3                           |       | 718              |       | West Virginia and Virginia                         |       | 124.5                          |
| 2006       |       | 5                           |       | 1,430            |       | West Virginia, California and Oklahoma             |       | 451.7                          |
| 2007       |       | 3                           |       | 902              |       | West Virginia and Texas                            |       | 453.9                          |
|       |       | 17                          |       | 4,246            |       |                                               |       | $                              | 1,108.0 |

 

In February 2007, theCompany completed the acquisition of certain oil and gas properties and relatedassets in the Texas Panhandle from Cavallo Energy, LP, acting through itsgeneral partner, Stallion Energy LLC (“Stallion”) for a contract price of$415.0 million, subject to customary post-closing adjustments (see Note 2 inNotes to Consolidated Financial Statements for additional details).  In addition, in January 2007, the Company completedthe acquisitions of certain gas properties located in the Appalachian Basin ofWest Virginia for an aggregate contract price of $39.0 million, subject tocustomary post-closing adjustments. These acquisitions were financed with a combination of private placementof our units and borrowings under the Company’s credit facility.

Our acquisitions have been funded by a combination of debt and privateplacements of our units.  During2006, we completed a private placement of our units raising gross proceeds of$305.0 million and completed another private placement of our units with grossproceeds of $360.0 million in February 2007.

**Strategy**

Our goal is to provide stability and growth in distributions to ourunitholders through continued successful drilling, acquisitions, increasingproduction of existing wells and pursuing operational and administrativeefficiencies.  The following is a summaryof the key elements of our business strategy:

·                  acquire properties that increase cash availablefor distributions;

·                  build regional scale to maximize value andoperating cash flows;

·                  grow through low risk, low cost developmentdrilling and other enhancements;

·                  create post-acquisition value; and

·                  mitigate commodity price risk through hedging.

Certain key elements included in our business strategyare further explained below.

*AcquireProperties and Build Regional Scale.*  Our acquisition program targets oil and gasproperties that offer high-quality, long-lived production with predictabledecline curves, as well as development drilling opportunities.  From March 2003 through the first quarter of2007, including preliminary estimates for our first quarter 2007 acquisitions,we have purchased approximately 795.0 Bcfe of proved reserves, at a total costof approximately $1,109.7 million (includes preliminary purchase prices, whichare subject to customary post-closing adjustments).  Including the amounts allocated to unprovedleasehold, our acquisition cost was approximately $1.40 per Mcfe over this timeperiod.  Our acquisition program focusesboth on acquiring new core areas, where the assets meet our strategic profile,and increasing our ownership in existing fields or core areas.  Acquisitions will continue to play a key rolein our future growth strategy.

*GrowThrough Development Activities*.  We seek to be the operator of our propertiesto design and develop capital maintenance and development drilling programsthat not only replace our production, but add value through the growth ofreserves and future operational synergies. During the third quarter of 2006, we acquired two drilling rigs tobetter manage and control costs related to our drilling programs.  In addition to our own rigs, we havecontracts in place for third party

2

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**Item1.  Business and Properties - Continued**

drilling servicesthat, together with our own rigs, provide the resources required to completeour drilling and development program for 2007 and beyond.  Most of our wells, excluding those inOklahoma, are relatively shallow, ranging from 3,000 to 6,000 feet, and drillthrough multiple productive zones.  Ourwells in Oklahoma range from 8,000 to 12,000 feet.  Many of our wells are completed in multipleproducing zones with commingled production. New producing wells generally have a total projected economic life inexcess of 50 years.  Our recentacquisitions provide an ample inventory of lower-risk developmentopportunities, which we believe will create post-acquisition value from ourassets.

*HedgingProgram*.  We typicallyseek to hedge a significant portion of our anticipated future productionvolumes to reduce commodity price volatility risk.  Managing this volatility, which we believe islikely to continue in the years ahead, provides a longer-term stability of cashflows.  We currently have gas hedges inplace covering substantially all of our anticipated production for theremainder of 2007 and a significant portion of estimated production from 2008through 2011, at weighted average NYMEX prices per Btu of $7.80.  In addition, we have a majority of ouranticipated oil production hedged for the remainder of 2007 through 2011, atweighted average NYMEX prices per Bbl of $67.49.  During 2006, settled hedges resulted in gainsof approximately $25.5 million.

**Core Operating Areas**

*AppalachianBasin*.  Our AppalachianBasin proved reserves represented 199.0 Bcfe, or 43%, of our total provedreserves at December 31, 2006, of which 60% were proved developedreserves.  During 2006, the AppalachianBasin assets produced 8.0 Bcfe, or 74%, of the Company’s 2006 production.  During 2006, we invested approximately $43.1million to drill 155 wells in the Appalachian Basin.  In addition, in order to improve our drillingefficiency, we purchased two drilling rigs at a cost of approximately $2.2 millionper rig in the latter part of 2006, and an additional rig in the first quarterof 2007.  We also own certain pipelineswhich market and transport our gas as well as transport gas for thirdparties.  In January 2007, we acquiredadditional reserves that we believe have significant development potential andalso expanded our pipeline facilities. During 2007, we anticipate spending 30% to 50% of our total budget fordrilling, development and pipeline expansion activities in the AppalachianBasin.

*Mid-Continent. *Our Mid-Continent proved reserves of 74.0 Bcfe, acquired inthird quarter of 2006, represented 16% of our total proved reserves atDecember 31, 2006, of which 52% were proved developed reserves.  This area produced 1.0 Bcfe, or 9%, of the Company’s2006 production.  During 2006, we investedapproximately $3.9 million to drill four wells in the Mid-Continent.  During 2007, we anticipate spending 10% to15% of our total budget for development activities in the Mid-Continent region.

*Western. *Our Western operations,also acquired in third quarter of 2006, represented proved reserves of 32.0MMboe, or 41%, of our total proved reserves at December 31, 2006, of which87% were proved developed reserves. During 2006, the Western assets produced 312.0 MMboe, or 17%, of theCompany’s 2006 production.  During 2007,we anticipate spending approximately 3% of our total budget for capitalmaintenance activities in the Brea-Olinda Field.  In addition to oil and gas production, ourWestern operations also include the operation of a gas power generationfacility that processes gas produced from our wells as well as third partygas.  The power generated is used toreduce our operating costs and any excess power is sold.  Reserve estimates related to contracts ofthird party gas totaled 10.0 Bcfe at December 31, 2006, which are notincluded in our reserve disclosures or amounts provided above.

*TexasPanhandle*.  In February2007, we completed our acquisition of oil and gas properties in the TexasPanhandle with proved reserves of approximately 51.0 MMboe, or 10%, of theCompany’s total proved reserves on a pro forma basis as of December 31,2006.  Of these, approximately 44% wereproved developed reserves.  We arecontinuing with the current development plan which deploys two drillingrigs.  Currently we are developing our2007 plan for this area and anticipate spending 30% to 40% of our total budgetfor drilling and development activities in the Texas Panhandle area.

**Drilling Activity**

We intend to concentrate our drilling activity on lower risk,development properties.  The number,types, and location of wells we drill will vary depending on our capitalbudget, the cost of each well, anticipated production and the estimatedrecoverable reserves attributable to each well.

3

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**Item1.  Business and Properties - Continued**

The followingtable sets forth the wells we drilled during the periods indicated (“gross”refers to the total wells in which we had a working interest and “net” refersto gross wells multiplied by our working interest):

|                             | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------|------------|--------------------------------------------|------------|
| ** **                  | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Gross Wells:**            |       |                                       |       |   |   |   |   |
| Productive                  |       | 154                                        |       | 110 |   | 90 |   |
| Dry                         |       | 5                                          |       | — |   | — |   |
| Total                       |       | 159                                        |       | 110 |   | 90 |   |
| **Net Development Wells:**  |       |                                       |       |   |   |   |   |
| Productive                  |       | 147                                        |       | 105 |   | 82 |   |
| Dry                         |       | 5                                          |       | — |   | — |   |
| Total                       |       | 152                                        |       | 105 |   | 82 |   |
| **Net  Exploratory Wells:** |       |                                       |       |   |   |   |   |
| Productive                  |       | —                                     |       | — |   | — |   |
| Dry                         |       | —                                     |       | — |   | — |   |
| Total                       |       | —                                     |       | — |   | — |   |

 

The information should not be considered indicative of futureperformance, nor should it be assumed that there is necessarily any correlationbetween the number of productive wells drilled, quantities of reserves found oreconomic value.  Productive wells arethose that produce commercial quantities of oil and gas, regardless of whetherthey generate a reasonable rate of return.

Historically, mostof our drilling has been in the Appalachian Basin.  At December 31, 2006, we had 16 (13.7net) wells in process.  From inceptionthrough December 31, 2006, we spentapproximately $91.3 million to drill and complete 359 wells, substantially allof which are capable of producing oil and gas in commercial quantities.

The following table sets forth information, as ofDecember 31, 2006, relating to our drilling locations and net acres ofleasehold interests in our three core areas at that date:

|                                | ** ** | **Appalachian  Basin** | ** ** | **Western** | ** ** | **Mid-Continent** | ** ** | **Total** | ** ** |
|--------------------------------|------------|------------------------|------------|-------------|------------|-------------------|------------|-----------|------------|
| Proved undeveloped             |       | 581                    |       | 2           |       | 133               |       | 716       |       |
| Other locations                |       | 538                    |       | —      |       | —            |       | 538       |       |
| Total drilling  locations      |       | 1,119                  |       | 2           |       | 133               |       | 1,254     |       |
|                           |       |                   |       |        |       |              |       |      |       |
| Leasehold interests-net  acres |       | 174,000                |       | 810         |       | 53,896            |       | 228,706   |       |

 

Withour February 2007 acquisition of oil and gas properties in the Texas Panhandle,we added 1,265 drilling locations, 347 of which were identified as provedundeveloped locations and 918 of which were identified as unproved locations.

Asshown in the table above, as of December 31, 2006, we had 716 provedundeveloped drilling locations (specific drilling locations as to which ourindependent engineering firm, DeGolyer and MacNaughton, assigned provedundeveloped reserves as of such date) and we had identified 538 additionalunproved drilling locations (specific drilling locations as to which DeGolyerand MacNaughton has not assigned any proved reserves) on acreage that we haveunder existing leases.  As successfuldevelopment wells frequently result in the reclassification of adjacent leaseacreage from unproved to proved, we expect that a significant number of ourunproved drilling locations will be reclassified as proved drilling locationsprior to the actual drilling of these locations.

4

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**Item 1.  Business and Properties - Continued**

**Oil and Gas Prices**

Linn’s gasproduction is generally sold under market sensitive price contracts, whichtypically sell at differentials to the NYMEX gas prices due to the Btu contentand the proximity to major consuming markets. Our gas production is sold to purchasers under percentage-of-proceedscontracts, percentage-of-index contracts or spot price contracts.  By the terms of the percentage-of-proceedscontracts, we receive a percentage of the resale price received by thepurchaser for sales of residue gas and natural gas liquids recovered aftertransportation and processing of our gas. These purchasers sell the residue gas and natural gas liquids basedprimarily on spot market prices.  Underpercentage-of-index contracts, the price per MMBtu we receive for our gas istied to indexes published in *Gas Daily*or *InsideFERC Gas Market Report.* Although exact percentages vary daily, as of February 2007,approximately 80% of our gas production was sold under short-term contracts atmarket-sensitive or spot prices.  Similarly,oil production is generally sold under market sensitive long-termpercentage-of-index contracts.

We enter intoderivative transactions in the form of hedging arrangements to reduce theimpact of commodity price volatility on our cash flow from operations.  Currently, we use fixed price swaps and putsto hedge NYMEX oil and gas prices, which do not include the additional netpremium we typically realize in the Appalachian Basin for gas.  By removing the price volatility from asignificant portion of our oil and gas production, we have mitigated, but noteliminated, the potential effects of fluctuating oil and gas prices on our cashflow from operations for those periods.

**Oil andGas Data**

***Proved Reserves***

Proved oil and gas reserves are the estimated quantitiesof oil and gas which geological and engineering data demonstrate withreasonable certainty to be recoverable in future years from known reservoirsunder existing economic and operating conditions, i.e., prices and costs as ofthe date the estimate is made.  Pricesinclude consideration of changes in existing prices provided by contractualarrangements, but not escalations based on future conditions.  For additional information regardingestimates of oil and gas reserves, including estimates of proved and proveddeveloped reserves, the standardized measure of discounted future cash flowsand the changes in discounted future cash flows, see Supplementary Oil and GasData (Unaudited) in Item 8.  “FinancialStatements and Supplementary Data.”

The following table presents our estimated net proved oiland gas reserves and the present value of our estimated proved reserves atDecember 31, 2006, 2005 and 2004, based on reserve reports prepared byDeGolyer and MacNaughton at December 31, 2006 and reserve reports preparedby Schlumberger Data and Consulting Services at December 31, 2005 and2004.  The Standardized Measure valuesshown in the table are not intended to represent the market value of ourestimated oil and gas reserves at such dates.
| ** **                                                 | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2006**              | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Reserve  Data:****(1)**                                  |       |                  |       |   |   |   |   |
| Estimated net  proved reserves:                            |       |                  |       |   |   |   |   |
| Gas (Bcf)                                                  |       | 274.0                 |       | 191.9 |   | 118.9 |   |
| Oil (MMBbls)                                               |       | 30.0                  |       | 0.2 |   | 0.1 |   |
| Total (Bcfe)                                               |       | 454.1                 |       | 193.2 |   | 119.8 |   |
| Proved developed  (Bcfe)                                   |       | 314.1                 |       | 125.2 |   | 74.4 |   |
| Proved  undeveloped (Bcfe)                                 |       | 140.0                 |       | 68.0 |   | 45.4 |   |
| Proved developed  reserves as a % of total proved reserves |       | 69.2                  | %          | 64.8 | % | 62.1 | % |
| **Standardized  Measure (in millions)****(2)**             |       | $                     | 552.3      |   | $ | 552.1 |   | $ | 215.0 |   |
| **Representative  Oil and Gas Prices:**                    |       |                  |       |   |   |   |   |
| Gas — NYMEX Henry Hub per MMBtu                       |       | $                     | 5.64       |   | $ | 10.08 |   | $ | 6.18 |   |
| Oil — NYMEX West  Texas Intermediate per Bbl          |       | $                     | 61.05      |   | $ | 57.98 |   | $ | 43.36 |   |

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(1)             Excludes the Texas Panhandle reserves of 51.0MMboe and reserves for the two Appalachian Basin acquisitions discussed above.

(2)             Does not give effect to derivative transactions.  For a description of our derivativetransactions, see Part II.  Item 7.  “Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Statements of Cash Flows -Operating Activities” in this Annual Report on Form 10-K.

5

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**Item 1. Business and Properties - Continued**

The data in the above table are estimates.  Oil and gas reserve engineering is inherentlya subjective process of estimating underground accumulations of oil and gasthat cannot be measured exactly.  Theaccuracy of any reserve estimate is a function of the quality of available dataand engineering and geological interpretation and judgment.  Accordingly, reserve estimates may vary fromthe quantities of oil and gas that are ultimately recovered.

These reserve estimates are reviewed and approved by oursenior engineering staff and management, with final approval by our ChiefOperating Officer.  The process performedby DeGolyer and MacNaughton to estimate the December 31, 2006 reserveamounts and by Schlumberger Data and Consulting Services to estimate theDecember 31, 2005 and 2004 reserve amounts included their preparation ofour estimated reserve quantities, future producing rates, future net revenueand the present value of such future net revenue.  The independent engineering firms alsoprepared our estimates with respect to reserve categorization, using thedefinitions for proved reserves set forth in Regulation S-X Rule 4-10 (a) andsubsequent Securities and Exchange Commission (“SEC”) staff interpretations andguidance.  In the conduct of theirpreparation of the reserve estimates, neither DeGolyer and MacNaughton norSchlumberger Data and Consulting Services independently verified the accuracyand completeness of information and data furnished by the Company with respectto ownership interests, oil and gas production, well test data, historicalcosts of operation and development, product prices, or any agreements relatingto current and future operations of the properties and sales of production.  However, if in the course of their work,something came to their attention which brought into question the validity orsufficiency of any such information or data, they did not rely on suchinformation or data until they had satisfactorily resolved their questionsrelating thereto.  Their estimates ofreserves conform to the guidelines of the SEC, including the criteria of “reasonablecertainty,” as it pertains to expectations about the recoverability of reservesin future years, under existing economic and operating conditions.  We have not filed reserve estimates with anyFederal authority or agency, with the exception of the SEC, since the lastfiscal year ended.

Future prices received for production may vary, perhapssignificantly, from the prices assumed for purposes of our estimate ofStandardized Measure.  The StandardizedMeasure shown should not be construed as the market value of the reserves atthe dates shown.  The 10% discount factorused to calculate Standardized Measure, which is required by Statements ofFinancial Accounting Standards (“SFAS”) No. 69, *“Disclosuresabout Oil and Gas Producing Activities,”* is not necessarily the mostappropriate discount rate.  TheStandardized Measure, no matter what discount rate is used, is materiallyaffected by assumptions as to timing of future production, which may prove tobe inaccurate.

***Production and Price History***

Thefollowing table sets forth information regarding net production of oil and gasand certain price information for each of the periods indicated:
| ** **                                    | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                    | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Production:**                               |       |                                       |       |   |   |   |   |
| Gas production (MMcf)                         |       | 8,599                                      |       | 4,720 |   | 3110 |   |
| Oil production (MBbls)                        |       | 370                                        |       | 20 |   | 10 |   |
| Total production  (MMcfe)                     |       | 10,818                                     |       | 4,839 |   | 3,112 |   |
| Average daily  production (Mcfe/d)            |       | 29,638                                     |       | 13,258 |   | 8,526 |   |
| ** **                                    |       |                                       |       |   |   |   |   |
| **Weighted  Average Realized Prices:****(1)** |       |                                       |       |   |   |   |   |
| Gas (Mcf)                                     |       | $                                          | 9.79       |   | $ | 6.92 |   | $ | 5.73 |   |
| Oil (Bbl) (2)                                 |       | $                                          | 58.68      |   | $ | 52.55 |   | $ | 37.83 |   |
| Total (Mcfe)                                  |       | $                                          | 9.79       |   | $ | 6.97 |   | $ | 5.74 |   |

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(1)             Includes the effect of realized gains and losseson oil and gas derivatives.

(2)             The majority of our oil production, which is inCalifornia, is sold pursuant to a long-term contract at 79% of NYMEX, and withgravity increase due to NGLs being mixed into the oil stream, prices realizedaverage approximately 82% of NYMEX.

6

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**Item1.  Business and Properties - Continued**

***Productive Wells***

The following table sets forth information relating to the productivewells in which we owned a working interest as of December 31, 2006.  Productive wells consist of producing wellsand wells capable of production, including gas wells awaiting pipelineconnections to commence deliveries.  “Gross”wells refers to the total number of producing wells in which we have aninterest, and “net” wells refers to the sum of our fractional working interestsowned in gross wells.

 
| ** **       | ** ** | **Gas Wells** | ** ** | **Oil Wells** | ** ** | **Total Wells** | ** ** |
|------------------|------------|--------------------|------------|--------------------|------------|----------------------|------------|
| ** **       | ** ** | **Gross**          | ** ** | **Net**            | ** ** | **Gross**            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Operated (1)     |       | 2,301              |       | 1,425              |       | 380                  |       | 360 |   | 2,681 |   | 1,785 |   |
| Non-operated (2) |       | 819                |       | 518                |       | 159                  |       | 71 |   | 978 |   | 589 |   |
| Total            |       | 3,120              |       | 1,943              |       | 539                  |       | 431 |   | 3,659 |   | 2,374 |   |

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(1)             Three operated wells had multiple completions atDecember 31, 2006.

(2)             One non-operated well had multiple completions atDecember 31, 2006.

***Developed and Undeveloped Acreage***

Thefollowing table sets forth information as of December 31, 2006, relatingto our leasehold acreage:
| ** **   | ** ** | **Developed  Acreage** | ** ** | **Undeveloped  Acreage** | ** ** | **Total  Acreage** | ** ** |
|--------------|------------|------------------------|------------|--------------------------|------------|--------------------|------------|
| ** **   | ** ** | **Gross**              | ** ** | **Net**                  | ** ** | **Gross**          | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Operated     |       | 213,086                |       | 143,203                  |       | 65,429             |       | 56,279 |   | 278,515 |   | 199,482 |   |
| Non-operated |       | 133,300                |       | 29,224                   |       | —             |       | — |   | 133,300 |   | 29,224 |   |
| Total        |       | 346,386                |       | 172,427                  |       | 65,429             |       | 56,279 |   | 411,815 |   | 228,706 |   |

 

**Oil and Gas Operational Overview**

***General***

We seek to be the operator ofwells in which we have an interest.  Asoperator, we design and manage the drilling and enhancement activities andsupervise operation and maintenance activities on a day-to-day basis.  We purchased two drilling rigs during 2006,an additional rig in the first quarter of 2007, and currently have contracts in place for additional third-partydrilling rigs needed to carry out our 2007 drilling program.  In the third quarter of 2006, the Companybegan, for the first time, operating its own drilling rigs, staffed withCompany personnel.  Company personnelalso perform drilling activities using leased equipment, and did so prior tothe purchase of its own rigs.  Inaddition, we employ drilling, production and reservoir engineers, geologistsand other specialists who work to improve production rates, increase reservesand lower the cost of operating our oil and gas properties.

***Principal Customers***

For the year ended December 31, 2006, sales of oiland gas to Dominion Resources, Inc. and ConocoPhillips accounted forapproximately 53% and 14%, respectively, of our total volumes, or 67% in theaggregate.  If we were to lose any one ofour major oil and gas purchasers, the loss could temporarily cease or delayproduction and sale of our oil and gas in that particular purchaser’s servicearea.  If we were to lose a purchaser, webelieve we could identify a substitute purchaser.  However, if one or more of these large gas purchasersceased purchasing oil and gas altogether, it could have a detrimental effect onthe oil and gas market in general and on the volume of oil and gas that we areable to sell.

***Competition***

The oil and gas industry ishighly competitive.  We encounter strongcompetition from other independent operators and from major oil companies inacquiring properties, contracting for drilling equipment and securing trainedpersonnel.  Many of these competitorshave financial and technical resources and staffs substantially larger thanours.  As a result, our competitors maybe able to pay more for desirable leases, or to evaluate, bid for and purchasea greater number of properties or prospects, than our financial or human resourcespermit.

7

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**Item 1.  Business and Properties - Continued**

We are also affected by competition for drilling rigs and theavailability of related equipment.  Inthe past, the oil and gas industry has experienced shortages of drilling rigs,equipment, pipe and personnel, which has delayed development drilling and hascaused significant price increases.  Weare unable to predict when, or if, such shortages may occur or how they wouldaffect our drilling program.

Competition is also strong for attractive oil and gas producingproperties, undeveloped leases and drilling rights, and we cannot guaranteethat we will be able to compete satisfactorily when attempting to make furtheracquisitions.

***Title to Properties***

As it is customary in the oil and gas industry, we initially conductonly a cursory review of the title to our properties on which we do not haveproved reserves.  Prior to thecommencement of drilling operations on those properties, we conduct a thoroughtitle examination and perform curative work with respect to significantdefects.  To the extent title opinions orother investigations reflect title defects on those properties; we aretypically responsible for curing any title defects at our expense prior tocommencing drilling operations.  Prior tocompleting an acquisition of producing gas leases, we perform title reviews onthe most significant leases and, depending on the materiality of properties, wemay obtain a title opinion or review previously obtained title opinions.  As a result, we have obtained title opinionson a significant portion of our oil and gas properties and believe that we havesatisfactory title to our producing properties in accordance with standardsgenerally accepted in the oil and gas industry. Our oil and gas properties are subject to customary royalty and otherinterests, liens for current taxes and other burdens which we believe do notmaterially interfere with the use of or affect our carrying value of theproperties.

***Seasonal Nature of Business***

Seasonal weather conditions and lease stipulations can limit ourdrilling and producing activities and other operations in certain areas of theUnited States that we operate in (primarily in parts of the Appalachian Basinand Oklahoma) and, as a result, we perform the majority of our drilling duringthe summer months in these areas.  Theseseasonal anomalies can pose challenges for meeting our well drilling objectivesand increase competition for equipment, supplies and personnel during thespring and summer months, which could lead to shortages and increase costs ordelay our operations.  The demand for gastypically decreases during the summer months and increases during the wintermonths.  Seasonal anomalies such as mild wintersor hot summers sometimes lessen this fluctuation.  In addition, certain gas users utilize gasstorage facilities and purchase some of their anticipated winter requirementsduring the summer.  This can also lessenseasonal demand fluctuations.

***Derivative Activity***

We enter into derivative transactions with third parties with respect tooil and gas prices and interest rates to achieve more predictable cash flowsand to reduce our exposure to short-term fluctuations in gas prices andinterest rates.  For a more detaileddiscussion of our derivative activities, see Part II.  Item 7. “Management’s  Discussion andAnalysis of Financial Condition and Results of Operation” and Item 7A.  “Quantitative and Qualitative Disclosuresabout Market Risk.”

**Appalachia Gas GatheringActivities**

***Gathering for Ourselves***

Inorder to more efficiently transport our gas to market, we own and operate anetwork of gas gathering systems comprised of over 900 miles of pipeline andassociated compression and metering facilities which connect to numerous salesoutlets on eight interstate and eight intrastate pipelines.  The interstate market outlets are DominionTransmission Inc. (West Virginia and Pennsylvania), Columbia Gas TransmissionCorp. (West Virginia and Pennsylvania), Cranberry Pipeline (West Virginia),Texas Eastern Pipeline (Pennsylvania), Transco Pipeline (Pennsylvania),Equitrans (West Virginia and Pennsylvania), Equitable Gas Company (WestVirginia and Pennsylvania), and Carnegie Gas Company (West Virginia).  Theintrastate market outlets are Dominion Peoples (Pennsylvania), Dominion Hope (WestVirginia), 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 FuelGas Distribution (New York) and Lumberport Shinnston Gas Company (WestVirginia).

We gather more than 90% of our current production.  Our ownership and control of these linesenables us to:

·                  realize faster connection of newly drilled wellsto the existing system;

·                  better control pipeline operating pressures andcapacity to maximize our production;

8

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**Item 1.  Business and Properties - Continued**

·                  control compression costs and fuel use;

·                  maintain system integrity;

·                  control the monthly nominations on the receivingpipelines to prevent imbalances and penalties; and

·                  closely track sales volumes and receipts to ensureall production values are realized.

***Gathering forOthers***

Weperform limited gas gathering activities for others on non-jurisdictionalgathering, primarily in Pennsylvania.  The fee charged to third partyproducers is set by contract and ranges from $0.10 to $0.44 per Mcf plus lineloss and any compressor fuel.  We aggregate these volumes with ourproduction and sell all the gas through our meters to the same purchasers.  These revenues are collected and distributedto the third party producers in the normal course of our revenue distributioncycle. Most of our gas gathering lines are not subject to United StatesDepartment of Transportation (“US DOT”) safety regulations.

***Purchase for Resale***

We own the Bessie8 Pipeline in Pennsylvania and purchase and re-sell production from otherproducers connected to it.  We intend toreconfigure other gas gathering systems to bring additional volumes online,both Company and third party owned, to the Bessie 8 Pipeline to increasethroughput volumes and revenues.

**OtherRecent Developments**

In October 2006, theCompany completed a Class B Unit and Unit Purchase Agreement with a group ofinstitutional investors whereby it privately placed 9,185,965 Class B units ata price of $20.55 per unit, and 5,534,687 units at a price of $21.00 per unit,for aggregate gross proceeds of $305.0 million (the “Class B Private Placement”).  Proceeds, net of expenses of approximately$0.3 million, from the Class B Private Placement were used to repayindebtedness.  In January 2007, at aspecial meeting of Linn unitholders, unitholders approved the one-for-oneconversion of each of the Class B units into units.

In February 2007, theCompany completed a Class C Unit and Unit Purchase Agreement with a group ofinstitutional investors whereby it privately placed 7,465,946 Class C units ata price of $25.06 per unit and 6,650,144 units at a price of $26.00 per unit,for aggregate gross proceeds of $360.0 million, (the “Class C Private Placement”)which were used to finance the Stallion acquisition and the acquisitions of gasproperties in West Virginia.  See Note 4in Notes to Consolidated Financial Statements for additional details about ourprivate placements of our units.

**Environmental Matters andRegulation**

We believe that ourproperties and operations are in compliance with applicable environmental lawsand regulations, and our operations to date have not resulted in any materialenvironmental liabilities.  To protect againstpotential environmental risk, we typically obtain Phase I environmentalassessments of any properties to be acquired prior to completing eachacquisition.

*General.*  Our operations are subject to stringentfederal, state and local laws and regulations governing the discharge ofmaterials into the environment or otherwise relating to environmentalprotection.  Our operations are subjectto the same environmental laws and regulations as other companies in the oiland gas industry.  These laws andregulations may:

·                  require the acquisition of various permits beforedrilling commences;

·                  require the installation of expensive pollutioncontrol equipment;

·                  restrict the types, quantities and concentrationof various substances that can be released into the environment in connectionwith drilling and production activities;

·                  limit or prohibit drilling activities on landslying within wilderness, wetlands and other protected areas;

·                  require remedial measures to prevent pollutionfrom former operations, such as pit closure and plugging of abandoned wells;

·                  impose substantial liabilities for pollutionresulting from our operations; and

·                  with respect to operations affecting federal landsor leases, require preparation of a Resource Management Plan, an EnvironmentalAssessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of oil andgas production below the rate that would otherwise be possible.  The regulatory burden on the oil and gasindustry increases the cost of doing business and consequently affectsprofitability.  Additionally, Congressand federal and state agencies frequently revise environmental laws andregulations, and 

9

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**Item 1.  Business and Properties - Continued**

any changes that result in more stringent and costly waste handling,disposal and clean-up requirements for the oil and gas industry could have asignificant impact on our operating costs. We believe that we substantially comply with all current applicable environmentallaws and regulations and that our continued compliance with existingrequirements will not have a material adverse impact on our financial conditionand results of operations.  However, wecannot predict how future environmental laws and regulations may impact ourproperties or operations.  For the yearended December 31, 2006, we did not incur any material capitalexpenditures for installation of remediation or pollution control equipment atany of our facilities.  We are not awareof any environmental issues or claims that will require material capitalexpenditures during 2007 or that will otherwise have a material impact on ourfinancial position or results of operations.

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

*National Environmental Policy Act.*  Oil andgas production activities on federal lands are subject to the NationalEnvironmental Policy Act (“NEPA”).  NEPArequires federal agencies, including the Department of Interior, to evaluatemajor agency actions having the potential to significantly impact theenvironment.  In the course of suchevaluations, an agency will typically prepare an Environmental Assessment toassess the potential direct, indirect and cumulative impacts of a proposedproject and, if necessary, will prepare a more detailed Environmental ImpactStatement that may be made available for public review and comment.  All of our current development and productionactivities, as well as proposed development plans, on federal lands requiregovernmental permits that are subject to the requirements of NEPA.  This process has the potential to delay thedevelopment of oil and gas projects.

*Resource Conservation and Recovery Act.*  TheResource Conservation and Recovery Act (“RCRA”), and comparable state statutes,regulate the generation, transportation, treatment, storage, disposal andcleanup of “hazardous wastes” and the disposal of non-hazardous wastes.  Under the auspices of the EnvironmentalProtection Agency (“EPA”), individual states administer some or all of theprovisions of RCRA, sometimes in conjunction with their own, more stringentrequirements.  Drilling fluids, producedwaters and most of the other wastes associated with the development andproduction of oil, gas or geothermal energy constitute “solid wastes,” whichare regulated under the less stringent non-hazardous waste provisions, butthere is no guarantee that the EPA or individual states will not adopt morestringent requirements for the handling of non-hazardous wastes or recategorizesome non-hazardous wastes as hazardous for future regulation.

We believe that we are currently in substantial compliance with therequirements of RCRA and related state and local laws and regulations, and thatwe hold all necessary and up-to-date permits, registrations and otherauthorizations to the extent that our operations require them under such lawsand regulations.  Although we do notbelieve the current costs of managing our wastes as they are presently classifiedto be significant, any legislative or regulatory reclassification of oil andgas development and production wastes could increase our costs to manage anddispose of such wastes.

*Comprehensive Environmental Response, Compensation andLiability 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 ofconduct, on persons who are considered to be responsible for the release of a “hazardoussubstance” into the environment.  Thesepersons include the owner or operator of the site where the release occurredand companies that disposed or arranged for the disposal of the hazardoussubstance at the site.  Under CERCLA,such persons may be liable for the costs of cleaning up the hazardoussubstances that have been released into the environment, for damages to naturalresources and for the costs of certain health studies.  In addition, it is not uncommon forneighboring landowners and other third parties to file claims for personalinjury and property damage allegedly caused by the hazardous substancesreleased into the environment.

We currently own, lease, or operate numerous properties that have beenused for oil and gas development and production for many years.  Although we believe we have utilizedoperating and waste disposal practices that were standard in the industry atthe time, hazardous substances, wastes or hydrocarbons may have been releasedon or under the properties owned or leased by us, or on or under otherlocations, including off-site locations, where such substances have been takenfor disposal.  In addition, some of theseproperties have been operated by third parties or by previous owners oroperators whose treatment and disposal of hazardous substances, wastes orhydrocarbons was not under our control. These properties and the substances disposed or released on them may besubject to CERCLA, RCRA and analogous state laws.  Under such laws, we could be required toremove previously disposed substances and wastes, remediate contaminatedproperty or perform remedial plugging or pit closure operations to preventfuture contamination.

*Federal Water Pollution Control Act.*  TheFederal Water Pollution Control Act, also known as the Clean Water Act, andanalogous state laws impose restrictions and strict controls on the dischargeof pollutants, including produced waters and other oil and gas wastes, intowaters of the United States.  Thedischarge of pollutants into regulated waters is prohibited, except inaccordance with the terms of a permit issued by EPA or the relevant state.  The Clean Water Act also prohibits thedischarge of 

10

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**Item 1.  Business and Properties - Continued**

dredge and fill material in regulated waters, including wetlands, unlessauthorized by a permit issued by the U.S. Army Corps of Engineers.  Federal and state regulatory agencies canimpose administrative, civil and criminal penalties for non-compliance withdischarge permits or other requirements of the federal Clean Water Act andanalogous state laws and regulations.  Webelieve we are in substantial compliance with the requirements of the CleanWater Act.

*Clean Air Act.*  The CleanAir Act, and associated state laws and regulations, regulate emissions ofvarious air pollutants through the issuance of permits and the imposition ofother requirements.  In addition, the EPAhas developed, and continues to develop, stringent regulations governingemissions of toxic air pollutants at specified sources.  Some of our new facilities may be required toobtain permits before work can begin, and existing facilities may be requiredto incur capital costs in order to comply with new emission limitations.  These regulations may increase the costs ofcompliance for some facilities, and federal and state regulatory agencies canimpose administrative, civil and criminal penalties for non-compliance.  We believe that we are in substantialcompliance with the requirements of the Clean Air Act.

*Other Laws and Regulation.*  The KyotoProtocol to the United Nations Framework Convention on Climate Change (the “Protocol”)became effective in February 2005.  Underthe Protocol, participating nations are required to implement programs toreduce emissions of certain gases, typically referred to as greenhouse gasesthat are suspected of contributing to global warming.  The United States is not currently aparticipant in the Protocol, and Congress has resisted recent proposedlegislation directed at reducing greenhouse gas emissions.  However, there has been support in variousregions of the country for legislation that requires reductions in greenhousegas emissions, and some states have already adopted legislation addressinggreenhouse gas emissions from various sources, primarily power plants.  The oil and gas industry is a direct sourceof certain greenhouse gas emissions, namely carbon dioxide and methane, andfuture restrictions on such emissions could impact our future operations.  Our operations are not adversely impacted bycurrent state and local climate change initiatives and, at this time, it is notpossible to accurately estimate how potential future laws or regulationsaddressing greenhouse gas emissions would impact our business.

**Other Regulation of the Oiland Gas Industry**

The oil and gas industry is extensively regulated by numerous federal,state and local authorities.  Legislationaffecting the oil and gas industry is under constant review for amendment orexpansion, which frequently increases the regulatory burden.  Also, numerous departments and agencies, bothfederal and state, are authorized by statute to issue rules and regulationsbinding on the oil and gas industry and its individual members, some of whichcarry substantial penalties for failure to comply.  Although the regulatory burden on the oil andgas industry increases our cost of doing business and, consequently, affectsour profitability, these burdens do not affect us any differently or to anygreater or lesser extent than they affect other companies in the industry withsimilar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development ofregulations continues in the Department of Homeland Security and other agenciesconcerning the security of industrial facilities, including oil and gasfacilities.  Our operations may besubject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we wouldincur to comply with any such facility security laws or regulations, but suchexpenditures could be substantial.

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

·                  the location of wells;

·                  the method of drilling and casing wells;

·                  the surface use and restoration of properties uponwhich wells are drilled;

·                  the plugging and abandoning of wells; and

·                  notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing of unitsor proportion of units governing the pooling of oil and gas properties.  Some states allow forced pooling orintegration of tracts to facilitate development while other states rely onvoluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented bythird parties and may reduce our interest in the unitized properties.  In addition, state conservation lawsestablish maximum rates of production from oil and gas wells, prohibit theventing or flaring of gas and impose requirements regarding the ratability ofproduction.  These laws and regulationsmay limit the amount of oil and gas we can produce from our wells or limit thenumber of wells or the locations at which we can drill.  Moreover, each state typically imposes aproduction or severance tax with respect to the production and sale of oil, gasand natural gas liquids within its jurisdiction.

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**Item 1.  Business and Properties - Continued**

*Oil and Gas Transportation and Pricing.*  Theavailability, terms and cost of transportation significantly affect sales ofoil and gas.  The interstate transportationand sale of oil and gas are subject to federal regulation, primarily by theFederal Energy Regulatory Commission, including regulation of the terms,conditions and rates for interstate transportation, storage and various othermatters.  Federal and state regulationsgovern the price and terms for access to oil and gas pipelinetransportation.  The Federal EnergyRegulatory Commission’s regulations for interstate oil and gas transmission insome circumstances may also affect the intrastate transportation of oil andgas.

Although oil and gas prices are currently unregulated, Congresshistorically has been active in the area of oil and gas regulation.  We cannot predict whether new legislation toregulate oil and gas might be proposed, what proposals, if any, might actuallybe enacted by Congress or the various state legislatures, and what effect, ifany, the proposals might have on the operations of the underlyingproperties.  Sales of condensate and oiland gas liquids are not currently regulated and occur at market prices.

*State Regulation.*  Thevarious states regulate the drilling for, and the production, gathering andsale of, oil and gas, including imposing severance taxes and requirements forobtaining drilling permits.  States alsoregulate the method of developing new fields, the spacing and operation ofwells and the prevention of waste of oil and gas resources.  States may regulate rates of production andmay establish maximum daily production allowables from gas wells based onmarket demand or resource conservation, or both.  States do not regulate wellhead prices orengage in other similar direct economic regulation, but there can be noassurance that they will not do so in the future.  The effect of these regulations may be tolimit the amounts of oil and gas that may be produced from our wells and tolimit the number of wells or locations we can drill.  The oil and gas industry is also subject tocompliance with various other federal, state and local regulations andlaws.  Some of those laws relate tooccupational safety, resource conservation and equal opportunityemployment.  We do not believe thatcompliance with these laws will have a material adverse effect on our financialposition or results of operations.

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**Item 1.  Business and Properties - Continued**

**Executive Officers of the Company**

Our executive officers as of February 28, 2007, were as follows:
| **Name**                           | ** ** | **Age** | ** ** | **Position with Our Company**                             |
|------------------------------------|------------|---------|------------|-----------------------------------------------------------|
| Michael C. Linn                    |       | 55      |       | Chairman, President and Chief Executive Officer           |
| Kolja Rockov                       |       | 36      |       | Executive Vice President and Chief Financial Officer      |
| Mark E. Ellis                      |       | 50      |       | Executive Vice President and Chief Operating Officer      |
| Lisa D. Anderson                   |       | 45      |       | Senior Vice President and Chief Accounting Officer        |
| Roland “Chip” P.  Keddie |       | 54      |       | Senior Vice President — Administration and Secretary |
| Thomas A. Lopus                    |       | 48      |       | Senior Vice President — Eastern Operations           |
| Arden L. Walker,  Jr.              |       | 47      |       | Senior Vice President — Western Operations           |
| David J. Grecco                    |       | 40      |       | Vice President and General Counsel                        |

 

*MichaelC. Linn* is the Chairman, President and Chief ExecutiveOfficer of our Company and has served in such capacity since June 2006.  Prior to that, from March 2003, he was thePresident, Chief Executive Officer and Director.  From 2000 to 2003 Mr. Linn was President ofAllegheny Interests, Inc., a private gas and oil investment company.  From 1980 to 1999, Mr. Linn served as GeneralCounsel (1980-1982), Vice President (1982-1987), President (1987-1990) and CEO(1990-1999) of Meridian Exploration, a private Appalachian Basin gas and oilcompany which was sold to Columbia Natural Gas Company in 1999.  Both Allegheny Interests and MeridianExploration were wholly-owned by Mr. Linn and his family.  Mr. Linn is a member of the IndependentPetroleum Association of America (“IPAA”), the largest national tradeassociation of independent gas and oil producers.  The members of the IPAA elected Mr. Linn tobe the Chairman for the 2005 to 2007 term. He currently serves as a member of the Natural Gas Council and theNational Petroleum Council and sits on the board of the Natural Gas SupplyAssociation.

*KoljaRockov* is the Executive Vice President and Chief FinancialOfficer of our Company.  From October2004 until he joined Linn in March 2005, Mr. Rockov served as a ManagingDirector in the Energy Group at RBC Capital Markets, where he was primarilyresponsible for investment banking coverage of the U.S. exploration andproduction sector.  From September 2000until October 2004, Mr. Rockov was a Director at RBC Capital Markets.  Prior to September 2000, Mr. Rockov heldvarious senior positions with Dain Rauscher Wessels and Rauscher PierceRefsnes, Inc., predecessors of RBC Capital Markets.

*Mark E.Ellis*is the Executive Vice President and Chief OperatingOfficer of our Company and joined Linn in December 2006.  From April 2006, until he joined Linn, Mr.Ellis served as President of the Lower 48 for ConocoPhillips Company.  Prior to joining ConocoPhillips, from October2004, Mr. Ellis served as Senior Vice President of North American Productionfor Burlington Resources.  Prior to that,from November 2000, Mr. Ellis was President of Burlington Resources CanadaLtd.  Mr. Ellis joined BurlingtonResources in 1985 and began his career with The Superior Oil Company in1979.  Mr. Ellis is a member of theSociety of Petroleum Engineers and a past board member of the New Mexico Oil& Gas Association.  While in Calgary,he was a member of the Board of Governors of the Canadian Association ofPetroleum Producers.  Mr. Ellis currentlyserves on the Board of The Center for Hearing and Speech in Houston, IndustryBoard of Petroleum Engineering at Texas A&M University and the VisitingCommittee of Petroleum Engineering at the Colorado School of Mines.

*Lisa D.Anderson*is the Senior Vice President and Chief AccountingOfficer of our Company.  Ms. Anderson oversees the Company’saccounting, financial reporting and internal control functions.  Before joining Linn in July 2006, she was theManaging Director leading the Financial Reporting Risk Services practice forProtiviti.  From January 2002 to August2005, she served as a Managing Director with Jefferson Wells, and prior to2002, she was an Assurance Partner with KPMG LLP.  Ms. Anderson is a member of the AmericanInstitute of Certified Public Accountants, Texas Society of CPAs and theInstitute of Internal Auditors.  Inaddition, she has served on the Presidential Advisory and the EducationalCurriculum Committees of the Texas Society of Certified Public Accountants.

*Roland “Chip”P. Keddie* is the Senior Vice President — Administration andSecretary of our Company and has served in such capacity since April 2003.  From January 2001 until April 2003, Mr.Keddie held the position of Project Landman with EOG Resources, Inc. and wasresponsible for various land services in the Appalachian Basin with a specialemphasis on coal bed methane projects. Mr. Keddie formed Gateway Resources Management, LLC, a professional landservices business, in October 1999 and was its sole member and President untilJanuary 2001.  He currently serves as aboard member of the 

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**Item 1.  Business and Properties - Continued**

Independent Oil and GasAssociation of Pennsylvania and is a member of the American Association ofPetroleum Landmen, the Independent Oil and Gas Association of New York, theIndependent Oil and Gas Association of West Virginia and the IndependentPetroleum Association of America.

*ThomasA. Lopus* is the Senior Vice President — Eastern Operations.  Mr.Lopus joined Linn in April 2006, as Senior Vice President — Operations, tooversee the Company’s drilling and production, engineering, land and geologyoperations.  In February 2007, Mr. Lopuswas appointed to his current position with responsibility for managing ourexisting assets in the Appalachian basin and any future assets we might acquireeast of the Mississippi River.  FromMarch 2005 to March 2006, Mr. Lopus served as President of PNG Inc., apetroleum engineering consulting business. From February 2002 until March 2005, Mr. Lopus was Senior Vice President— Operations of Equitable Resources, Inc. From February 2000 until February 2002, Mr. Lopus was Vice President ofWELLOGIX, an energy software firm based in Houston.

*ArdenL. Walker, Jr.*isthe Senior Vice President — Western Operations. Mr. Walker joined Linn in February 2007 to oversee our Westernoperations, which includes our California, Oklahoma and Texasassets.  In addition, Mr. Walker willserve in the capacity of chief engineer for Linn, responsible for our futurereserve review and booking processes.  From April 2006 until he joined Linn,Mr. Walker served as Asset Development Manager, San Juan Business Unit forConocoPhillips Company.  Since June 2004,Mr. Walker served as General Manager, Asset Development in San Juan Divisionfor Burlington Resources.  Mr. Walkerbegan his career with El Paso Exploration Company in 1982.  Mr. Walker is a member of the Society ofPetroleum Engineers and has served on the Board for Farmington Boys and GirlsClub since 2004.

*DavidJ. Grecco* is the Vice President and General Counsel of ourCompany and has served in such capacity since February 2006.  Mr. Grecco joined our Company as GeneralCounsel in December 2005.  From September1997 until October 2005, Mr. Grecco was employed as an attorney with the lawfirm Kirkpatrick & Lockhart Nicholson Graham LLP.  Prior to that, Mr. Grecco was employed byRockwell International Corporation from March 1993 through June 1996.

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**Item 1.  Business and Properties - Continued**

**Employees**

As of February 28, 2007, we employed approximately 220 personnel.  We also contract for the services ofindependent consultants involved in land, regulatory, accounting, financial andother disciplines as needed.  None of ouremployees are represented by labor unions or covered by any collectivebargaining agreement.  We believe thatour relationship with our employees is satisfactory.

**Principal Executive Offices**

We are a Delaware limited liability company with headquarters inTexas.  Our principal executive officesare located at 600 Travis Street, Suite 7000, Houston, Texas 77002.  Our main telephone number is (281) 605-4100.

**Company Website**

Our internet address is http://www.linnenergy.com.  We make available free of charge on orthrough our website our Annual Reports on Form 10-K, Quarterly Reports on Form10-Q, Current Reports on Form 8-K, and any amendments to those reports filed orfurnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of1934 as soon as reasonably practicable after we electronically file suchmaterial with, or furnish it to, the SEC. Information on our website should not be considered a part of, orincorporated by reference into, this Annual Report on Form 10-K.

The SEC maintains aninternet website that contains these reports at http://www.sec.gov.  Any materials that we file with the SEC maybe read or copied at the SEC’s Public Reference Room at 100 F Street, NE,Washington, DC 20549.  Informationconcerning the operation of the Public Reference Room may be obtained bycalling the SEC at (800) 732-0330.

**Forward-Looking Statements**

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

·                  business strategy;

·                  acquisition strategy;

·                  financial strategy;

·                  drilling locations;

·                  oil and gas reserves;

·                  realized oil and gas prices;

·                  production volumes;

·                  lease operating expenses, general andadministrative expenses and finding and development costs;

·                  future operating results; and

·                  plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historicalfact included in this Annual Report on Form 10-K, are forward-lookingstatements.  These forward-lookingstatements may be found in Part I.  Item1.  “Business and Properties;”Part I.  Item 1A.  “Risk Factors;” Part II.  Item 7. “Management’s Discussion and Analysis of Financial Condition and Resultsof Operation” and other items within this Annual Report on Form 10-K.  In some cases, forward-looking statements canbe identified 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 comparableterminology.

Theforward-looking statements contained in this Annual Report on Form 10-K arelargely based on our expectations, which reflect estimates and assumptions madeby our management.  These estimates andassumptions reflect our best judgment based on currently known marketconditions and other factors.  Althoughwe believe such estimates and assumptions to be reasonable, they are inherentlyuncertain and involve a number of risks and uncertainties beyond ourcontrol.  In addition, management’sassumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this AnnualReport on Form 10-K are not guarantees of future performance, and we cannotassure any reader that such statements will be realized or the forward-lookingstatements or events will occur.  Actualresults may differ materially from those anticipated or implied inforward-looking statements due to factors listed in the “Risk Factors” sectionand elsewhere in this 

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**Item 1.  Business and Properties - Continued**

Annual Report onForm 10-K.  The forward-lookingstatements 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-lookingstatement, whether as a result of new information, future events or otherwise.

**SecuritiesAct Disclaimer**

This Form 10-Kdoes not constitute an offer to sell or the solicitation of an offer to buy anysecurities.

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**Item 1A**.  RiskFactors

Our business hasmany risks.  Factors that couldmaterially adversely affect our business, financial condition, operatingresults or liquidity and the trading price of our units are described below.  This information should be consideredcarefully, together with other information in this report and other reports andmaterials we file with the SEC.

**Risks Related to Our Business**

***We may not havesufficient cash flow from operations to pay the quarterly distribution at thecurrent distribution level and future distributions to our unitholders mayfluctuate from quarter to quarter.***

We may not have sufficient cash flow from operations each quarter to paythe quarterly distribution at the current distribution level.  Under the terms of our limited liabilitycompany agreement, the amount of cash otherwise available for distribution willbe reduced by our operating expenses and the amount of any cash reserve amountsthat our Board of Directors establishes to provide for future operations, futurecapital expenditures, future debt service requirements and future cashdistributions to our unitholders.  Theamount of cash we can distribute on our units principally depends upon theamount of cash we generate from our operations, which will fluctuate fromquarter to quarter based on, among other things:

·                  the amount of oil and gas we produce;

·                  the price at which we are able to sell our oil andgas production;

·                  the level of our operating costs;

·                  the level of our interest expense, which dependson the amount of our indebtedness and the interest payable thereon; and

·                  the level of our capital expenditures.

In addition, the actual amount of cash we will have available fordistribution will depend on other factors, some of which are beyond ourcontrol, including:

·                  our ability to make working capital borrowingsunder our credit facility to pay distributions;

·                  the costs of acquisitions, if any;

·                  fluctuations in our working capital needs;

·                  timing and collectibility of receivables;

·                  restrictions on distributions contained in ourcredit facility;

·                  prevailing economic conditions; and

·                  the amount of cash reserves established by ourBoard of Directors for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute to ourunitholders in any quarter may fluctuate significantly from quarter to quarterand may be significantly less than the current distribution level.

We will be prohibited from borrowing under our credit facility to paydistributions to unitholders if the amount of borrowings outstanding under ourcredit facility reaches or exceeds 90% of the borrowing base, which is theamount of money available for borrowing, as determined semi-annually by ourlenders in their sole discretion.  Thelenders will redetermine the borrowing base based on an engineering report withrespect to our oil and gas reserves, which will take into account theprevailing oil and 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 issolely dependent on our ability to generate sufficient cash from ouroperations.

***If wedo not make acquisitions on economically acceptable terms, then our futuregrowth and ability to increase distributions will be limited.***

Our ability togrow and to increase distributions to our unitholders is partially dependent onour ability to make acquisitions that result in an increase in pro formaavailable cash per unit.  We may beunable to make such acquisitions because we are:

·                  unable to identify attractive acquisitioncandidates or negotiate acceptable purchase contracts with them;

·                  unable to obtain financing for these acquisitionson economically acceptable terms; or

·                  outbid by competitors.

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

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**Item 1A**.  RiskFactors - Continued

Any acquisitioninvolves potential risks, including, among other things:

·                  the risk that reserves expected to support theacquired assets may not be of the anticipated magnitude or may not be developedas anticipated;

·                  mistaken assumptions about revenues and costs,including synergies;

·                  significant increases in our indebtedness andworking capital requirements;

·                  an inability to integrate successfully or timelythe businesses we acquire;

·                  the assumption of unknown liabilities;

·                  limitations on rights to indemnity from theseller;

·                  the diversion of management’s attention from otherbusiness concerns;

·                  increased demands on existing personnel;

·                  customer or key employee losses at the acquiredbusinesses; and

·                  the failure to realize expected growth orprofitability.

The scope and costof these risks may ultimately be materially greater than estimated at the timeof the acquisition.  Further, our futureacquisition costs may be higher than those we have achieved historically.  Any of these factors could adversely impactour future growth and our ability to increase distributions.

***We have significant indebtedness under our creditfacility.  Our credit facility has substantial restrictions and financialcovenants and we may have difficulty obtaining additional credit, which couldadversely affect our operations and our ability to pay distributions to ourunitholders.***

We havesignificant indebtedness under our credit facility.  As of February 28, 2007, we had approximately$600.8 million outstanding under our credit facility (with additional borrowingcapacity of approximately $120.2 million). As a result of our indebtedness, we will use a portion of our cash flowto pay interest and principal when due, which will reduce the cash available tofinance our operations and other business activities and could limit ourflexibility in planning for or reacting to changes in our business and theindustry in which we operate.  The amount of our indebtedness may alsocause us to be more vulnerable to economic downturns and adverse developmentsin our business.  Our ability to access the capital markets to raisecapital on favorable terms will be affected by our debt level and by adversemarket conditions resulting from, among other things, general economicconditions, contingencies and uncertainties that are difficult to predict andimpossible to control.  Such a development could adversely affect ourability to obtain financing for working capital, capital expenditures oracquisitions or to refinance existing indebtedness.

We depend on ourcredit facility for future capital needs and to fund a portion of ourdistributions.  The credit facility restricts our ability to obtainadditional financing, make investments, lease equipment, sell assets and engagein business combinations.  We also are required to comply with certainfinancial covenants and ratios.  Our ability to comply with theserestrictions and covenants in the future is uncertain and will be affected bythe levels of cash flow from our operations and events or circumstances beyondour control.  Our failure to comply withany of the restrictions and covenants under our credit facility could result ina default under our credit facility, which could cause all of our existingindebtedness to be immediately due and payable.

Availability underour credit facility is determined semi-annually at the discretion of thelenders and is based in part on oil and gas prices.  The lenders canunilaterally adjust the borrowing base and the borrowings permitted to beoutstanding under the credit facility.  Any increase in the borrowing baserequires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaidimmediately, or we must pledge other oil and gas properties as additionalcollateral.  We do not currently have any substantial unpledgedproperties, and we may not have the financial resources in the future to makeany mandatory principal prepayments required under the credit facility. Significant declines in our production or significant declines in realized oilor gas prices for prolonged periods and resulting decreases in our borrowingbase may force us to reduce or suspend distributions to our unitholders.

***Increases in interest rates could adversely affect ourbusiness, results of operations, cash flows from operations and financialcondition.***

In addition to ourexposure to commodity prices, we have significant exposure to increases ininterest rates.  All of the indebtedness outstanding under our creditfacility is at variable interest rates, after giving effect to existinginterest swap arrangements.  Therefore, our business, results ofoperations and cash flows from operations could be adversely affected by significantincreases in interest rates.

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**Item 1A**.  RiskFactors - Continued

An increase in interestrates may cause a corresponding decline in demand for equity investments, inparticular for yield-based equity investments such as our units.  Any suchreduction in demand for our units resulting from other more attractiveinvestment opportunities may cause the trading price of our units to decline.

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

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

·                  the domestic and foreign supply of and demand foroil and gas;

·                  the price and level of foreign imports;

·                  the level of consumer product demand;

·                  weather conditions;

·                  overall domestic and global economic conditions;

·                  political and economic conditions in oil and gasproducing countries, including those in the Middle East and South America;

·                  the ability of members of the Organization ofPetroleum Exporting Countries to agree to and maintain oil price and productioncontrols;

·                  the impact of the U.S. dollar exchange rates onoil and gas prices;

·                  technological advances affecting energyconsumption;

·                  domestic and foreign governmental regulations andtaxation;

·                  the impact of energy conservation efforts;

·                  the proximity and capacity of oil and gaspipelines and other transportation facilities; and

·                  the price and availability of alternative fuels.

In the past, theprices of oil and gas have been extremely volatile, and we expect thisvolatility to continue.  If commodityprices decline significantly for a prolonged period, our cash flow fromoperations will decline, and we may have to lower our distribution or may notbe able to pay distributions at all.

***Futureprice declines or downward reserve revisions may result in a write-down of ourasset carrying values.***

Declines in oiland gas prices may result in our having to make substantial downwardadjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase,production data factors change or drilling results deteriorate, accountingrules may require us to write-down, as a non-cash charge to earnings, thecarrying value of our oil and gas properties for impairments.  We are required to perform impairment testson our assets periodically and whenever events or changes in circumstanceswarrant a review of our assets.  To theextent such tests indicate a reduction of the estimated useful life orestimated future cash flows of our assets, the carrying value may not berecoverable and therefore require a write-down. We may incur impairment charges in the future, which could have amaterial adverse effect on our results of operations in the period incurred andon our ability to borrow funds under our credit facility, which in turn mayadversely affect our ability to make cash distributions to our unitholders.

***Unless we replace our reserves, our reserves andproduction will decline, which would adversely affect our cash flow fromoperations and our ability to make distributions to our unitholders.***

Producing oil andgas reservoirs are characterized by declining production rates that varydepending upon reservoir characteristics and other factors.  The overall rate of decline for ourproduction will change if production from our existing wells declines in adifferent manner than we have estimated and can change when we drill additionalwells, make acquisitions and under other circumstances.  Thus, our future oil and gas reserves andproduction and, therefore, our cash flow and income, are highly dependent onour success in efficiently developing and exploiting our current reserves andeconomically finding or acquiring additional recoverable reserves.  We may not be able to develop, find or acquireadditional reserves to replace our current and future production at acceptablecosts, which would adversely affect our cash flow from operations and ourability to make distributions to our unitholders.

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**Item 1A**.  RiskFactors - Continued

***Our estimated reserves are based on manyassumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlyingassumptions will materially affect the quantities and present value of ourreserves.***

No one can measureunderground accumulations of oil and gas in an exact way.  Reserve engineering requires subjectiveestimates of underground accumulations of oil and gas and assumptionsconcerning future oil and gas prices, production levels, and operating anddevelopment costs.  As a result,estimated quantities of proved reserves and projections of future productionrates and the timing of development expenditures may prove to be inaccurate.  Independent petroleum engineering firmsprepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserveestimates taking into account the results of actual drilling andproduction.  Some of our reserveestimates are made without the benefit of a lengthy production history, whichare less reliable than estimates based on a lengthy production history.  Also, we make certain assumptions regardingfuture oil and gas prices, production levels, and operating and developmentcosts that may prove incorrect.  Anysignificant variance from these assumptions by actual figures could greatlyaffect our estimates of reserves, the economically recoverable quantities ofoil and gas attributable to any particular group of properties, theclassifications of reserves based on risk of recovery and estimates of thefuture net cash flows.  Numerous changesover time to the assumptions on which our reserve estimates are based, asdescribed above, often result in the actual quantities of oil and gas weultimately recover being different from our reserve estimates.

The present valueof future net cash flows from our proved reserves is not necessarily the sameas the current market value of our estimated oil and gas reserves.  We base the estimated discounted future netcash flows from our proved reserves on prices and costs in effect on the day ofestimate.  However, actual future netcash flows from our oil and gas properties also will be affected by factorssuch as:

·                  actual prices we receive for oil and gas;

·                  the amount and timing of actual production;

·                  supply of and demand for oil and gas; and

·                  changes in governmental regulations or taxation.

The timing of bothour production and our incurrence of expenses in connection with thedevelopment and production of oil and gas properties will affect the timing ofactual future net cash flows from proved reserves, and thus their actualpresent value.  In addition, the 10%discount factor we use when calculating discounted future net cash flows maynot be the most appropriate discount factor based on interest rates in effectfrom time to time and risks associated with us or the oil and gas industry ingeneral.

***Our developmentoperations require substantial capital expenditures, which will reduce our cashavailable for distribution.  We may beunable to obtain needed capital or financing on satisfactory terms, which couldlead to a decline in our reserves.***

The oil and gasindustry is capital intensive.  We makeand expect to continue to make substantial capital expenditures in our businessfor the development, production and acquisition of oil and gas reserves.  These expenditures will reduce our cashavailable for distribution.  We intend tofinance our future capital expenditures with cash flow from operations and ourfinancing arrangements.  Our cash flowfrom operations and access to capital are subject to a number of variables,including:

·                  our proved reserves;

·                  the level of oil and gas we are able to producefrom existing wells;

·                  the prices at which we are able to sell our oiland gas; and

·                  our ability to acquire, locate and produce newreserves.

If our revenues orthe borrowing base under our credit facility decrease as a result of lower oiland gas prices, operating difficulties, declines in reserves or for any otherreason, we may have limited ability to obtain the capital necessary to sustainour operations at current levels.  Ourcredit facility restricts our ability to obtain new financing.  If additional capital is needed, we may notbe able to obtain debt or equity financing on terms favorable to us, or atall.  If cash generated by operations oravailable under our credit facility is not sufficient to meet our capitalrequirements, the failure to obtain additional financing could result in acurtailment of our development operations, which in turn could lead to apossible decline in our reserves.

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**Item 1A**.  RiskFactors - Continued

***Ourbusiness depends on gathering and transportation facilities.  Any limitation in the availability of thosefacilities would interfere with our ability to market the oil and gas weproduce, and could reduce our cash available for distribution and adverselyimpact expected increases in oil and gas production from our drilling program.***

Although we gathermost of our current production, the marketability of our oil and gas productiondepends in part on the availability, proximity and capacity of gathering andpipeline systems.  The amount of oil andgas that can be produced and sold is subject to limitation in certaincircumstances, such as pipeline interruptions due to scheduled and unscheduledmaintenance, excessive pressure, physical damage to the gathering ortransportation system, or lack of contracted capacity on such systems.  The curtailments arising from these andsimilar circumstances may last from a few days to several months.  In many cases, we are provided only withlimited, if any, notice as to when these circumstances will arise and theirduration.  In addition, some of our wellsare drilled in locations that are not serviced by gathering and transportationpipelines, or the gathering and transportation pipelines in the area may nothave sufficient capacity to transport the additional production.  As a result, we may not be able to sell theoil and gas production from these wells until the necessary gathering andtransportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, orsignificant delay in the construction of necessary gathering and transportationfacilities, would interfere with our ability to market the oil and gas weproduce, and could reduce our cash available for distribution and adverselyimpact expected increases in oil and gas production from our drilling program.

***We depend on certain key customers for sales of ouroil and gas.  To the extent these andother customers reduce the volumes of oil and gas they purchase from us, ourrevenues and cash available for distribution could decline.***

For the year endedDecember 31, 2006, Dominion Resources, Inc. and ConocoPhillips accountedfor approximately 53%, and 14%, respectively, of our total volumes, or 67% inthe aggregate.  For the year ended December 31, 2005, DominionResources, Inc., Cabot Oil & Gas Corporation and UGI Energy Services, Inc.accounted for approximately 48%, 14% and 10%, respectively, of our totalvolumes, or 72% in the aggregate.  To the extent these and other customersreduce the volumes of oil or gas that they purchase from us, our revenues andcash available for distribution could decline.

***Weare exposed to the credit risk of our customers and certain parties, and ageneral increase in the nonpayment and nonperformance by our customers couldhave an adverse impact on our financial condition and results of operations.***

We aresubject to risks of loss resulting from nonpayment or nonperformance by ourcustomers.  Any increase in thenonpayment and nonperformance by our customers could have an adverse impact onour operating results and could cause our cash available for distribution todecline.

***Shortages of drilling rigs, pipe, equipment and crews could delay ouroperations and increase our drilling costs, which could impact our ability togenerate sufficient cash flow from operations to pay quarterly distributions toour unitholders at the current distribution level.***

Higher oil and gas prices increase the demand for drilling rigs, pipe,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 andoil field equipment and services could restrict our ability to drill the wellsand conduct the operations which we currently have planned.  Any delay in the drilling of new wells orsignificant increase in drilling costs could impact our ability to generatesufficient cash flow from operations to pay quarterly distributions to ourunitholders at the current distribution level.

***Because we handle oil and gas and other hydrocarbons, we may incursignificant costs and liabilities in the future resulting from a failure tocomply with new or existing environmental regulations or an accidental releaseof hazardous substances into the environment.***

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

·                  the federal Clean Air Act and comparable statelaws and regulations that impose obligations related to air emissions;

·                  the federal Clean Water Act and comparable statelaws and regulations that impose obligations related to discharges ofpollutants into regulated bodies of water;

·                  the federal Resource Conservation and RecoveryAct, and comparable state laws that impose requirements for the handling anddisposal of waste from our facilities; and

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**Item 1A**.  RiskFactors - Continued

·                  the Comprehensive Environmental Response,Compensation and Liability Act of 1980, also known as “Superfund,” andcomparable state laws that regulate the cleanup of hazardous substances thatmay have been released at properties currently or previously owned or operatedby us or at locations to which we have sent waste for disposal.

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

There is aninherent risk that we may incur environmental costs and liabilities due to thenature of our business and the substances we handle.  For example, an accidental release from oneof our wells or gathering pipelines could subject us to substantial liabilitiesarising from environmental cleanup and restoration costs, claims made by neighboringlandowners and other third parties for personal injury and property damage, andfines or penalties for related violations of environmental laws orregulations.  Moreover, the possibilityexists that stricter laws, regulations or enforcement policies couldsignificantly increase our compliance costs and the cost of any remediationthat may become necessary.  We may not beable to recover these costs from insurance. See Part I.  Item 1.  “Business and Properties - Operation -Environmental Matters and Regulation.”

***Wemay decide not to drill some of the prospects we have identified, and locationsthat we decide to drill may not yield oil and gas in commercially viablequantities.***

Our prospectivedrilling locations are in various stages of evaluation, ranging from a prospectthat is ready to drill to a prospect that will require additional seismic dataprocessing and interpretation.  Based ona variety of factors, including future oil and gas prices, the generation ofadditional seismic or geological information, the availability of drilling rigsand other factors, we may decide not to drill one or more of theseprospects.  As a result, we may not beable to increase or maintain our reserves or production, which in turn couldhave an adverse effect on our business, financial condition or results ofoperations.

The cost ofdrilling, completing and operating a well is often uncertain, and cost factorscan adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that areproductive but do not produce enough oil and gas to be commercially viableafter drilling, operating and other costs. If we drill future wells that we identify as dry holes, our drillingsuccess rate would decline, which could have an adverse effect on our business,financial condition or results of operations.

***Manyof our leases are in areas that have been partially depleted or drained byoffset wells.***

Our key projectareas are located in some of the most active drilling areas of the producingbasins in the United States.  As aresult, many of our leases are in areas that have already been partiallydepleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantitiesof oil and gas in these areas.

Our identifieddrilling location inventories are scheduled out over several years, making themsusceptible to uncertainties that could materially alter the occurrence ortiming of their drilling, resulting in temporarily lower cash from operations,which may impact our ability to pay distributions.

Our management hasspecifically identified and scheduled drilling locations as an estimation ofour future multi-year drilling activities on our existing acreage.  As of December 31, 2006, we hadidentified 1,254 drilling locations, of which 716 were proved undevelopedlocations and 538 were other locations. These identified drilling locations represent a significant part of ourgrowth strategy.  Our ability to drilland develop these locations depends on a number of factors, including theavailability of capital, seasonal conditions, regulatory approvals, oil and gasprices, costs and drilling results.  Inaddition, DeGolyer and MacNaughton has not assigned any proved reserves to the538 other drilling locations we have identified and scheduled for drilling, andtherefore there may be greater uncertainty with respect to the success ofdrilling wells at these drilling locations. Our final determination on whether to drill any of these drillinglocations will be dependent upon the factors described above as well as, tosome degree, the results of our drilling activities with respect to our proveddrilling locations.  Because of theseuncertainties, we do not know if the numerous drilling locations we have identifiedwill be drilled within our expected timeframe or will ever be drilled or if wewill be able to produce oil and gas from these or any 

22

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**Item 1A**.  RiskFactors - Continued

other potentialdrilling locations.  As such, our actualdrilling activities may materially differ from those presently identified,which could adversely affect our business.

***Drillingfor and producing oil and gas are high risk activities with many uncertaintiesthat could adversely affect our financial condition or results of operationsand, as a result, our ability to pay distributions to our unitholders.***

Our drilling activitiesare subject to many risks, including the risk that we will not discovercommercially productive reservoirs. Drilling for oil and gas can be uneconomic, not only from dry holes, butalso from productive wells that do not produce sufficient revenues to becommercially viable.  In addition, ourdrilling and producing operations may be curtailed, delayed or canceled as a resultof other factors, including:

·                  the high cost, shortages or delivery delays ofequipment and services;

·                  unexpected operational events;

·                  adverse weather conditions, particularly seasonalweather conditions in the spring;

·                  facility or equipment malfunctions;

·                  title problems;

·                  pipeline ruptures or spills;

·                  compliance with environmental and othergovernmental requirements;

·                  unusual or unexpected geological formations;

·                  loss of drilling fluid circulation;

·                  formations with abnormal pressures;

·                  fires;

·                  blowouts, craterings and explosions; and

·                  uncontrollable flows of oil and gas or wellfluids.

Any of theseevents 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 ordinarilymaintain insurance against certain losses and liabilities arising from ouroperations.  However, it is impossible toinsure against all operational risks in the course of our business.  Additionally, we may elect not to obtaininsurance if we believe that the cost of available insurance is excessiverelative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or inamounts in excess of existing insurance coverage.  The occurrence of an event that is not fullycovered by insurance could have a material adverse impact on our businessactivities, financial condition and results of operations.

***Propertiesthat we buy may not produce as projected and we may be unable to determinereserve potential, identify liabilities associated with the properties orobtain protection from sellers against such liabilities.***

One of our growthstrategies is to capitalize on opportunistic acquisitions of oil and gasreserves.  However, our reviews ofacquired properties are inherently incomplete because it is not feasible toreview in depth every individual property involved in each acquisition.  Even a detailed review of records andproperties may not necessarily reveal existing or potential problems, nor willit permit a buyer to become sufficiently familiar with the properties to assessfully their deficiencies and potential. Inspections may not always be performed on every well, and environmentalproblems, such as ground water contamination, are not necessarily observableeven when an inspection is undertaken.

***Ourhedging 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 morepredictable cash flow and to reduce our exposure to adverse fluctuations in theprices of oil and gas, we currently and may in the future enter into hedgingarrangements for a significant portion of our oil and gas production.  If we experience a sustained materialinterruption in our production or if we are unable to perform our drillingactivity as planned, we might be forced to satisfy all or a portion of ourhedging obligations without the benefit of the cash flow from our sale of theunderlying physical commodity, resulting in a substantial reduction of ourliquidity.  Under our credit facility, weare prohibited from hedging all of our production, and we therefore retain therisk of a price decrease on our unhedged volumes.

23

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**Item 1A**.  Risk Factors - Continued

***Wedepend on our Chairman, President and Chief Executive Officer who would bedifficult to replace.***

We depend on theperformance of Michael C. Linn, our Chairman, President and Chief ExecutiveOfficer.  We maintain no key personinsurance for Mr. Linn.  The loss of Mr.Linn could negatively impact our ability to execute our strategy and ourresults of operations.

***Wemay be unable to compete effectively with larger companies, which may adverselyaffect our ability to generate sufficient revenue to allow us to paydistributions to our unitholders.***

The oil and gasindustry is intensely competitive, and we compete with companies that havegreater resources than we have.  Ourability to acquire additional properties and to discover reserves will bedependent upon our ability to evaluate and select suitable properties and toconsummate transactions in a highly competitive environment.  Many of our larger competitors not only drillfor and produce oil and gas, but also carry on refining operations and marketpetroleum and other products on a regional, national or worldwide basis.  These companies may be able to pay more foroil and gas properties and evaluate, bid for and purchase a greater number ofproperties than our financial or human resources permit.  In addition, these companies may have agreater ability to continue drilling activities during periods of low oil andgas prices and to absorb the burden of present and future federal, state, localand other laws and regulations.  Ourinability to compete effectively with larger companies could have a materialadverse impact on our business activities, financial condition and results ofoperations.

***Weare subject to complex federal, state, local and other laws and regulationsthat could adversely affect the cost, manner or feasibility of doing business.***

Our operations areregulated extensively at the federal, state and local levels.  Environmental and other governmental laws andregulations have increased the costs to plan, design, drill, install, operateand abandon oil and gas wells.  Underthese laws and regulations, we could also be liable for personal injuries,property damage and other damages.  Failureto comply with these laws and regulations may result in the suspension or terminationof our operations and subject us to administrative, civil and criminalpenalties.  Moreover, public interest inenvironmental protection has increased in recent years, and environmentalorganizations have opposed, with some success, certain drilling projects.

Part of theregulatory environment in which we operate includes, in some cases, legalrequirements for obtaining environmental assessments, environmental impactstudies and/or plans of development before commencing drilling and productionactivities.  In addition, our activitiesare subject to the regulations regarding conservation practices and protectionof correlative rights.  These regulationsaffect our operations and limit the quantity of oil and gas we may produce andsell.  A major risk inherent in ourdrilling plans is the need to obtain drilling permits from state and localauthorities.  Delays in obtainingregulatory approvals or drilling permits, the failure to obtain a drillingpermit for a well or the receipt of a permit with unreasonable conditions orcosts could have a material adverse effect on our ability to develop ourproperties.  Additionally, the oil andgas regulatory environment could change in ways that might substantiallyincrease the financial and managerial costs of compliance with these laws andregulations and, consequently, adversely affect our ability to paydistributions to our unitholders.  For adescription of the laws and regulations that affect us, see Part I.  Item 1. “Business and Properties - Operations - Environmental Matters andRegulation” and “Business - Operations - Other Regulation of the Oil and GasIndustry” in this Annual Report on Form 10-K for a description of the laws andregulations that affect us.

***If wefail to develop or maintain an effective system of internal controls, we maynot be able to accurately report our financial results or prevent fraud.  As a result, current and potentialunitholders could lose confidence in our financial reporting, which would harmour business and the trading price of our units.***

A company’sinternal control over financial reporting is a process designed to providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. Because of its inherent limitations, internal control over financialreporting may not prevent or detect misstatements.  Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.  If we cannot provide reliable financialreports or prevent fraud, our reputation and operating results could beharmed.  We cannot be certain that ourefforts to develop and maintain our internal controls will be successful, thatwe will be able to maintain adequate controls over our financial processes andreporting in the future or that we will be able to comply with our obligationsunder Section 404 of the Sarbanes-Oxley Act of 2002 by our initial compliancedate of December 31, 2007.  Weidentified a material weakness in our internal controls during the course ofevaluating disclosure controls and procedures as of December 31, 2005 anddue to that material weakness, concluded our 

24

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**Item 1A**.  Risk Factors - Continued

disclosurecontrols and procedures were not effective as of December 31, 2006.  For additional information, see Part II.  Item 9A. “Controls and Procedures” for additional information.

Any failure todevelop or maintain effective internal controls, or difficulties encountered inimplementing or improving our internal controls, could harm our operatingresults or cause us to fail to meet certain reporting obligations.  Ineffective internal controls could alsocause investors to lose confidence in our reported financial information, whichcould have a negative effect on the trading price of our units.

***Wemay face risks related to the restatement of our financial statements.***

Werestated our financial statements for the period from March 14, 2003(inception) through December 31, 2003, for the year endedDecember 31, 2004 and certain financial statement line items for the ninemonths ended September 30, 2004 and 2005, primarily to correct certainaccounting entries related to the acquisition of oil and gas properties.  As a result of these changes, which primarilyaffected fiscal 2003 and 2004, revenues were reduced by $0.9 million and $1.7million, respectively, and net loss was increased by $0.4 million and $83,018,respectively.  Companies that restatetheir financial statements sometimes face litigation claims and/or SECproceedings following such a restatement of financial results.  Although we are unaware of any pending orthreatened claims or proceedings relating to our restatement, if any claim orproceeding were to be commenced and successfully asserted against us, we couldface monetary judgments, penalties or other sanctions which could adverselyaffect our financial condition and could cause the price of our units todecline.

**Risks Related to Our Structure**

***Our management and Quantum Energy Partners own, in theaggregate, a significant interest in us, with management and Quantum EnergyPartners owning approximately 11.1% and 20.2%, respectively, of our outstandingunits.***

Our management andQuantum Energy Partners own or control an aggregate 31.2% of our outstandingunits without giving effect to the potential conversion of 7,465,946 non-votingClass C units into units.  Postconversion of the Class C units, management and Quantum Energy Partners areexpected to own or control approximately 9.6% and 17.6%, respectively, of ouroutstanding units.  Accordingly,management and Quantum Energy Partners, acting together, possess significantvoting power on substantially all matters submitted to a vote of the holders ofour units.  This concentration of ownership may have the effect ofpreventing or discouraging transactions involving an actual or a potentialchange of control of our company, regardless of whether a premium is offeredover then-current market prices.

***Eachof management or Quantum Energy Partners, or both, may have conflicts ofinterest with us.  Our limited liabilitycompany agreement limits the remedies available to our unitholders in the eventunitholders have a claim relating to conflicts of interest.***

Conflicts ofinterest may arise between our management or Quantum Energy Partners on onehand, and the Company and our unitholders on the other hand.  These potential conflicts may relate to thedivergent interests of our management or Quantum Energy Partners.  Situations in which the interests of our managementor Quantum Energy Partners may differ from interests of our non-affiliatedunitholders include, among others, the following situations:

·                  our limited liability company agreement gives ourBoard of Directors broad discretion in establishing cash reserves for theproper conduct of our business, which will affect the amount of cash availablefor distribution.  For example, ourmanagement will use its reasonable discretion to establish and maintain cashreserves sufficient to fund our drilling program;

·                  our management team determines the timing andextent of our drilling program and related capital expenditures, assetpurchases and sales, borrowings, issuances of additional membership interestsand reserve adjustments, all of which will affect the amount of cash that wedistribute to our unitholders; and

·                  Quantum Energy Partners and other affiliates ofour directors are not prohibited from investing or engaging in other businessesor activities that compete with us.

***We may issueadditional units without unitholder approval, which would dilute existingownership interests.***

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

25

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**Item 1A**.  Risk Factors - Continued

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

·                  an individual unitholder’s proportionate ownershipinterest in us may decrease;

·                  the amount of cash distributed on each unit maydecrease;

·                  the relative voting strength of each previouslyoutstanding unit may be reduced; and

·                  the market price of the units may decline.

***The market priceof our units could be volatile due to a number of factors, many of which arebeyond our control.***

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

·                  changes in securities analysts’ recommendationsand their estimates of our financial performance;

·                  the public’s reaction to our press releases,announcements and our filings with the SEC;

·                  fluctuations in broader securities market pricesand volumes, particularly among securities of oil and gas companies andsecurities of publicly-traded limited partnerships and limited liabilitycompanies;

·                  changes in market valuations of similar companies;

·                  departures of key personnel;

·                  commencement of or involvement in litigation;

·                  variations in our quarterly results of operationsor those of other oil and gas companies;

·                  variations in the amount of our quarterly cashdistributions;

·                  future issuances and sales of our units; and

·                  changes in general conditions in the U.S. economy,financial markets or the oil and gas industry.

In recent years, the securities market has experienced extreme price andvolume fluctuations.  This volatility hashad a significant effect on the market price of securities issued by manycompanies for reasons unrelated to the operating performance of thesecompanies.  Future market fluctuationsmay result in a lower price of our units.

***Quantum Energy Partners and others may sell units in thefuture, which could reduce the market price of our outstanding units.***

As of February 28,2007, Quantum Energy Partners controlled an aggregate of 10,144,585 of ourunits.  In addition, we have agreed, upon demand by Quantum EnergyPartners, to register for sale units held by Quantum Energy Partners, certainnon-affiliated investors and certain members of our management.  Theseregistration rights allow Quantum Energy Partners to request registration oftheir units and to include any of those units in a registration of other securitiesby us.  If Quantum Energy Partners were to sell a substantial portion oftheir units, then the market price of our outstanding units may decline.

We also completeda private offering to institutional investors of 5,534,687 units and 9,185,965newly created Class B units in October 2006, which were converted into units ona one-for-one basis in January 2007.  Weagreed to file a registration statement with the SEC covering the units and theunits underlying the Class B units with the SEC.  In accordance with the agreement, theregistration statement must be declared effective by the SEC no later than 210days following the closing (extended by separate agreement from 165 days).

In February 2007, wecompleted a private offering to institutional investors of 6,650,144 units and7,465,946 Class C units.  We agreed tofile a registration statement with the SEC covering the units and the unitsunderlying the Class C units with the SEC. In accordance with the agreement, the registration statement must bedeclared effective by the SEC no later than 165 days following the closing.

Each of our privateplacements discussed above were made without registration under the SecuritiesAct of 1933, as amended (the “Securities Act”) in reliance on the exemptionfrom the registration requirements for transactions not involving a publicoffering contained in Section 4(2) of the Securities Act.

If the institutionalpurchasers in the private placements discussed above were to sell a substantialportion of their units, then the market price of our outstanding units maydecline.

26

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**Item 1A**.  Risk Factors - Continued

***We do not have the sameflexibility as other types of organizations to accumulate cash and equity toprotect against illiquidity in the future.***

Unlike a corporation, our limited liability companyagreement requires us to make quarterly distributions to our unitholders of allavailable cash reduced by any amounts of reserves for commitments andcontingencies, including capital and operating costs and debt service requirements.  The value of our units may decrease in directcorrelation with decreases in the amount we distribute per unit.  Accordingly, if we experience a liquidityproblem in the future, we may have difficulty issuing more equity torecapitalize.

**Tax Risks to Unitholders**

***Ourtax treatment depends on our status as a partnership for federal income taxpurposes, as well as our not being subject to entity-level taxation byindividual states.  If the IRS were totreat us as a corporation for federal income tax purposes or we were to becomesubject to entity-level taxation for state tax purposes, taxes paid, if any,would reduce the amount of cash available for distribution.***

The anticipatedafter-tax benefit of an investment in our units depends largely on our beingtreated as a partnership for federal income tax purposes.  We have not requested, and do not plan torequest, a ruling from the IRS on this or any other tax matters.

If we were treatedas a corporation for federal income tax purposes, we would pay federal incometax on our taxable income at the corporate tax rates, currently at a maximumrate of 35%, and would likely pay state income tax at varying rates.  Distributions to unitholders would be taxedas corporate dividends, and no income, gain, loss, deduction or credit wouldflow through to unitholders.  Because atax may be imposed on us as a corporation, our cash available for distributionto our unitholders could be reduced. Therefore, our treatment as a corporation could result in a materialreduction in the anticipated cash flow and after-tax return to our unitholdersand therefore result in a substantial reduction in the value of our units.

Current law or ourbusiness may change so as to cause us to be treated as a corporation forfederal income tax purposes or otherwise subject us to entity-leveltaxation.  In addition, because ofwidespread state budget deficits, several states are evaluating ways to subjectpartnerships and limited liability companies to entity-level taxation throughthe imposition of state income, franchise or other forms of taxation.  If any state were to impose a tax upon us asan entity, the cash available for distribution to unitholders may be reduced.

***Ourunitholders may be required to pay taxes on income from us even if they do notreceive any cash distributions from us.***

Our unitholdersare required to pay federal income taxes and, in some cases, state and localincome taxes on their share of our taxable income, whether or not they receivecash distributions from us.  Our unitholdersmay not receive cash distributions from us equal to their share of our taxableincome or even equal to the actual tax liability that results from their shareof our taxable income.

***Asuccessful IRS contest of the federal income tax positions we take mayadversely affect the market for our units, and the costs of any contest willreduce cash available for distribution.***

We have notrequested a ruling from the IRS with respect to our treatment as a partnershipfor federal income tax purposes or any other matter that affects us.  The IRS may adopt positions that differ fromthe positions we take.  It may benecessary to resort to administrative or court proceedings to sustain some orall of the positions we take and a court may disagree with some or all of thosepositions.  Any contest with the IRS maymaterially and adversely impact the market for our units and the price at whichthey trade.  In addition, our costs ofany contest with the IRS will result in a reduction in cash available fordistribution to our unitholders and thus will be borne indirectly by ourunitholders.

***Wewill treat each purchaser of our units as having the same tax benefits withoutregard to the units purchased.  The IRSmay challenge this treatment, which could adversely affect the value of theunits.***

Because we cannotmatch transferors and transferees of units, we will adopt depreciation andamortization positions that may not conform with all aspects of existing U.S.Treasury regulations.  A successful IRSchallenge to those positions could adversely affect the amount of tax benefitsavailable to our unitholders.  It alsocould affect the timing of these tax benefits or 

27

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**Item 1A**.  Risk Factors - Continued

the amount of gainon the sale of units and could have a negative impact on the value of our unitsor result in audits of and adjustments to our unitholders’ tax returns.

***Ourunitholders may be subject to state and local taxes and return filingrequirements.***

In addition tofederal income taxes, our unitholders 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 jurisdictionsin which we do business or own property now or in the future, even if they do notreside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and localincome tax returns and pay state and local income taxes in some or all of thesejurisdictions.  Further, our unitholdersmay be subject to penalties for failure to comply with those requirements.  We currently do business and own assets inWest Virginia, Pennsylvania, New York, Virginia, California, Oklahoma, andTexas.  As we make acquisitions or expandour business, we may do business or own assets in other states in thefuture.  It is the responsibility of eachunitholder to file all United States federal, foreign, state and local taxreturns that may be required of such unitholder.  Our counsel has not rendered an opinion onthe state or local tax consequences of an investment in the units.

***Taxgain or loss on the disposition of our units could be more or less thanexpected because prior distributions in excess of allocations of income willdecrease the tax basis of the units.***

As units are sold,our unitholders will recognize gain or loss equal to the difference between theamount realized and the tax basis in those units.  Prior distributions to unitholders in excessof the total net taxable income they were allocated for a unit, which decreasedour unitholders’ tax basis in that unit, will, in effect, become taxable incometo them if the unit is sold at a price greater than their tax basis in thatunit, even if the price received 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.

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

We will be consideredto have terminated for tax purposes if there is a sale or exchange of 50% ormore of the total interests in our capital and profits within a twelve-monthperiod.  A constructive terminationresults in the closing of our taxable year for all unitholders and in the caseof a unitholder reporting on a taxable year other than a fiscal year endingDecember 31, may result in more than twelve months of our taxable incomeor loss being includable in his taxable income for the year of termination.  A constructive termination occurring on adate other than December 31, will result in us filing two tax returns (andunitholders receiving two Schedule K-ls) for one fiscal year and the cost ofthe preparation of these returns will be borne by all of our unitholders.

**Item 1B. Unresolved Staff Comments**

None.

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**Item 2.   ****Properties**

Informationconcerning our proved reserves, production, wells, acreage and related mattersare contained in Part I.  Item 1.  “Business and Properties.”

Our obligationsunder our credit facility are secured by mortgages on our oil and gasproperties. See Part II.  Item 7. “Management’sDiscussion and Analysis of Financial Condition and Results of Operation -Credit Facility” for additional information concerning our credit facility.

***Offices***

We currently lease approximately 44,000 square feet of office space inHouston, Texas at 600 Travis Street, where our principal offices are located,for which the lease expires in 2014.  Wealso currently lease approximately 20,000 square feet of office space in Pittsburgh,Pennsylvania for which the lease expires in 2015.  We own field offices in Brea, California,Glenville, West Virginia and Indiana, Pennsylvania.

**Item 3.   ****Legal Proceedings**

EffectiveSeptember 30, 2003, we purchased interests in oil and gas wells from Cabot Oil& Gas Corporation (“Cabot”) for an aggregate purchase price of $15.5million.  On September 27, 2005, PowerGas Marketing & Transmission Inc. (“Power Gas”) filed a complaint styled *Power Gas Marketing & Transmission, Inc. v. Cabot Oil & GasCorporation and Linn Energy* in the court of common pleas of IndianaCounty, Pennsylvania against Cabot and Linn alleging that Cabot conveyed suchinterests to us in breach of purported preferential purchase rights.  Power Gas alleges that we interfered withPower Gas’ contract rights and demands the right to evaluate whether toexercise its purported preferential purchase rights.  We believe that Power Gas’ allegations arewithout merit, intend to vigorously defend the matter and do not believe thatthe outcome of the matter will have a material adverse effect on our financialposition or results of operations.

Although we may, fromtime to time, be involved in litigation and claims arising out of ouroperations in the normal course of business, we are not currently a party toany material legal proceedings.  Inaddition, we are not aware of any legal or governmental proceedings against us,or contemplated to be brought against us, under the various environmentalprotection statutes to which we are subject.

**Item 4.   ****Submission of Matters to a Vote of Security Holders**

No matters were submittedto a vote of security holders of the Company during the fourth quarter of theyear ended December 31, 2006.

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**Part II**

**Item 5.****          ****Market for Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities**

**Market Information**

Our units are listed onThe NASDAQ Global Market under the symbol “LINE” and began trading on January13, 2006, after pricing of our initial public offering.

The followingtable presents the range of high and low last reported sales prices per unit,as reported by The NASDAQ Global Market, for the quarters indicated.  In addition, distributions declared duringeach quarter are presented.

 

|                   | ** ** | **Range of Sales Prices** | ** ** | **Cash  Distribution  Declared** |
|-------------------|------------|---------------------------|------------|----------------------------------|
| **Quarter Ended** | ** ** | **High**                  | ** ** | **Low**                          | ** ** | **Per Unit** |
| **2006:**         | ** ** | ** **                | ** ** | ** **                       | ** ** | ** ** |
| First quarter     |       | $                         | 22.35      |                             | $ | 19.55 |   | $ | — |
| Second quarter    |       | $                         | 21.00      |                             | $ | 18.72 |   | $ | 0.32 |
| Third quarter     |       | $                         | 24.10      |                             | $ | 20.08 |   | $ | 0.40 |
| Fourth quarter    |       | $                         | 33.46      |                             | $ | 21.21 |   | $ | 0.43 |

## **Holders**

As of February 27,2007, there were approximately 10,186 holders of our units.  In addition, there were approximately 44holders of our unregistered Class C units. There is no established public trading market for our Class C units.

## **Distributions**

Our limitedliability company agreement requires us to make quarterly distributions to ouruntiholders of all “available cash.” Available cash means, for each fiscal quarter, all cash on hand at theend of the quarter less the amount of cash reserves established by our Board ofDirectors to:

·                  provide for the proper conduct of our business(including reserves for future capital expenditures, future debt servicerequirements, and for our anticipated credit needs);

·                  comply with applicable law, any of our debtinstruments or other agreements;

·                  provide funds for distribution to our unitholders;

·                  plus all cash on hand on the date of determinationof available cash for the quarter resulting from working capital borrowingsmade after the end of the quarter for which the determination is beingmade.  Working capital borrowings areborrowings that will be made under our senior secured revolving credit facilityand in all cases are used solely for working capital purposes or to paydistributions to unitholders.

See Part II.  Item 7. “Management’s Discussion and Analysis of Results of Operation andFinancial Condition - Liquidity and Capital Resources” for a discussion on thepayment of future distributions.

30

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** **
| **Item 5.** | **Market for Registrant’s Common Equity, Related  Stockholder Matters and Issuer Purchases of Equity Securities — Continued** |
|-------------|-----------------------------------------------------------------------------------------------------------------------------------------|

 

**Securities Authorized forIssuance Under Equity Compensation Plans**

The following tablesummarizes information regarding the number of our units that are available forissuance under all of our equity compensation plans as of December 31,2006:

 
| **Plan category**                                        | ** ** | **Number of securities to be  issued upon exercise of  outstanding unit options,  warrants and rights** | ** ** | **Weighted-average exercise  price of outstanding unit  options, warrants and rights** | ** ** | **Number of securities  remaining available for  future issuance under equity  compensation plans  (excluding securities reflected  in column (a))** | ** ** |   |
|---------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------|
|                                                          |       | (a)                                                                                                                                                            |       | (b)                                                                                                                       |       | (c)                                                                                                                                                                                                              |       |   |
| Equity  compensation  plans approved by  security holders     |       | 930,500                                                                                                                                                        |       | $                                                                                                                         | 24.24      |                                                                                                                                                                                                             | 1,844,810  |   |   |
|                                                          |       |                                                                                                                                                           |       |                                                                                                                      |       |                                                                                                                                                                                                             |       |   |
| Equity  compensation  plans not approved  by security holders |       | —                                                                                                                                                         |       | —                                                                                                                    |       | —                                                                                                                                                                                                           |       |
| ** **                                                    |       |                                                                                                                                                           |       |                                                                                                                      |       |                                                                                                                                                                                                             |       |   |
| **Total**                                                     |       | 930,500                                                                                                                                                        |       | $                                                                                                                         | 24.24      |                                                                                                                                                                                                             | 1,844,810  |   |   |
|                                                               |            |                                                                                                                                                                |            |                                                                                                                           |            |                                                                                                                                                                                                                  |            |        |  |  |

**Cumulative Preferred Stock**

The Company does not haveany cumulative preferred stock outstanding.

**Sales ofUnregistered Securities**

None not previouslyreported on a Quarterly Report on Form 10-Q or a Current Report on Form8-K.  See Part II.  Item 7. “Management’s Discussion and Analysis of Results of Operation andFinancial Condition” for discussion of these matters.

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** **
| **Item 5.** | **Market for Registrant’s Common Equity, Related  Stockholder Matters and Issuer Purchases of Equity Securities — Continued** |
|-------------|-----------------------------------------------------------------------------------------------------------------------------------------|

** **

**Unitholder Return PerformancePresentation**

The performance graphbelow compares the total unitholder return on our units, with the total returnof the Standard & Poor’s 500 Index (the “S&P 500 Index”) and theAlerian MLP Index, a weighted composite of 50 prominent energy master limitedpartnerships.  Total return includes thechange in the market price, adjusted for reinvested dividends or distributions,for the period shown on the performance graph and assumes that $100 wasinvested in our Company at the last reported sale price of our units asreported on The NASDAQ Global Market ($22.00) on January 13, 2006 (the daytrading of our units commenced), and in the S&P 500 Index and the AlerianMLP Index on the same date.  The resultsshown in the graph below are not necessarily indicative of future performance.

 
| ** **         | ** ** | **1/13/2006** | ** ** | **12/29/2006** | ** ** |
|--------------------|------------|---------------|------------|----------------|------------|
| Linn Energy        |       | $             | 100        |           | $          | 153 | (1) |
| Alerian MLP  Index |       | $             | 100        |           | $          | 120 |   |
| S&P 500 Index  |       | $             | 100        |           | $          | 112 |   |

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(1)          Based on the last reported sale price of ourunits as reported on The NASDAQ Global Market on December 29, 2006 ($31.95).

Notwithstanding anythingto the contrary set forth in any of our previous or future filings under theSecurities Act of 1933 or the Securities Exchange Act of 1934 that mightincorporate this Form 10-K or future filings with SEC, in whole or in part, thepreceding performance information shall not be deemed to be “solicitingmaterial” or to be “filed” with the SEC or incorporated by reference into anyfiling except to the extent this performance presentation is specificallyincorporated by reference therein.

 

32

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** Item 6.  ****SelectedFinancial Data**

Set forth below is ourselected historical consolidated financial data for the periods indicated forLinn (Successor).  The historicalfinancial data for the periods ended December 31, 2006, 2005, 2004 and2003 and the balance sheet data as of December 31, 2006, 2005, 2004 and2003 have been derived from our audited financial statements.

On August 1, 2006,we acquired certain affiliated entities of Blacksand, located in the LosAngeles Basin, for an aggregate purchase price, including estimated transactioncosts and assumed liabilities, of approximately $301.0 million.  On August 14, 2006, effective September 1,2006, we acquired the Mid-Continent Kaiser-Francis Assets located in Oklahomafor an aggregate purchase price, including estimated transaction costs andassumed liabilities, of approximately $126.4 million.  Linn results include Blacksand and theKaiser-Francis Assets from the respective dates of acquisition in the tablesbelow.

On October 31, 2003, wecompleted a $31.5 million acquisition of oil and gas assets from WacoOil & Gas  (“Waco”) (ourPredecessor).  The historical financialdata for the period from January 1, 2003 through October 31, 2003 and the yearended December 31, 2002, have been derived from the audited financialstatements of the Predecessor entity. The balance sheet data at December 31, 2002, has been derived fromthe unaudited financial statements of the Predecessor entity.

This selected financialdata should be read in conjunction with Part II.  Item 7. “Management’s Discussion and Analysis of Financial Condition and Resultsof Operation” and the Consolidated Financial Statements and Notes theretoincluded elsewhere herein.

Because of our rapidgrowth through acquisitions and development of our properties, our historicalresults of operations and period-to-period comparisons of these results andcertain other financial data may not be meaningful or indicative of futureresults.

The followingtables present a non-GAAP financial measure, adjusted EBITDA, which we use inour business.  This measure is notcalculated or presented in accordance with generally accepted accountingprinciples, or GAAP.  We explain thismeasure below and reconcile it to the most directly comparable financialmeasure calculated and presented in accordance with GAAP in “Non-GAAP FinancialMeasure” beginning on page 51.

33

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**Item6.   ****Selected Financial Data - Continued**
| ** **                                                                | ** ** | **Successor**                              | ** ** | ** **                                                                        | ** ** | **Predecessor**         | ** ** |
|---------------------------------------------------------------------------|------------|--------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                | ** ** | **Year Ended December 31,** | ** ** | **Period from  March 14,  2003  (inception) -  December 31,** | ** ** | ** **              | ** ** | **Period from  January 1,  2003  October 31,** | ** ** | **Year Ended  December 31,** | ** ** |
| ** **                                                                | ** ** | **2006**                                   | ** ** | **2005**                                                                          | ** ** | **2004**                | ** ** | **2003** | ** ** | ** ** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                | ** ** | **(in thousands)**                    | ** ** | ** **                                                                        | ** ** | **(in thousands)** | ** ** |
| **Statement  of Operations Data:**                                        | ** ** | ** **                                 | ** ** | ** **                                                                        | ** ** | ** **              | ** ** | ** ** |   |   |   | ** ** | ** ** | ** ** | ** ** |
| **Revenues:**                                                             | ** ** | ** **                                 | ** ** | ** **                                                                        | ** ** | ** **              | ** ** | ** ** |   |   |   | ** ** | ** ** | ** ** | ** ** |
| Oil and gas sales                                                         |       | $                                          | 80,393     |                                                                              | $          | 44,645                  |       | $ | 19,502 |   | $ | 2,379 |   |   |   | $ | 4,705 |   | $ | 3,779 |   |
| Gain (loss) on oil and gas derivatives (1) (2)                            |       | 103,308                                    |       | (76,193                                                                           | )          | (11,004                 | )          | (1,437 | ) |   |   | — |   | — |   |
| Natural gas marketing revenues                                            |       | 5,598                                      |       | 4,722                                                                             |       | 520                     |       | — |   |   |   | — |   | — |   |
| Other revenues                                                            |       | 1,759                                      |       | 345                                                                               |       | 160                     |       | 4 |   |   |   | 788 |   | 698 |   |
| Total revenues                                                            |       | 191,058                                    |       | (26,481                                                                           | )          | 9,178                   |       | 946 |   |   |   | 5,493 |   | 4,477 |   |
| **Expenses:**                                                             | ** ** | ** **                                 | ** ** | ** **                                                                        | ** ** | ** **              | ** ** | ** ** |   |   |   | ** ** | ** ** | ** ** | ** ** |
| Operating expenses                                                        |       | 18,099                                     |       | 7,356                                                                             |       | 4,756                   |       | 798 |   |   |   | 2,204 |   | 2,426 |   |
| Natural gas  marketing expenses                                           |       | 4,862                                      |       | 4,401                                                                             |       | 482                     |       | — |   |   |   | — |   | — |   |
| General and  administrative expenses (3)                             |       | 39,993                                     |       | 3,332                                                                             |       | 1,488                   |       | 783 |   |   |   | 870 |   | 1,047 |   |
| Depreciation,  depletion and amortization                                 |       | 24,173                                     |       | 7,294                                                                             |       | 3,656                   |       | 562 |   |   |   | 1,185 |   | 1,494 |   |
| Total expenses                                                            |       | 87,127                                     |       | 22,383                                                                            |       | 10,382                  |       | 2,143 |   |   |   | 4,259 |   | 4,967 |   |
| **Other income and (expenses):**                                          | ** ** | ** **                                 | ** ** | ** **                                                                        | ** ** | ** **              | ** ** | ** ** |   |   |   | ** ** | ** ** | ** ** | ** ** |
| Interest income                                                           |       | 761                                        |       | 47                                                                                |       | 7                       |       | 34 |   |   |   | — |   | — |   |
| Interest  expense, net of amounts capitalized (4)                    |       | (25,494                                    | )          | (7,040                                                                            | )          | (3,530                  | )          | (517 | ) |   |   | (237 | ) | (352 | ) |
| Write-off of  deferred financing fees and other losses                    |       | (3,415                                     | )          | (420                                                                              | )          | (89                     | )          | (8 | ) |   |   | (14 | ) | (208 | ) |
| Total other  income and (expenses)                                        |       | (28,148                                    | )          | (7,413                                                                            | )          | (3,612                  | )          | (491 | ) |   |   | (251 | ) | (560 | ) |
| Income (loss)  before income taxes                                        |       | 75,783                                     |       | (56,277                                                                           | )          | (4,816                  | )          | (1,688 | ) |   |   | 983 |   | (1,050 | ) |
| Income tax  (provision) (5)                                               |       | 3,402                                      |       | (74                                                                               | )          | —                  |       | — |   |   |   | — |   | — |   |
| Income (loss)  before cumulative effect of change in accounting principle |       | 79,185                                     |       | (56,351                                                                           | )          | (4,816                  | )          | (1,688 | ) |   |   | 983 |   | (1,050 | ) |
| Cumulative  effect of change in accounting principle                      |       | —                                     |       | —                                                                            |       | —                  |       | — |   |   |   | (757 | ) | — |   |
| **Net income (loss)**                                                     |       | $                                          | 79,185     |                                                                              | $          | (56,351                 | )          | $ | (4,816 | ) | $ | (1,688 | ) |   |   | $ | 226 |   | $ | (1,050 | ) |

----

(1)             During 2005, we canceled (before their originalsettlement date) a portion of out-of-the-money gas swaps and realized a loss of$38.3 million.  We subsequentlyhedged similar volumes at higher prices. The remaining 2005 lossrelates to losses on derivative positions settled in 2005 at scheduled maturitydates that were not related to the cancellation of out-of-the-money gas hedges.

(2)       Theoil and gas derivatives are not designated as hedges under Statement ofFinancial Accounting Standards No. 133, *“Accounting Derivatives andHedging Activity”* as amended, (“SFAS 133”) even though they reduceour exposure to changes in oil and gas prices. Therefore, the changes in fair value of these instruments were recordedin our current earnings.  These amountsare non-cash gain or losses.

(3)       Theyear ended December 31, 2006 includes non-cash unit-based compensationexpense of $21.6 million, recorded in accordance with No. 123 (revised 2004), *“SharedBased Payment.”*

(4)             Includes the unrealized gain (loss) on interest rateswaps that were not designated as hedges under SFAS 133, even though theyreduce our exposure to changes in interest rates.  Therefore, the changesin fair value of these instruments wererecorded in our current earnings.  Theseamounts are non-cash gains or losses.

(5)             Linn Operating, LLC was not subject to federal income taxbefore converting to a subchapter C-corporation on June 1, 2005.  Prior to the conversion, there was no taxprovision included in our consolidated financial statements because all of ourtaxable income or loss was included in the income tax returns of the individualmembers.  The income tax benefit for theyear ended December 31, 2006 was generated by the Company’s taxablesubsidiaries having net operating losses for the year.  See Note 17 in Notes to ConsolidatedFinancial Statements for additional details about the Company’s income taxes.

34

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**Item 6.****   ****Selected Financial Data -Continued**
| ** **                                               | ** ** | **Successor**                              | ** ** | ** **                                                                            | **Predecessor**         | ** ** |
|----------------------------------------------------------|------------|--------------------------------------------|------------|---------------------------------------------------------------------------------------|-------------------------|------------|
| ** **                                               | ** ** | **Year Ended December 31,** | ** ** | **Period from  March 14,  2003 (inception) -  December 31,** | ** **              | ** ** | **Period from  January 1,  2003  October 31,** | ** ** | **Year Ended  December 31,** | ** ** |
| ** **                                               | ** ** | **2006**                                   | ** ** | **2005**                                                                              | ** **              | **2004**   | ** ** | **2003** | ** ** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                               | ** ** | **(in thousands)**                    | ** ** | ** **                                                                            | **(in thousands)** | ** ** |
| **Cash  Flow Data:**                                     | ** ** | ** **                                 | ** ** | ** **                                                                            | ** **              | ** ** | ** ** | ** ** |   |   | ** ** | ** ** | ** ** | ** ** |
| Net cash  provided by (used in) operating activities (1) |       | $                                          | (6,805     | )                                                                                     | $                       | (29,518    | ) | $ | 10,351 |   | $ | (135 | ) |   | $ | 1,826 |   | $ | (40 | ) |
| Net cash  provided by (used in) investing activities     |       | $                                          | (551,631   | )                                                                                     | $                       | (150,898   | ) | $ | (61,373 | ) | $ | (35,344 | ) |   | $ | 10,880 |   | $ | (1,480 | ) |
| Net cash  provided by (used in) financing activities     |       | $                                          | 553,990    |                                                                                  | $                       | 189,269    |   | $ | 31,167 |   | $ | 57,521 |   |   | $ | (2,415 | ) | $ | 1,056 |   |
| Capital  expenditures                                    |       | $                                          | 551,737    |                                                                                  | $                       | 150,849    |   | $ | 63,594 |   | $ | 32,863 |   |   | $ | 1,717 |   | $ | 1,375 |   |
| **Other  Financial Information (Unaudited):**            | ** ** | ** **                                 | ** ** | ** **                                                                            | ** **              | ** ** | ** ** | ** ** |   |   | ** ** | ** ** | ** ** | ** ** |
| Adjusted EBITDA (2)                                      |       | $                                          | 75,084     |                                                                                  | $                       | 21,706     |   | $ | 11,298 |   | $ | 1,014 |   |   | $ | — |   | $ | — |   |

 
| ** **                                                                           | ** ** | **Successor**                         | ** ** | ** ** | **Predecessor**                       | ** ** |
|--------------------------------------------------------------------------------------|------------|---------------------------------------|------------|------------|---------------------------------------|------------|
| ** **                                                                           | ** ** | **As of December 31,** | ** ** | ** ** | **As of December 31,** | ** ** |
| ** **                                                                           | ** ** | **2006**                              | ** ** | **2005**   | ** **                            | **2004**   | ** ** | **2003** | ** ** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                                           | ** ** | ** **                            | ** ** | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** | **(Unaudited)** | ** ** |
| ** **                                                                           | ** ** | **(in thousands)**               | ** ** | ** ** | **(in thousands)**               | ** ** |
| **Balance Sheet Data:**                                                              | ** ** |                                  | ** ** |       | ** **                            |       | ** ** |   |   | ** ** |   | ** ** |   | ** ** |
| Cash and cash  equivalents (3)                                                       |       | $                                     | 6,595      |       | $                                     | 11,041     |   | $ | 2,188 |   | $ | 22,043 |   |   | $ | 542 |   | $ | 1,006 |   |
| Other current assets                                                                 |       | 63,081                                |       | 23,692     |                                  | 5,892      |   | 1,971 |   |   | 710 |   | 447 |   |
| Oil and gas properties,  net of accumulated depreciation, depletion and amortization |       | 733,289                               |       | 239,293    |                                  | 95,381     |   | 52,307 |   |   | 12,829 |   | 12,831 |   |
| Property, plant and  equipment, net of accumulated depreciation                      |       | 20,754                                |       | 2,525      |                                  | 1,387      |   | 370 |   |   | 2,778 |   | 2,958 |   |
| Other assets                                                                         | ** ** | 92,589                                | ** ** | 4,373      | ** **                            | 577        | ** ** | 2,486 |   |   | 168 | ** ** | 208 | ** ** |
| Total assets                                                                         | ** ** | $                                     | 916,308    | ** ** | $                                     | 280,924    | ** ** | $ | 105,425 | ** ** | $ | 79,177 |   |   | $ | 17,027 | ** ** | $ | 17,450 | ** ** |
| Current liabilities                                                                  | ** ** | $                                     | 18,017     | ** ** | $                                     | 86,557     | ** ** | $ | 10,216 | ** ** | $ | 20,200 |   |   | $ | 3,468 | ** ** | $ | 3,498 | ** ** |
| Long-term debt                                                                       | ** ** | 428,237                               | ** ** | 207,695    | ** **                            | 72,750     | ** ** | 41,518 |   |   | 1,919 | ** ** | 2,686 | ** ** |
| Other long-term  liabilities                                                         | ** ** | 19,100                                | ** ** | 33,503     | ** **                            | 12,939     | ** ** | 3,123 |   |   | — | ** ** | — | ** ** |
| Unitholders’ capital  (deficit)                                                 | ** ** | 450,954                               | ** ** | (46,831    | **)**                                 | 9,520      | ** ** | 14,336 |   |   | 11,640 | ** ** | 11,266 | ** ** |
| Total  liabilities and unitholders’ capital                                     | ** ** | $                                     | 916,308    | ** ** | $                                     | 280,924    | ** ** | $ | 105,425 | ** ** | $ | 79,177 |   |   | $ | 17,027 | ** ** | $ | 17,450 | ** ** |

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(1)             During2005, we canceled (before their original settlement date) a portion ofout-of-the-money gas hedges and realized a loss of $38.3 million.

(2)             See Part II. Item 7.  “Management’s Discussionand Analysis of Financial Condition and Results of Operation - Non-GAAPFinancial Measure.”

(3)             In December 2003, we borrowed approximately $18.0million under our credit facility to pay the remaining purchase price for theWaco acquisition, which amount was paid to Waco in January 2004.

35

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**Item6.   ****Selected Financial Data - Continued**

**Summary Reserve and Operating Data**

The following tables show estimated net proved reserves, based onreserve reports prepared by DeGolyer and MacNaughton, our independent petroleumengineering firm for the year ended December 31, 2006, and certain summaryunaudited information with respect to our production and sales of oil andgas.  Schlumberger Data and ConsultingServices provided the estimated reserves at December 31, 2005 and2004.  This data should be read in conjunctionwith Part I.  Item 1.  “Business - Oil and Gas Data - ProvedReserves and Production and Price History,” Part I.  Item 1A. “Risk Factors,” and Part II.  Item7.  “Management’s Discussion and Analysisof Financial Condition and Results of Operation.”

 
|                                                            | ** ** | **As of December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                 | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Reserve Data:**                                          |       |                                  |       |   |   |   |   |   |   |
| Estimated net proved reserves:                             |       |                                  |       |   |   |   |   |   |   |
| Gas (Bcf)                                                  |       | 274.0                                 |       | 191.9 |   | 118.9 |   | 68.9 |   |
| Oil (MMBbls)                                               |       | 30.0                                  |       | 0.2 |   | 0.1 |   | 0.2 |   |
| Proved developed (Bcfe)                                    |       | 314.1                                 |       | 125.2 |   | 74.4 |   | 41.8 |   |
| Proved undeveloped (Bcfe)                                  |       | 140.0                                 |       | 68.0 |   | 45.4 |   | 28.0 |   |
| Proved developed reserves as  a % of total proved reserves |       | 69.2                                  | %          | 64.8 | % | 62.1 | % | 59.9 | % |
| **Standardized Measure (in millions)**(1)                  |       | $                                     | 552.3      |   | $ | 552.1 |   | $ | 215.0 |   | $ | 126.3 |   |
| **Representative Oil and Gas Prices:**                     |       |                                  |       |   |   |   |   |   |   |
| Gas — NYMEX Henry Hub  per MMBtu                      |       | $                                     | 5.64       |   | $ | 10.08 |   | $ | 6.18 |   | $ | 5.97 |   |
| Oil — NYMEX West Texas  Intermediate per Bbl          |       | $                                     | 61.05      |   | $ | 57.98 |   | $ | 43.36 |   | $ | 32.76 |   |

 
| ** **                                                  | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                  | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** | **Period from  March 14, 2003  (inception) -  December 31,  2003** | ** ** |
| **Production:**                                             |       |                                       |       |   |   |   |   |   |   |
| Gas production (MMcf)                                       |       | 8,599                                      |       | 4,720 |   | 3,110 |   | 304 |   |
| Oil production (MBbls)                                      |       | 370                                        |       | 20 |   | 10 |   | 1 |   |
| Total production (MMcfe)                                    |       | 10,818                                     |       | 4,839 |   | 3,112 |   | 492 |   |
| Average daily production (Mcfe/d)                           |       | 29,638                                     |       | 13,258 |   | 8,526 |   | 2,299 |   |
| **Weighted  Average Realized Prices**: (2)                  |       |                                       |       |   |   |   |   |   |   |
| Gas (Mcf)                                                   |       | $                                          | 9.79       |   | $ | 6.92 |   | $ | 5.73 |   | $ | 5.26 |   |
| Oil (Bbl) (3)                                               |       | $                                          | 58.68      |   | $ | 52.55 |   | $ | 37.83 |   | $ | 25.99 |   |
| Total (Mcfe)                                                |       | $                                          | 9.79       |   | $ | 6.97 |   | $ | 5.74 |   | $ | 5.25 |   |
| **Average  Unit Costs per Mcfe of Production  (Non-GAAP):** |       |                                       |       |   |   |   |   |   |   |
| Operating expenses                                          |       | $                                          | 1.67       |   | $ | 1.52 |   | $ | 1.53 |   | $ | 1.62 |   |
| General and administrative expenses (4)                     |       | $                                          | 0.63       |   | $ | 0.69 |   | $ | 0.48 |   | $ | 1.59 |   |
| Depreciation,  depletion and amortization                   |       | $                                          | 2.23       |   | $ | 1.51 |   | $ | 1.17 |   | $ | 1.14 |   |

----

(1)             The Standardized Measure does not include futureincome tax expenses because our reserves are owned by our subsidiary LinnEnergy Holdings, LLC, which is not subject to income taxes.  The Standardized Measure does not give effectto derivative transactions.  For a descriptionof our derivative transactions, see Part II. Item 7.  “Management’s Discussionand Analysis of Financial Condition and Results of Operation - Statements ofCash Flows.”

(2)       Includes the effect of realized gains and losses on oil and gasderivatives.

(3)             The majority of our oil production, which is inCalifornia, is sold pursuant to a long-term contract at 79% of NYMEX, and withgravity increase due to NGLs being mixed into the oil stream, prices realizedaverage approximately 82% of NYMEX.

(4)             This is a non-GAAP performance measure used by ourmanagement and is a quantitative measure used in the oil and gas industry.  The measure for the year endedDecember 31, 2006 excludes approximately $21.6 million of unit-basedcompensation expense and $2.0 million of bonuses paid to certain executiveofficers in connection with our IPO. General and administrative expenses including these amounts was $3.70per Mcfe for the year ended December 31, 2006.

 

36

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**Item7.   Management’s Discussion and Analysisof Financial Condition and Results of Operation**

*The following discussion and analysis should be readin conjunction with the “Selected Historical Consolidated Financial andOperating Data” and the financial statements and related notes includedelsewhere in this Annual Report on Form 10-K.  The following discussion containsforward-looking statements that reflect our future plans, estimates, beliefsand expected performance.  Theforward-looking statements are dependent upon events, risks and uncertaintiesthat may be outside our control.  Ouractual results could differ materially from those discussed in theseforward-looking statements.  Factors thatcould cause or contribute to such differences include, but are not limited to,market prices for oil and gas, production volumes, estimates of provedreserves, capital expenditures, economic and competitive conditions, regulatorychanges and other uncertainties, as well as those factors discussed below andelsewhere in this Annual Report on Form 10-K, particularly inPart I.  Item 1A.  “Risk Factors.”  In light of these risks, uncertainties andassumptions, the forward-looking events discussed may not occur.*

**Executive Summary**

We are anindependent oil and gas company focused on the development and acquisition oflong-lived properties in the United States. Our Company was formed in March 2003 and in January 2006, we completedour IPO of 12,450,000 units at a price of $21.00 per unit, for net proceedsafter underwriting discounts and offering expenses of $238.8 million (see “Statements of Cash Flows — Financing Activities”below for additional details).  InOctober 2006, the Company privately placed 9,185,965 Class B units at a priceof $20.55 per unit, and 5,534,687 units at a price of $21.00 per unit, or atotal of 14,720,652 units at a blended price of $20.72 per unit, for aggregategross proceeds of $305.0 million. Proceeds, net of expenses of approximately $0.3 million, from the ClassB Private Placement were used to repay indebtedness.  The Class B units were subsequentlyconverted into units on a one-for-one basis per unitholder vote in January2007.  In February 2007, the Companyprivately placed 7,465,946 Class C units at a price of $25.06 per unit and 6,650,144units at a price of $26.00 per unit, or a total of 14,116,090 units at ablended price of $25.50 per unit, for aggregate gross proceeds of approximately$360.0 million, which were used to partially finance the Stallion acquisitionand the acquisition of certain gas properties in West Virginia (see Note 2 inNotes to Consolidated Financial Statements). See “Private Placement — Class B Units” and “Private Placement —Class C Units” in “Liquidity and Capital Resources” below for additionaldetails.

Our goal is to providestability and growth in distributions to our unitholders through continuedsuccessful drilling and, acquisitions,increasing production of existing wells and pursuing operational and administrativeefficiencies.  Our properties and our oil and gas reserves are currently located infour core areas:

·                  Appalachian Basin, which includes West Virginia,Pennsylvania, New York and Virginia;

·                  Western, which includes the Brea Olinda Field ofthe Los Angeles Basin in California;

·                  Mid-Continent, which includes the Sooner Trend ofnorth central Oklahoma; and

·                  Texas Panhandle, which includes the Texas portionof the Hugoton-Panhandle Field.

During the year endedDecember 31, 2006, we completed five acquisitions of oil and gasproperties and related gathering and pipeline assets for an aggregate purchaseprice of approximately $454.9 million, with total proved reserves of 263.7Bcfe, or an acquisition cost of approximately $1.72 per Mcfe.  As of December 31, 2006, sinceinception, we completed 14 acquisitions ofoil and gas properties and related gathering and pipeline assets for anaggregate purchase price of approximately $656.4 million, with total provedreserves of approximately 441.5 Bcfe, or an acquisition cost of approximately$1.49 per Mcfe.  As part of ourbusiness strategy, we continually evaluate opportunities to acquire additionaloil and gas properties that complement our asset profile.  See “Acquisitions” below for details aboutour most recent acquisitions in Texas and West Virginia, which are not includedin our reserves at December 31, 2006.

Our proved reserves atDecember 31, 2006, which exclude our three acquisitions in the firstquarter of 2007, were 454.1 Bcfe, of which approximately 60.3% were gas and39.7% were oil.  Approximately 69.2% wereclassified as proved developed, with a total proved Standardized Measure valueof $552.3 million.  At December 31, 2005, we had 193.2 Bcfe ofestimated net proved reserves with a Standardized Measure of $552.1million.  Our December 31, 2006 and2005 Standardized Measures were determined using a price of $5.64 and $10.08per Mcf of gas, respectively, and $61.05 and $57.98 per Bbl of oil,respectively.  Our production wasapproximately 79.5% gas and 20.5% oil for the year ended December 31,2006.  During 2005, oil accounted forless than 3% of our production.

At December 31,2006, we operated 2,683, or 73.3%, of our 3,659 productive wells.  Our average proved reserves-to-productionratio, or average reserve life, is approximately 29.5 years, based on ourDecember 31, 2006 reserve report and annualized production for the fourthquarter ended December 31, 2006.

37

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**Item 7.   Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

***Acquisitions***

The Company made two significant acquisitions in thethird quarter of 2006.  The Companyacquired certain affiliated entities of Blacksand, located in the Los AngelesBasin, for an aggregate purchase price of approximately $301.0 million andcertain Mid-Continent Kaiser-Francis Assets, located in Oklahoma, for anaggregate purchase price of approximately $126.4 million.  Results of Blacksand and the Kaiser-FrancisAssets are included in the consolidated results of the Company beginning August1, 2006 and September 1, 2006, respectively. See Note 2 in Notes to Consolidated Financial Statements for furtherdetails about the Blacksand and Kaiser-Francis acquisitions.  Thefollowing table provides a summary of the oil and gas properties we haveacquired from inception through the date of this report:
| Year       | ** ** | **# of  Acquisitions** | ** ** | **Gross Wells** | ** ** | **Location**                                       | ** ** | **Aggregate  Contract  Price** |
|------------|------------|------------------------|------------|-----------------|------------|----------------------------------------------------|------------|--------------------------------|
| ** ** | ** ** | ** **             | ** ** | ** **      | ** ** | ** **                                         | ** ** | **(in millions)**              |
|       |       |                   |       |            |       |                                               |       |                           |
| 2003       |       | 4                      |       | 498             |       | West Virginia, Virginia, New York and Pennsylvania |       | $52.0                          |
| 2004       |       | 2                      |       | 698             |       | Pennsylvania                                       |       | 25.9                           |
| 2005       |       | 3                      |       | 718             |       | West Virginia and Virginia                         |       | 124.5                          |
| 2006       |       | 5                      |       | 1,430           |       | West Virginia, California and Oklahoma             |       | 451.7                          |
| 2007       |       | 3                      |       | 902             |       | West Virginia and Texas                            |       | 453.9                          |
|       |       | 17                     |       | 4,246           |       |                                               |       | $1,108.0                       |

 

Ouracquisitions were financed with a combination of private placements of ourunits, proceeds from bank borrowings and cash flow from operations.  Our activities are focused on evaluating anddeveloping our asset base, increasing our acreage positions and evaluatingpotential acquisitions.  Because of ourrapid growth through acquisitions and development of our properties, ourhistorical results of operations and period-to-period comparisons of theseresults and certain financial data may not be meaningful or indicative offuture results.

InFebruary 2007, the Company completed the acquisition of certain oil and gasproperties and related assets in the Texas Panhandle from Cavallo Energy, LP,acting through its general partner, Stallion for a contract price of $415.0million, subject to customary post-closing adjustments (see Note 2 in Notes toConsolidated Financial Statements for additional details).  In addition, in January 2007, the Companycompleted two acquisitions of certain gas properties located in the AppalachianBasin of West Virginia for an aggregate contract price of $39.0 million,subject to customary post-closing adjustments. In connection with these acquisitions, the Company amended its creditfacility to increase the borrowing base from $480.0 million to $725.0 million.  See “Credit Facility” below for additionaldetails.

***Drilling***

The following table setsforth information, as of December 31, 2006, relating to our drillinglocations and net acres of leasehold interests in each of our three core areas.

 

|                                | ** ** | **Appalachian  Basin** | ** ** | **Western** | ** ** | **Mid-Continent** | ** ** | **Total** | ** ** |
|--------------------------------|------------|------------------------|------------|-------------|------------|-------------------|------------|-----------|------------|
| Proved  undeveloped            |       | 581                    |       | 2           |       | 133               |       | 716       |       |
| Other locations                |       | 538                    |       | —      |       | —            |       | 538       |       |
| Total drilling locations       |       | 1,119                  |       | 2           |       | 133               |       | 1,254     |       |
| Leasehold interests-net  acres |       | 174,000                |       | 810         |       | 53,896            |       | 228,706   |       |

 

We utilize the successful efforts method of accounting for our oil andgas properties.  Leasehold costs arecapitalized when incurred.  Unprovedproperties are assessed periodically within specific geographic areas andimpairments are charged to expense. Geological and geophysical expenses and delay rentals are charged toexpense as incurred.  Drilling costs arecapitalized, but charged to expense if the well is determined to beunsuccessful.  We carry the costs of anexploratory well as an asset if the well finds a sufficient quantity ofreserves to justify its capitalization as a producing well as long as we aremaking sufficient progress assessing the reserves and the economic andoperating viability of the project.

38

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**Item7.   Management’s Discussion and Analysisof Financial Condition and Results of Operation - Continued**

Higher oil and gas priceshave led to higher demand for drilling rigs, operating personnel and fieldsupplies and services and have caused increases in the costs of those goods andservices.  The Company performs certainactivities in connection with its drilling of oil and gas wells, which includespreparing and clearing well sites, providing drilling engineers, roustaboutsand other personnel necessary for drilling. During 2006, the Company took delivery of its first two drilling rigs,with an additional rig delivered in the first quarter of 2007, which willreduce reliance on contract rigs.  In thethird quarter of 2006, the Company began, for the first time, operating its owndrilling rigs staffed with Company personnel. Given the inherent volatility of oil and gas prices, which areinfluenced by many factors beyond our control, we plan our activities andbudget based on conservative sales price assumptions, which are lower than theaverage sales prices ultimately realized. We focus our efforts on increasing oil and gas reserves and productionwhile controlling costs at a level that is appropriate for long-termoperations.  Our future cash flow fromoperations is dependent on our ability to manage our overall cost structure.

We face the challenge ofnatural production declines.  As initialreservoir pressures are depleted, oil or gas production from a given welldecreases.  We attempt to overcome thisnatural decline by drilling to find additional reserves and acquiring morereserves than we produce.  Our futuregrowth will depend on our ability to continue to add reserves in excess ofproduction.  We will maintain our focuson adding reserves through drilling and acquisitions as well as the costsnecessary to produce such reserves.  Ourability to add reserves through drilling is dependent on our capital resourcesand can be limited by many factors, including our ability to timely obtaindrilling permits and regulatory approvals.

***Operations***

Our revenues are highlysensitive to changes in oil and gas prices and levels of production.  As of December 31, 2006, we have hedgeda significant portion of our expected production through 2011 using oil and gasderivatives, which allows us to mitigate, but not eliminate, commodity pricerisk.  Our expected increase in levels ofproduction as a result of the anticipated drilling of over 250 wells during2007 is dependent on our ability to quickly and efficiently bring the newlydrilled wells online.  Any delays in drilling,completion or connection to gathering lines of our new wells will negativelyimpact the rate of increase in our production, which may have an adverse effecton our revenues and as a result, cash available for distribution.  We continuously conduct financial sensitivityanalyses to assess the effect of changes in pricing and production.  These analyses allow us to determine howchanges in oil and gas prices will affect the ability to drill additional wellsand to meet future financial obligations. Further, the financial analyses allow us to monitor any impact suchchanges in oil and gas prices may have on the value of our proved reserves andtheir impact, if any, on any redetermination of the borrowing base under ourcredit facility.

Our revenue, cash flowfrom operations and future growth depend substantially on factors beyond ourcontrol, such as economic, political and regulatory developments andcompetition from other producers.  Oiland gas prices historically have been volatile and may fluctuate widely in thefuture.  Sustained periods of low pricesfor oil or gas could materially and adversely affect our financial position,our results of operations, the quantities of oil and gas reserves that we caneconomically produce and our access to capital.

***Production andOperating Costs Reporting***

We strive to increase ourproduction levels to maximize our revenue and cash available fordistribution.  Additionally, wecontinuously monitor our operations to ensure that we are incurring operatingcosts at the lowest possible level. Accordingly, we analyze our production and operating costs per well todetermine if any wells should be shut in or sold.

***Land and LeaseTracking System***

As a significant amountof our growth is dependent on drilling new wells, we continuously monitor ourlease agreements and our drilling locations to avoid delays.  Our monitoring system matches our leaseagreements to existing wells and sites for future development, allowingmanagement to make real time decisions on which acreage to develop and at whatpoint in time.  We continually seek toacquire new lease positions to increase potential drilling locations.

39

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**Item 7.   Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

**Results of Operations - Year EndedDecember 31, 2006 Compared to Year Ended December 31, 2005**

The following tables set forth selected financial and operating data forthe years indicated:

 
| ** **                                    | ** ** | **Year Ended December 31,** | ** ** | ** ** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------|------------|------------|------------|
| ** **                                    | ** ** | **2006**                                   | ** ** | **2005**   | ** ** | **Variance** | ** ** |
| ** **                                    | ** ** | **(in thousands)**                    | ** ** |
| **Revenues:**                                 |       |                                       |       |       |       |   |   |
| Gas sales                                     |       | $                                          | 61,641     |       | $          | 43,594 |   | $ | 18,047 |   |
| Oil sales                                     |       | 18,752                                     |       | 1,051      |       | 17,701 |   |
| Total oil and gas sales                       |       | 80,393                                     |       | 44,645     |       | 35,748 |   |
| Gain (loss) on oil and gas derivatives (1)    |       | 103,308                                    |       | (76,193    | )          | 179,501 |   |
| Natural gas marketing revenues                |       | 5,598                                      |       | 4,722      |       | 876 |   |
| Other revenues                                |       | 1,759                                      |       | 345        |       | 1,414 |   |
| Total revenues                                |       | $                                          | 191,058    |       | $          | (26,481 | ) | $ | 217,539 |   |
| **Expenses:**                                 |       |                                       |       |       |       |   |   |
| Operating expenses                            |       | $                                          | 18,099     |       | $          | 7,356 |   | $ | 10,743 |   |
| Natural gas marketing expenses                |       | 4,862                                      |       | 4,401      |       | 461 |   |
| General and administrative expenses           |       | 39,993                                     |       | 3,332      |       | 36,661 |   |
| Depreciation, depletion and amortization      |       | 24,173                                     |       | 7,294      |       | 16,879 |   |
| Total expenses                                |       | $                                          | 87,127     |       | $          | 22,383 |   | $ | 64,744 |   |
| **Other  Income and (Expenses):**             |       |                                       |       |       |       |   |   |
| Interest  expense, net of amounts capitalized |       | $                                          | (25,494    | )          | $          | (7,040 | ) | $ | (18,454 | ) |

 
| ** **                                                 | ** ** | **Year Ended December 31,** | ** ** | **Percentage  Increase** | ** ** |
|------------------------------------------------------------|------------|--------------------------------------------|------------|--------------------------|------------|
| ** **                                                 | ** ** | **2006**                                   | ** ** | **2005**                 | ** ** | **(Decrease)** | ** ** |
| **Production:**                                            |       |                                       |       |                     |       |   |   |
| Gas production (MMcf)                                      |       | 8,599                                      |       | 4,720                    |       | 82.2 | % |
| Oil production (MBbls)                                     |       | 370                                        |       | 20                       |       | 1750.0 | % |
| Total production (MMcfe)                                   |       | 10,818                                     |       | 4,839                    |       | 123.6 | % |
| Average daily production (Mcfe/d)                          |       | 29,638                                     |       | 13,258                   |       | 123.5 | % |
| ** **                                                 |       |                                       |       |                     |       |   |   |
| **Weighted  Average Realized Prices:**(2)                  |       |                                       |       |                     |       |   |   |
| Gas (Mcf)                                                  |       | $                                          | 9.79       |                     | $          | 6.92 |   | 41.5 | % |
| Oil (Bbl) (3)                                              |       | $                                          | 58.68      |                     | $          | 52.55 |   | 11.7 | % |
| Total (Mcfe)                                               |       | $                                          | 9.79       |                     | $          | 6.97 |   | 40.5 | % |
| ** **                                                 |       |                                       |       |                     |       |   |   |
| **Average  Unit Costs per Mcfe of Production (Non-GAAP):** |       |                                       |       |                     |       |   |   |
| Operating expenses                                         |       | $                                          | 1.67       |                     | $          | 1.52 |   | 9.9 | % |
| General and administrative expenses (4)                    |       | $                                          | 0.63       |                     | $          | 0.69 |   | (8.7 | )% |
| Depreciation,  depletion and amortization                  |       | $                                          | 2.23       |                     | $          | 1.51 |   | 47.7 | % |

----

(1)             During the year endedDecember 31, 2005, we canceled (before their original settlement date) aportion of out-of-the-money gas swaps and realized a loss of $38.3million.  We subsequently hedged similarvolumes at higher prices.

(2)       Includes the effect of realized gains of $25.5million and realized losses of $13.1 million (excludes the $38.3 million lossnoted above) on oil and gas derivatives for the years ended December 31,2006 and 2005, respectively.

(3)       The majority of our oil production, which is inCalifornia, is sold pursuant to a long-term contract at 79% of NYMEX, and withgravity increase due to NGLs being mixed into the oil stream, prices realizedaverage approximately 82% of NYMEX.

(4)       This is a non-GAAP performance measure used by ourmanagement and is a quantitative measure used in the oil and gas industry.  The measure for the year endedDecember 31, 2006 excludes approximately $21.6 million of unit-basedcompensation expense and $2.0 million of bonuses paid to certain executiveofficers in connection with our IPO. General and administrative expenses including these amounts was $3.70per Mcfe for the year ended December 31, 2006.

40

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**Item 7.****         Management’s Discussionand Analysis of Financial Condition and Results of Operation - Continued**

***Revenues***

Oil and gas sales increased to approximately $80.4 million for the yearended December 31, 2006, from $44.6 million for the year endedDecember 31, 2005.

The increase in revenue from oil and gas sales was primarilyattributable to increased production. Total production increased to 10,818 MMcfe during the year endedDecember 31, 2006, from 4,839 MMcfe during the year endedDecember 31, 2005.  Oil productionincreased to 370 MBbls during the year ended December 31, 2006, from 20MBbls during the year ended December 2005, primarily due to the acquisition ofBlacksand in August 2006.  Gas productionincreased to 8,599 MMcf during the year ended December 31, 2006, from4,720 MMcf during the year ended December 31, 2005.  The increase in gas production was due to thedrilling of new wells and production added by the acquisitions of oil and gasproperties during 2006 and 2005.  Thecompany drilled 159 wells during 2006 and 110 wells in 2005.

***Hedging Activities***

During the year ended December 31, 2006, we enteredinto commodity pricing derivative contracts for approximately 108% of our gasproduction and 50% of our oil production, which resulted in revenues that were$25.5 million greater than we would have achieved at unhedged prices.  During the year ended December 31, 2005,we entered into commodity pricing derivative contracts for approximately 84% ofour oil and gas production, which resulted in revenues that were $13.1 millionless than we would have achieved at unhedged prices.  During the year ended December 31, 2005,we canceled (before their original settlement date) a portion of out-of-the-moneygas hedges and realized a loss of $38.3 million, then subsequently hedgedsimilar volumes at higher prices. Unrealized gain on derivatives in the amount of $77.8 million for theyear ended December 31, 2006 and unrealized losses on derivatives in the amountsof $24.8 million for the year ended December 31, 2005 were alsorecorded.  Unrealized gains and lossesresult from oil and gas price fluctuations as compared to the settlement priceon the derivative.

***Expenses***

Operating expenses consist of lease operating expenses, labor, fieldoffice rent, vehicle expenses, supervision, transportation, minor maintenance,tools and supplies, severance and ad valorem taxes and other customarycharges.  Severance taxes are a functionof volumes and revenues generated from production.  Ad valorem taxes vary by state/county and arebased on the value of our reserves.  Weassess our operating expenses by monitoring the expenses in relation to theamount of production and the number of wells operated.  Operating expenses increased to $18.1 millionfor the year ended December 31, 2006, from $7.4 million for the year endedDecember 31, 2005, due to the increase in the number of producing wells asa result of the acquisitions completed in both 2006 and 2005 and the drillingof 159 wells during 2006 and 110 wells during 2005.  From inception through December 31,2006, we have drilled 359 wells and acquired 3,344 wells.

Generaland administrative expenses include the costs of our employees and executiveofficers, related benefits, office leases, professional fees and other costsnot directly associated with field operations. We monitor general and administrative expenses in relation to the amountof production and the number of wells operated. General and administrative expenses increased to $40.0 million, for theyear ended December 31, 2006, from $3.3 million for the year endedDecember 31, 2005.  Theincrease in general and administrative expenses was due to the recognition ofunit-based compensation expense of $21.6 million during the year endedDecember 31, 2006, compared to none during the year endedDecember 31, 2005.  In addition,acquisition costs that are not eligible for capitalization, including internaland indirect costs for completed acquisitions, as well as direct costsassociated with acquisition efforts that have not reached fruition, contributedto the increase.  Costs to support ourrapidly growing operations and position the Company for future growth includeincreasing our staffing levels to manage the 359 wells drilled and 3,344 wellsacquired from inception in 2003 through December 31, 2006, recruiting keymanagement team members and performing the functions associated with being apublic company, which totaled approximately $6.1 million in 2006 (the year ofour IPO).  General and administrativeexpenses are presented net of approximately $1.1 million and $1.2 millionduring the year ended December 31, 2006 and 2005, respectively, whichrepresent expense reimbursements from other working interest owners.

Depreciation, depletionand amortization increased to $24.2 million for the year endedDecember 31, 2006, from $7.3 million for the year ended December 31,2005.  Of this increase, approximately$4.8 million was as a result of depletion related to the properties in theBlacksand and Kaiser-Francis acquisitions in the third quarter of 2006.  In addition, the depletion rate for our oiland gas properties in the Appalachia Basin increased 37.4% in the fourthquarter of 2006, due to a downward revision of our estimated reserves from theprior year.  The Company also recorded $1.0million of impairments during the year ended December 31, 2006.  During the years ended December 31, 2006and 2005, the Company capitalized approximately

41

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**Item 7.   Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

$8.5 million and$1.6 million, respectively, of costs related to drilling for specificactivities related to drilling its wells, which included site preparation,drilling labor, meter installation, pipeline connection and sitereclamation.  Capitalized drilling costsincreased compared to the prior year due to the Company’s purchase andplacement of its own drilling rigs into service during the third quarter of2006.  The Company began, for the firsttime, operating its own drilling rigs, staffed with Company personnel.  Company personnel also perform activitiesusing leased equipment, and did so prior to the purchase of its own rigs.  The aggregate amount spent on drilling and developmentfor the years ended December 31, 2006 and 2005 was approximately $47.0million and $27.1 million, respectively.

Interest and financingincome (expense) increased to a net expense of $25.5 million for the yearended December 31, 2006, compared to a net expense of $7.0 million for theyear ended December 31, 2005, primarily due to increased debt levelsassociated with acquisitions and drilling. Cash payments for interest increased to $24.1 million for the year endedDecember 31, 2006, from $6.5 million for the year ended December 31,2005.  Our interest rate swaps were notdesignated as hedges under SFAS 133, even though they reduce our exposure tochanges in interest rates.  Therefore,the changes in fair values of these instruments were recorded as gains ofapproximately $82,000 and $1.0 million for the years ended December 31,2006 and 2005, respectively.  Theseamounts are non-cash gains.

Income tax was a benefitof approximately $3.4 million for the year ended December 31, 2006.  Income tax expense was approximately $74,000for the year ended December 31, 2005. Linn is an LLC, and is taxed substantially as a partnership; however,the Company’s taxable subsidiaries generated net operating losses for the yearended December 31, 2006.  The increasein realizable net operating loss income tax benefit currently realizable wasthe result of a 2006 backlog of expenses reported by the taxable subsidiarieson behalf of the consolidated Company. Management has determined such losses will be realized in 2007 since thestrategy of the corporate structure for the taxable subsidiaries is to recovercosts rather than generate significant profits and the forecast of lossgeneration is not expected to turn around in the foreseeable future.

42

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**Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

**Results ofOperations - Year Ended December 31, 2005 Compared to Year EndedDecember 31, 2004**

The following tables set forth selected financial and operating data forthe years indicated:
| ** **                                    | ** ** | **Year Ended December 31,** | ** ** | ** ** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------|------------|------------|------------|
| ** **                                    | ** ** | **2005**                                   | ** ** | **2004**   | ** ** | **Variance** | ** ** |
| ** **                                    | ** ** | **(in thousands)**                    | ** ** |
| **Revenues:**                                 |       |                                       |       |       |       |   |   |
| Gas sales                                     |       | $                                          | 43,594     |       | $          | 19,129 |   | $ | 24,465 |   |
| Oil sales                                     |       | 1,051                                      |       | 373        |       | 678 |   |
| Total oil and  gas sales                      |       | 44,645                                     |       | 19,502     |       | 25,143 |   |
| Loss on oil and  gas derivatives (1)          |       | (76,193                                    | )          | (11,004    | )          | (65,189 | ) |
| Natural gas  marketing revenues               |       | 4,722                                      |       | 520        |       | 4,202 |   |
| Other revenues                                |       | 345                                        |       | 160        |       | 185 |   |
| Total revenue                                 |       | $                                          | (26,481    | )          | $          | 9,178 |   | $ | (35,659 | ) |
| **Expenses:**                                 |       |                                       |       |       |       |   |   |
| Operating  expenses                           |       | $                                          | 7,356      |       | $          | 4,756 |   | $ | 2,600 |   |
| Natural gas  marketing expenses               |       | 4,401                                      |       | 482        |       | 3,919 |   |
| General and  administrative expenses          |       | 3,332                                      |       | 1,488      |       | 1,844 |   |
| Depreciation,  depletion and amortization     |       | 7,294                                      |       | 3,656      |       | 3,638 |   |
| Total expenses                                |       | $                                          | 22,383     |       | $          | 10,382 |   | $ | 12,001 |   |
| **Other Income and (Expenses):**              |       |                                       |       |       |       |   |   |
| Interest expense, net  of amounts capitalized |       | $                                          | (7,040     | )          | $          | (3,530 | ) | $ | (3,510 | ) |

 
| ** **                                                 | ** ** | **Year Ended December 31,** | ** ** | **Percentage  Increase** | ** ** |
|------------------------------------------------------------|------------|--------------------------------------------|------------|--------------------------|------------|
| ** **                                                 | ** ** | **2005**                                   | ** ** | **2004**                 | ** ** | **(Decrease)** | ** ** |
| **Production:**                                            |       |                                       |       |                     |       |   |   |
| Gas production  (MMcf)                                     |       | 4,720                                      |       | 3,502                    |       | 54.7 | % |
| Oil production  (MBbls)                                    |       | 20                                         |       | 10                       |       | 100.0 | % |
| Total production  (MMcfe)                                  |       | 4,839                                      |       | 3,112                    |       | 55.5 | % |
| Average daily  production (Mcfe/d)                         |       | 13,258                                     |       | 8,526                    |       | 55.5 | % |
| ** **                                                 |       |                                       |       |                     |       |   |   |
| **Weighted Average Realized  Prices:****(2)**              |       |                                       |       |                     |       |   |   |
| Gas (Mcf)                                                  |       | $                                          | 6.92       |                     | $          | 5.73 |   | 20.8 | % |
| Oil (Bbl)                                                  |       | $                                          | 52.55      |                     | $          | 37.83 |   | 38.9 | % |
| Total (Mcfe)                                               |       | $                                          | 6.97       |                     | $          | 5.74 |   | 21.4 | % |
| ** **                                                 |       |                                       |       |                     |       |   |   |
| **Average Unit Costs per Mcfe of  Production (Non-GAAP):** |       |                                       |       |                     |       |   |   |
| Operating  expenses                                        |       | $                                          | 1.52       |                     | $          | 1.53 |   | (0.7 | )% |
| General and  administrative expenses                       |       | $                                          | 0.69       |                     | $          | 0.48 |   | 43.8 | % |
| Depreciation, depletion  and amortization                  |       | $                                          | 1.51       |                     | $          | 1.17 |   | 29.1 | % |

----

(1)                Duringthe year ended December 31, 2005, we canceled (before their originalsettlement date) a portion of out-of-the-money gas swaps and realized a loss of$38.3 million.  We subsequently hedgedsimilar volumes at higher prices.

(2)                Includesthe effect of realized losses of $13.1 million (excludes the $38.3 million lossnoted above) and $2.2 million on oil and gas derivatives for the years endedDecember 31, 2005 and 2004, respectively.

43

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**Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

***Revenues***

Oil and gas sales increased to approximately $44.6 million for the yearended December 31, 2005, from $19.5 million for the year endedDecember 31, 2004.

The increase in revenue from oil and gas sales was attributableprimarily to increased production.  Totalproduction increased to 4,839 MMcfe during the year ended December 31,2005, from 3,112 MMcfe during the year ended December 31, 2004, due to thedrilling of new wells and production added by the acquisitions of oil and gasproperties during 2005 and 2004.  TheCompany drilled 110 wells during 2005 compared to 90 wells in 2004.  In addition to the increase in production,the average gas sales price increased during the year ended December 31,2005 compared to the year ended December 31, 2004.

***Hedging Activities***

During the year ended December 31, 2005, we enteredinto commodity pricing derivative contracts for approximately 84% of our oiland gas production, which resulted in revenues that were $13.1 million lessthan we would have achieved at unhedged prices. During the year ended December 31, 2004, we entered into commoditypricing derivative contracts for approximately 72% of our oil and gasproduction, which resulted in revenues that were $2.2 million less than wewould have achieved at unhedged prices. During the year ended December 31, 2005, we canceled (before theiroriginal settlement date) a portion of out-of-the-money gas hedges and realizeda loss of $38.3 million, then subsequently hedged similar volumes at higherprices.  Unrealized losses on derivativesin the amounts of $24.8 million and $8.8 million in 2005 and 2004,respectively, were also recorded. Unrealized losses result from oil and gas price fluctuations as comparedto the settlement price on the derivative.

***Expenses***

Operating expenses consist of lease operating expenses, labor, fieldoffice rent, vehicle expenses, supervision, transportation, minor maintenance,tools and supplies, severance and ad valorem taxes and other customarycharges.  Severance taxes are a functionof volumes and revenues generated from production.  Ad valorem taxes vary by state/county and arebased on the value of our reserves.  Weassess our operating expenses by monitoring the expenses in relation to theamount of production and the number of wells operated.  Operating expenses increased to $7.4 millionfor the year ended December 31, 2005, from $4.8 million for the year endedDecember 31, 2004, due to the increase in the number of producing wells asa result of the acquisitions completed in both 2005 and 2004 and the drillingof 110 wells during 2005 and 90 wells during 2004.

Generaland administrative expenses include the costs of our employees and executiveofficers, related benefits, office leases, professional fees and other costsnot directly associated with field operations. We monitor general and administrative expenses in relation to the amountof production and the number of wells operated. General and administrative expenses increased to $3.3 million for theyear ended December 31, 2005, from $1.5 million for the year endedDecember 31, 2004.  Generaland administrative expenses are presented net of approximately $1.2 million and$0.6 million during the years ended December 31, 2005 and 2004,respectively, which represent expense reimbursements from other workinginterest owners.  In addition,acquisition costs that are not eligible for capitalization, including internaland indirect costs for completed acquisitions, as well as direct costsassociated with due diligence for acquisitions that did not reach fruition,contributed to the increase.  Costs tosupport our rapidly growing operations, including increasing our staffing levelto manage the additional wells acquired and drilled in 2005 and 2004, and toperform the functions associated with preparation to become a public companyalso contributed to the increase.

Depreciation, depletionand amortization increased to $7.3 million for the year ended December 31,2005, from $3.7 million for the year ended December 31, 2004, due to theincrease in the number of wells as a result of the acquisitions completed andthe wells drilled in 2005 and 2004, as noted above.  Additionally, during the years endedDecember 31, 2005 and 2004, the Company capitalized approximately $1.6million and $0.2 million, respectively, of costs related to drilling.

Interest and financingincome (expense) increased to a net expense of $7.0 million for the yearended December 31, 2005, compared to a net expense of $3.5 million for theyear ended December 31, 2004, primarily due to increased debt levelsassociated with acquisitions and drilling. Cash payments for interest increased to $6.5 million for the year endedDecember 31, 2005, from $2.0 million for the year ended December 31,2004.  Our interest rate swaps were notdesignated as hedges under SFAS 133, even though they reduce our exposure tochanges in interest rates.  Therefore,the changes in fair values of these instruments were recorded as a gain of $1.0million and a loss of approximately $1.3 million for the years endedDecember 31, 2005 and 2004, respectively. These amounts are non-cash gains and losses.

44

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**Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

Income tax expense wasapproximately $74,000 for the year ended December 31, 2005, compared to $0in 2004.  Linn is an LLC, and is taxedsubstantially as a partnership.

**Liquidity and Capital Resources**

Weutilize private placements of our units, proceeds from bank borrowings and cashflow from operations for our capital resources and liquidity.  To date, our primary use of capital has beenfor the acquisition and development of oil and gas properties.  As we pursue growth, we continually monitorthe capital resources available to us to meet our future financial obligationsand planned capital expenditures.  Ourfuture success in growing reserves and production will be highly dependent onthe capital resources available to us and our success in drilling for oracquiring additional reserves.  Weactively review acquisition opportunities on an ongoing basis.  If we were to make significant additionalacquisitions for cash, we would need to borrow additional amounts under ourcredit facility, if available, or obtain additional debt or equityfinancing.  Our credit facility imposescertain restrictions on our ability to obtain additional debt financing.  Based upon our current expectations, webelieve our liquidity and capital resources will be sufficient for the conductof our business and operations.

***Statements ofCash Flows — Operating Activities***

At December 31, 2006, we had cash and cash equivalents of $6.6million compared to $11.0 million at December 31, 2005.

Cash used in operating activities was $ 6.8 million and$29.5 million for the years ended December 31, 2006 and 2005,respectively.  The decrease in cash usedby operating activities was due to the increase in net income, which was $78.2million for the year ended December 31, 2006, compared to a net loss of$56.4 million for the year ended December 31, 2005.  See “Results of Operations” above for detailabout the increase in components of net income. In addition, the Company paid premiums of approximately $49.8 millionfor its oil and gas derivatives, which is reported as a use of operating cash.

Our cash flow from operations is subject to many variables, the mostsignificant of which is the volatility of oil and gas prices.  Oil and gas prices are determined primarilyby prevailing market conditions, which are dependent on regional and worldwideeconomic activity, weather and other factors beyond our control.  Our future cash flow from operations willdepend on our ability to maintain and increase production through our drillingprogram and acquisitions, as well as the prices of oil and gas.

We enter into derivative arrangements to reduce the impact of oil andgas volatility on our operations. Currently, we use fixed price swaps and puts to reduce our exposure tothe volatility in oil and gas prices.

By removing the price volatility from a significant portion of our oiland gas production, we have mitigated, but not eliminated, the potentialeffects of changing prices on our cash flow from operations for thoseperiods.  While mitigating negativeeffects of falling commodity prices, these derivative contracts also limit thebenefits we would receive from increases in commodity prices.  It is our policy to enter into derivativecontracts only with counterparties that are major, creditworthy financialinstitutions deemed by management as competent and competitive market makers.

45

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**Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

The following tables summarize, as of February 28, 2007, and for theperiods indicated, our derivatives in place through December 31,2011.  Currently, we use fixed priceswaps and puts to manage commodity prices. The gas transactions are settled based upon the closing NYMEX futureprice of gas on the settlement date, which occurs on the third day of theproduction month proceeding the production month.  The oil transactions are settled based uponthe average daily NYMEX price of light oil and settlement occurs on the finalday of the production month.
| ** **               | ** ** | **March 1-  December 31,  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** |
|--------------------------|------------|--------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas  Positions**       | ** ** | ** **                                 | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Fixed Price  Swaps:      |       |                                       |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MMBtu)    |       | 6,673                                      |       | 10,264         |       | 10,405         |       | 8,520          |       | 7,800          |       |
| Average Price ($/MMBtu)  |       | $                                          | 8.73       |           | $          | 8.37           |       | $              | 7.73       |           | $          | 7.20 |   | $ | 7.20 |   |
| Puts:                    |       |                                       |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MMBtu)    |       | 7,250                                      |       | 7,053          |       | 6,960          |       | 6,960          |       | 6,960          |       |
| Average Price ($/MMBtu)  |       | $                                          | 8.18       |           | $          | 8.07           |       | $              | 7.50       |           | $          | 7.50 |   | $ | 7.50 |   |
| Total:                   |       |                                       |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MMBtu)    |       | 13,923                                     |       | 17,317         |       | 17,365         |       | 15,480         |       | 14,760         |       |
| Average Price  ($/MMBtu) |       | $                                          | 8.44       |           | $          | 8.25           |       | $              | 7.64       |           | $          | 7.34 |   | $ | 7.34 |   |

 
| ** **             | ** ** | **March 1-  December 31,  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** |
|------------------------|------------|--------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Oil  Positions**     | ** ** | ** **                                 |       |           |       |           |       |           |       |           |       |
| Fixed Price  Swaps:    | ** ** | ** **                                 |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)  |       | 417                                        |       | 560            |       | 580            |       | 550            |       | 525            |       |
| Average Price ($/Bbl)  |       | $                                          | 75.83      |           | $          | 74.31          |       | $              | 73.87      |           | $          | 74.54 |   | $ | 61.58 |   |
| Puts:                  |       |                                       |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)  |       | 1,250                                      |       | 1,550          |       | 1,550          |       | 1,700          |       | 1,750          |       |
| Average Price ($/Bbl)  |       | $                                          | 66.33      |           | $          | 66.29          |       | $              | 66.29      |           | $          | 66.18 |   | $ | 65.00 |   |
| Total:                 |       |                                       |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)  |       | 1,667                                      |       | 2,110          |       | 2,130          |       | 2,250          |       | 2,275          |       |
| Average Price  ($/Bbl) |       | $                                          | 68.71      |           | $          | 68.42          |       | $              | 68.35      |           | $          | 68.22 |   | $ | 64.21 |   |

 

The oil and gas derivatives are not designated as cashflow hedges under SFAS 133 and, accordingly, the changes in fair value arerecorded in current period earnings.

***Statements of Cash Flows — InvestingActivities***

Cash used in investing activities was $551.6 million forthe year ended December 31, 2006, compared to $150.9 million for the yearended December 31, 2005.  Theincrease in cash used in investing activities was due primarily to theacquisitions of Blacksand and the Kaiser-Francis Assets in the third quarter of2006, as well as to several other acquisitions that were completed in thesecond quarter of 2006.  See Note 2 inNotes to Consolidated Financial Statements.

The total cash used in investing activities for the year endedDecember 31, 2006 includes $298.1 million and $125.0 million for theacquisitions of Blacksand and the Kaiser-Francis Assets, respectively.  Other acquisitions and additional workinginterests in our current wells were approximately $46.2 million and property,plant and equipment purchases accounted for $15.4 million.  In December 20006, we also made a deposit of$20.0 million for the February 2007 acquisition of Stallion (see Note 2 inNotes to Consolidated Financial Statements). The total for the year ended December 31, 2006 also includes $47.0million for the drilling and development of oil and gas properties.

The total for the year ended December 31, 2005 includes $111.4million for the acquisition of Exploration Partners, LLC, $11.2 million for theacquisition of other oil and gas properties and wells and additional workinginterests in our current wells and $1.6 million for property, plant andequipment.  It also includes $27.1million for the drilling and development of oil and gas properties.

We currently anticipate that our drilling budget, which predominantlyconsists of drilling, infrastructure projects and equipment, will be between$80.0 million and $120.0 million for 2007. At February 28, 2007, we had $120.2 million available for 

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**Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

borrowing under our credit facility. The amount and timing of our capital expenditures is largely discretionaryand within our control.  If oil and gasprices decline below acceptable levels, we could choose to defer a portion ofour planned capital expenditures until later periods.  We routinely monitor and adjust our capitalexpenditures in response to changes in oil and gas prices, drilling andacquisition costs, industry conditions and internally generated cash flow.  Matters outside our control that could affectthe timing of our capital expenditures include obtaining required permits andapprovals in a timely manner and the availability of rigs and crews.  Based upon current oil and gas priceexpectations for 2007, we anticipate that our cash flow from operations andavailable borrowing capacity under our credit facility will exceed our plannedcapital expenditures and other cash requirements for 2007.  However, future cash flows are subject to anumber of variables, including the level of gas production and prices.  There can be no assurance that operations andother capital resources will provide cash in sufficient amounts to maintainplanned levels of capital expenditures.

***Statements of Cash Flows — Financing Activities***

Cash provided by financing activities was $554.0 millionfor year ended December 31, 2006, compared to $189.3 million for the yearended December 31, 2005.  Inthe first quarter of 2006, we completed our IPO of an aggregate of 12,450,000units representing limited liability company interests at $21.00 per unit.  The grossproceeds received in the IPO were $261.4 million.  Net proceeds to the Company (afterunderwriting discounts of approximately $18.3 million) were approximately$243.1 million, of which $122.0 million was used to reduce the Company’sthen-existing indebtedness, approximately$114.4 million was used to redeem a portion of the membership interests in theCompany and units held by certain affiliated and non-affiliated holders,approximately $4.3 million was used to pay offering expenses andapproximately $2.0 million was used to pay bonuses to certain executiveofficers of the Company.

TheCompany also recorded gross proceeds of $305.0 million from a private placementof its units during 2006 (see “Private Placement — Class B Units” below).  The proceeds, net of expenses ofapproximately $0.3 million, were used to repay in full the Company’s $250.0million Subordinated Bridge Loan and $53.3 million of borrowings under itsCredit Facility.  Total payments made onthe Credit Facility during 2006 were $115.3 million.

During2006, the Company received proceeds from borrowings on its Credit Facility of$334.0 million, and from borrowing on its Subordinated Bridge Loan of $250.0million.  These proceeds were usedprimarily to fund the acquisitions of Blacksand and the Kaiser-Francis Assets.

In April 2006, theCompany’s Board of Directors declared a distribution of $0.32 per unit withrespect to the first quarter of 2006 pro-rated for the period from the closingof the IPO on January 19, 2006 to March 31, 2006.  As a result, the Company paid aggregatedistributions of approximately $8.9 million in May 2006.

In July 2006, the Company’sBoard of Directors declared a distribution of $0.40 per unit with respect tothe second quarter of 2006.  Thedistribution totaling approximately $11.2 million was paid in August 2006.

In October 2006, theCompany’s Board of Directors declared a distribution of $0.43 per unit withrespect to the third quarter of 2006. The distribution totaling approximately $12.0 million was paid inNovember 2006.

In January 2007, the Company’sBoard of Directors declared a distribution of $0.52 per unit with respect tothe fourth quarter of 2006.  Thedistribution totaling approximately $22.5 million was paid in February 2007 tounitholders of record at the close of business on January 29, 2007.

Company management currentlyanticipates recommending to the Board of Directors an increase in the cashdistribution beginning with the second fiscal quarter of 2007 to an annual rateof $2.28 per unit from the current annual rate of $2.08 per unit.

***Private Placement — Class B Units***

InOctober 2006, the Company completed a Class B Unit and Unit Purchase Agreementwith a group of institutionalinvestors whereby it privately placed9,185,965 Class B units at a price of $20.55 per unit, and 5,534,687 units at aprice of $21.00 per unit, for aggregate gross proceeds of $305.0 million, withoffering expenses of approximately $0.3 million, (the “Class B PrivatePlacement”).  In January 2007, at aspecial meeting of Linn unitholders, unitholders approved the one-for-oneconversion of each of the Class B units into units.  In connection with the Class B PrivatePlacement, the Company also agreed to file a registration statement with theSEC covering the units and the units underlying the Class B units.  In accordance with the 

47

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**Item 7.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operation - Continued**

agreement, theregistration statement must be declared effective by the SEC no later than 210days following the closing (extended by separate agreement from 165 days).

As noted above, proceeds from this transaction were used to repayindebtedness.  In connection with therepayment of the subordinated bridge loan, the Company wrote off approximately$2.7 million of deferred financing fees, which was recognized as expense in thefourth quarter of 2006.

***Private Placement — Class C Units***

In February 2007, theCompany completed a Class C Unit and Unit Purchase Agreement with a group of institutional investorswhereby it privately placed 7,465,946 Class C units at a price of $25.06 perunit, and 6,650,144 units at a price of $26.00 per unit, for aggregate grossproceeds of $360.0 million (the “Class C Private Placement”).  The proceeds from the Class C PrivatePlacement were used to finance the Stallion acquisition and the acquisitions ofcertain gas properties in West Virginia (see Note 2 in Notes to ConsolidatedFinancial Statements).

The Class C unitsrepresent a new class of equity securities that is entitled to a specialquarterly distribution equal to 115% of the distribution received by theexisting units.  The Class C units haveno voting rights other than as required by law and are subordinated to theunits on dissolution and liquidation.  Ifapproved by a vote of the Company’s unitholders at the special meeting to beheld in April 2007, the Class C units will convert to units on a one-for-onebasis.  In connection with the Class CPrivate Placement, the Company also agreed to file a registration statementwith the SEC covering the units and the units underlying the Class Cunits.  In accordance with the agreement,the registration statement must be declared effective by the SEC no later than165 days following the closing.

The Company has agreed tofile a registration statement to register the future resale of units issued underthe Class B Private Placement and the Class C Private Placement shortly afterthe filing of its Annual Report on Form 10-K. Under the terms of the Class B Private Placement and the Class C PrivatePlacement, if the registration statements are not declared effective inaccordance with the respective agreements, the Company could be required to paypurchasers, as liquidated damages and not as a penalty, certain amounts asdefined in the agreements.  The Company doesnot believe it is probable that it will be required to make such payments;therefore, has not recorded a liability at this time.  Such amounts, if any, would not be expectedto be material to the Company’s financial position or results of operations.

***Credit Facility***

At December 31, 2006 the Company had an $800.0million senior secured revolving credit facility with a maturity of August2010, and a borrowing base of $480.0 million (“Credit Facility”).  In February 2007, in conjunction with theStallion acquisition and two acquisitions in West Virginia (see Note 2 in Notesto Consolidated Financial Statements) the Company amended its Credit Facility,increasing the borrowing base to $725.0 million.  In connection with this amendment, in thefirst quarter of 2007, the Company paid fees of approximately $1.5 million,which will be amortized over the remaining term of the Credit Facility, andwrote-off deferred financing fees of approximately $0.5 million.  At February 28, 2007, we had $120.2 millionavailable for borrowing under our credit facility.

The borrowing base under the Credit Facility will beredetermined semi-annually by the lenders in their sole discretion, based on,among other things, reserve reports as prepared by reserve engineers takinginto account the oil and gas prices at such time.  Our obligations under the Credit Facility aresecured by mortgages on our oil and gas properties as well as a pledge of allownership interests in our operating subsidiaries.  We are required to maintain the mortgages onproperties representing at least 80% of our oil and gas properties.  Additionally, the obligations under theCredit Facility are guaranteed by all of our operating subsidiaries and may beguaranteed by any future subsidiaries.

At our election, interest on the Credit Facility isdetermined by reference to LIBOR plus an applicable margin between 1.00% and1.75% per annum; or a domestic bank rate plus an applicable margin between0.00% and 0.25% per annum.  Interest ispayable quarterly for domestic bank rate loans and at the applicable maturitydate for LIBOR loans.

48

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**Item 7.    Management’s Discussionand Analysis of Financial Condition and Results of Operation - Continued**

The Credit Facility contains various covenants thatlimit the Company’s ability to incur additional indebtedness, make acquisitionsor certain capital expenditures; make distributions other than from availablecash; merge or consolidate; and engage in certain asset dispositions.  The Credit Facility also contains covenantsthat require the Company to maintain the following financial ratios:

·                  consolidatednet income plus interest expense, income taxes, depreciation, depletion,amortization and other similar changes, minus all non-cash income added toconsolidated net income, and giving pro forma effect to any acquisitions orcapital expenditures, to interest expense of not less than 2.5 to 1.0

·                  consolidatedcurrent assets, including the unused amount of the total commitments, toconsolidated current liabilities of not less than 1.0 to 1.0, excludingnon-cash assets and liabilities under SFAS 133, which includes the currentportion of oil and gas and interest rate derivatives

TheCredit Facility does not contain a minimum debt to equity ratiorequirement.  The Company is in compliancewith all financial and other covenants of its Credit Facility.

The Company repaid $53.3million of borrowings under its Credit Facility in October 2006 (see “PrivatePlacement — Class B Units” above).

***SubordinatedTerm Loan***

In October 2005, we enteredinto a facility for a $60.0 million second lien senior subordinated termloan.  The proceeds of the subordinatedterm loan were used to fund a portion of the purchase price for the acquisitionof oil and gas properties from Exploration Partners.  The outstanding balance was paid in full in2006, with proceeds from our IPO.

***Subordinated Bridge Loan***

In August 2006, in orderto fund a portion of the acquisitions of Blacksand and the Kaiser-FrancisAssets, we entered into a $250.0 million Subordinated Bridge Loan with atermination of August 1, 2007.  TheCompany repaid in full the Subordinated Bridge Loan in October 2006 (see “PrivatePlacement — Class B Units” above).

49

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**Item 7.    Management’s Discussionand Analysis of Financial Condition and Results of Operation - Continued**

***Contractual Obligations***

A summary of ourlong-term contractual obligations as of December 31, 2006 is provided inthe following table:
| ** **                                      | ** ** | **Payments Due**   | ** ** |
|-------------------------------------------------|------------|-------------------------|------------|
| **Contractual Obligations**                | ** ** | ** **              | ** ** | **Total** | ** ** | **Less than  1 Year** | ** ** | **2 — 3  Years** | ** ** | **4 -5  Years** | ** ** | **After  5 Years** | ** ** |
| ** **                                      | ** ** | **(in thousands)** | ** ** |
| Long-term Debt  Obligations:                    |       |                    |       |   |   |   |   |   |   |   |   |
| Long-term notes  payable                        |       | $                       | 3,361      |   | $ | 874 |   | $ | 1,511 |   | $ | 675 |   | $ | 301 |   |
| Credit facility                                 |       | 425,750                 |       | — |   | — |   | 425,750 |   | — |   |
| Interest on  credit facility computed at 7.125% |       | 108,699                 |       | 30,335 |   | 60,669 |   | 17,695 |   | — |   |
| Operating Lease  Obligations:                   |       |                    |       |   |   |   |   |   |   |   |   |
| Office and  office equipment leases             |       | 8,837                   |       | 825 |   | 2,104 |   | 2,232 |   | 3,676 |   |
| Other Long-term  Liabilities:                   |       |                    |       |   |   |   |   |   |   |   |   |
| Asset retirement  obligation                    |       | 8,594                   |       | — |   | — |   | 65 |   | 8,529 |   |
| Other:                                          |       |                    |       |   |   |   |   |   |   |   |   |
| Equipment  purchases                            |       | 909                     |       | 909 |   | — |   | — |   | — |   |
| Executive  compensation                         |       | 250                     |       | 250 |   | — |   | — |   | — |   |
| Total                                           |       | $                       | 556,400    |   | $ | 33,193 |   | $ | 64,284 |   | $ | 446,417 |   | $ | 12,506 |   |
|                                                 |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

***Off-Balance Sheet Arrangements***

At December 31,2006, the Company did not have any off-balance sheet arrangements that have, orare reasonably likely to have, a material effect on our financial position orresults of operations.

***Contingencies***

During 2006, 2005, and2004 no significant payments were made to settle any of the Company’s legalproceedings.  The Company regularlyanalyzes current information and accrues for probable liabilities on thedisposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments,litigation or other sources are recorded when it is probable that a liabilityhas been incurred and the amount can be reasonably estimated.

***CapitalStructure***

The Company’s capitalization,including current maturities of long-term debt, is presented below:

|                                             | ** ** | **December 31,**   | ** ** |
|---------------------------------------------|------------|-------------------------|------------|
| ** **                                  | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                  | ** ** | **(in thousands)** | ** ** |
| Cash and cash  equivalents                  |       | $                       | 6,595      |   | $ | 11,041 |   |
| Credit facility                             |       | $                       | 425,750    |   | $ | 207,000 |   |
| Other long-term  liabilities                |       | 21,587                  |       | 34,198 |   |
| Total long-term  debt and other obligations |       | 447,337                 |       | 241,198 |   |
| Total  unitholders’ capital (deficit)  |       | 449,954                 |       | (46,831 | ) |
| Total  capitalization                       |       | $                       | 897,291    |   | $ | 194,367 |   |

 

50

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**Item 7.    Management’s Discussionand Analysis of Financial Condition and Results of Operation - Continued**

**Non-GAAP Financial Measure**

**Adjusted EBITDA**

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

Interest expense, net ofamounts capitalized;Depreciation, depletion and amortization;Write-off of deferred financing fees;(Gain) loss on sale of assets;(Gain) loss from equity investment;Accretion of asset retirement obligation;Unrealized (gain) loss oil and gas derivatives;Realized (gain) loss on canceled gas swaps;Unit-based compensation expense;IPO cash bonuses; andIncome tax (benefit) provision.

The costs of canceling gas swaps before their originalsettlement date during 2005 were adjustments to Adjusted EBITDA that requiredexpenditure of cash.  These costs werefinanced with borrowings under our credit facility, and such long-term debt isrecognized as an increase in cash from financing activities.

Adjusted EBITDA is a significant performance metric usedby management to indicate (prior to the establishment of any reserves by ourBoard of Directors) the cash distributions we expect to pay ourunitholders.  Specifically, thisfinancial measure indicates to investors whether or not we are generating cashflow at a level that can sustain or support an increase in our quarterly distributionrates.  Adjusted EBITDA is also aquantitative standard used throughout the investment community with respect topublicly-traded partnerships and limited liability companies.

The following table presents a reconciliation of our consolidated net income(loss) to Adjusted EBITDA:
| ** **                                        | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                        | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                        | ** ** | **(in thousands)**                    | ** ** |
| Net income  (loss)                                |       | $                                          | 79,185     |   | $ | (56,351 | ) | $ | (4,816 | ) |
| Plus:                                             |       |                                       |       |   |   |   |   |
| Interest expense, net of amounts capitalized      |       | 25,494                                     |       | 7,040 |   | 3,530 |   |
| Depreciation, depletion and amortization          |       | 24,173                                     |       | 7,294 |   | 3,656 |   |
| Write-off of deferred financing fees              |       | 3,342                                      |       | 364 |   | — |   |
| Loss on sale of assets                            |       | 72                                         |       | 39 |   | 33 |   |
| Loss from equity investment                       |       | —                                     |       | 17 |   | 56 |   |
| Accretion of asset retirement obligation          |       | 314                                        |       | 172 |   | 74 |   |
| Unrealized (gain) loss on oil and gas derivatives |       | (77,776                                    | )          | 24,776 |   | 8,765 |   |
| Realized loss on canceled gas derivatives(1)      |       | —                                     |       | 38,281 |   | — |   |
| Unit-based compensation expense                   |       | 21,643                                     |       | — |   | — |   |
| IPO cash bonuses                                  |       | 2,039                                      |       | — |   | — |   |
| Income tax (benefit) provision(2)                 |       | (3,402                                     | )          | 74 |   | — |   |
| Adjusted EBITDA                                   |       | $                                          | 75,084     |   | $ | 21,706 |   | $ | 11,298 |   |

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(1)                Duringthe year ended December 31, 2005, we canceled (before their originalsettlement date) a portion of out-of-the-money gas swaps and realized a loss of$38.3 million.  We subsequently hedgedsimilar volumes at higher prices.

(2)                TheCompany’s taxable subsidiaries generated net operating losses for theyear.  Management has subsequentlyrecovered expenses through an intercompany charge for services from LinnOperating, Inc. to Linn Energy, LLC, which should result in a corresponding taxexpense in first quarter of 2007.

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**Item 7.    Management’s Discussionand Analysis of Financial Condition and Results of Operation - Continued**

As noted above,Adjusted EBITDA is a non-GAAP performance measure used by our management and isa quantitative measure used in the oil and gas industry.  On our consolidated statement of cash flowsfor the year ended December 31, 2006, net cash used in operatingactivities was approximately $6.8 million and includes approximately $20.4million realized gain on oil and gas and interest rate swap derivatives and$2.0 million of bonuses paid to executive officers in connection with our IPO.  On our consolidated statement of cash flowsfor the year ended December 31, 2005, net cash used in operatingactivities was approximately $29.5 million and includes approximately $51.4million realized loss on oil and gas and interest rate swap derivatives.  On our consolidated statement of cash flowsfor the year ended December 31, 2004, net cash provided by operatingactivities was approximately $10.4 million and includes approximately $2.2million realized loss on oil and gas and interest rate swap derivatives.

**Competition**

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

We are also affected by competition for drilling rigs and theavailability of related equipment.  Inthe past, the oil and gas industry has experienced shortages of drilling rigs,equipment, pipe and personnel, which has delayed development drilling and hascaused significant price increases.  Weare unable to predict when, or if, such shortages may occur or how they wouldaffect our drilling program.  Wepurchased two drilling rigs during 2006, at a cost of approximately $2.2million per rig, an additional rig in the first quarter of 2007, and currently have contracts in place foradditional third-party drilling rigs needed to carry out our 2007 drillingprogram.  In the third quarter of 2006,the Company began, for the first time, operating its own drilling rigs, staffedwith Company personnel.

Competition is also strong for attractive oil and gas producingproperties, undeveloped leases and drilling rights, and we cannot assure thatwe will be able to compete satisfactorily when attempting to make furtheracquisitions.

**Critical Accounting Policies andEstimates**

The discussion and analysis of our financial condition and results ofoperations are based upon the consolidated financial statements, which havebeen prepared in accordance with U.S. generally accepted accounting principles(“GAAP”).  The preparation of thesefinancial statements requires us to make estimates and assumptions that affectthe reported amounts of assets, liabilities, revenues and expenses, and relateddisclosure of contingent assets and liabilities.  Certain accounting policies involve judgmentsand uncertainties to such an extent that there is reasonable likelihood thatmaterially different amounts could have been reported under differentconditions, or if different assumptions had been used.  We evaluate our estimates and assumptions ona regular basis.  We base our estimateson historical experience and various other assumptions that are believed to bereasonable under the circumstances, the results of which form the basis formaking judgments about the carrying values of assets and liabilities that arenot readily apparent from other sources. Actual results may differ from these estimates and assumptions used inthe preparation of our financial statements. Below, we have provided expanded discussion of our more significantaccounting policies, estimates and judgments. These accounting policies reflect our more significant estimates andassumptions used in the preparation of our financial statements.  See Note 1 of the Notes to the ConsolidatedFinancial Statements for a discussion of additional accounting policies andestimates made by management.

***Oil and GasProperties***

We account for oil and gas properties by the successful effortsmethod.  Leasehold acquisition costs arecapitalized when incurred.  If provedreserves are found on an undeveloped property, leasehold cost is transferred toproved properties.  Under this method ofaccounting, costs relating to the development of proved areas are capitalizedwhen incurred.

Depreciation and depletion of producing oil and gasproperties is recorded based on units of production.  Unit rates are computed for unamortizeddrilling and development costs using proved developed reserves and foracquisition costs using all proved reserves. SFAS No. 19, *“Financial Accounting and Reporting for Oiland Gas Producing Companies*”(“SFAS 19”) requires that acquisition costs of proved properties beamortized on the basis of all proved reserves, developed and undeveloped andthat capitalized development costs (wells and related equipment and facilities)be amortized on the basis of proved developed reserves.  As more fully described in the SupplementaryOil and Gas Data (Unaudited) in Item 8.  “Financial

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**Item 7.    Management’s Discussionand Analysis of Financial Condition and Results of Operation - Continued**

Statements and Supplementary Data,” our proved reservesat December 31, 2006 were estimated by an independent petroleumengineering firm, DeGolyer and MacNaughton, and are subject to future revisionsbased on availability of additional information.  As described in Note 11 of the Notes to theConsolidated Financial Statements, we follow SFAS No. 143, *“Accounting for Asset Retirement Obligations”*(“SFAS 143”).  Under SFAS 143, estimated asset retirementcosts are recognized when the asset is placed in service and are amortized overproved developed reserves using the units of production method.  Asset retirement costs are estimated by ourengineers using existing regulatory requirements and anticipated futureinflation rates.

Geological, geophysical and dry hole costs on oil and gas propertiesrelating to unsuccessful wells are charged to expense as incurred.

Upon sale or retirement of complete fields of depreciable or depletedproperty, the book value thereof, less proceeds or salvage value, is charged orcredited to income.  On sale orretirement of an individual well the proceeds are credited to accumulateddepreciation and depletion.

In accordance with SFAS No. 144, *“Accounting for theImpairment or Disposal of Long-Lived Assets,”* we assess proved oiland gas properties for possible impairment when events or circumstances indicatethat the recorded carrying value of the properties may not be recoverable.  We recognize an impairment loss as a resultof a triggering event and when the estimated undiscounted future cash flowsfrom a property are less than the carrying value.  If an impairment is indicated, the cash flowsare discounted at a rate approximate to our cost of capital and compared to thecarrying value for determining the amount of the impairment loss torecord.  Estimated future cash flows arebased on management’s expectations for the future and include estimates of oiland gas reserves and future commodity prices and operating costs.  Downward revisions in estimates of reservequantities or expectations of falling commodity prices or rising operatingcosts could result in a reduction in undiscounted future cash flows and couldindicate property impairment.  TheCompany recorded approximately $1.0 million of impairments in 2006, primarilyrelated to downward reserve revisions. See Note 1 in Notes to Consolidated Financial Statements.  The impairment expense is included indepreciation, depletion and amortization on the consolidated statement ofoperations.  No impairments were recordedin 2005 or 2004.

Unproved properties that are individually insignificant are amortized.  Unproved properties that are individuallysignificant are assessed for impairment on a property-by-property basis.  If considered impaired, costs are charged toexpense when such impairment is deemed to have occurred.

***Oil and GasReserve Quantities***

The Company’s estimates of proved reserves are based on the quantitiesof oil and gas that engineering and geological analyses demonstrate, withreasonable certainty, to be recoverable from established reservoirs in thefuture under current operating and economic parameters.  DeGolyer and MacNaughton prepared a reserveand economic evaluation of all our properties on a well-by-well basis as ofDecember 31, 2006.

Reserves and their relation to estimated future net cash flows impactour depletion and impairment calculations. As a result, adjustments to depletion and impairment are madeconcurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derivedfrom these reserve estimates, in accordance with SEC guidelines.  The independent engineering firm describedabove adheres to the same guidelines when preparing their reserve reports.  The accuracy of our reserve estimates is afunction of many factors including the following:  the quality and quantity of available data,the interpretation of that data, the accuracy of various mandated economicassumptions and the judgments of the individuals preparing the estimates.

The Company’s proved reserve estimates are a function of manyassumptions, all of which could deviate significantly from actual results.  As such, reserve estimates may materiallyvary from the ultimate quantities of gas, natural gas liquids and oileventually recovered.

***RevenueRecognition***

Sales of oil and gas are recognized when oil or gas hasbeen delivered to a custody transfer point, persuasive evidence of a salesarrangement exists, the rights and responsibility of ownership pass to thepurchaser upon delivery, collection of revenue from the sale is reasonablyassured, and the sales price is fixed or determinable.  Oil and gas is sold by the Company on amonthly basis.  Virtually all of theCompany’s contracts’ pricing provisions are tied to a market index, withcertain adjustments based on, among 

53

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**Item 7.    Management’s Discussionand Analysis of Financial Condition and Results of Operation - Continued**

other factors, whether a well delivers to a gathering ortransmission line, quality of oil and gas, and prevailing supply and demandconditions, so that the price of the oil and gas fluctuate to remaincompetitive with other available oil and gas suppliers.  As a result, the Company’s revenues from thesale of oil and gas will suffer if market prices decline, and benefit if theyincrease.  The Company believes that thepricing provisions of its oil and gas contracts are customary in the industry.

Gas imbalances occur when the Company sells more or lessthan its entitled ownership percentage of total gas production.  Any amount received in excess of the Company’sshare is treated as a liability.  If theCompany receives less than its entitled share, the underproduction is recordedas a receivable.  The Company did nothave any significant gas imbalance positions at December 31, 2006 or 2005.

Natural gas marketing is recorded on the gross accountingmethod because the Company takes title to the gas it purchases from the variousproducers and bears the risks and enjoys the benefits of that ownership.  Natural gas marketing revenues and naturalgas marketing expense, titled as such, are reported on the consolidatedstatements of operations for the years ended December 31, 2006, 2005 and2004.

The Company currently uses the “Net-Back” method ofaccounting for transportation arrangements of its gas sales.  The Company sells gas at the wellhead andcollects a price and recognizes revenues based on the wellhead sales pricesince transportation costs downstream of the wellhead are incurred by itscustomers and reflected in the wellhead price.

The Company generates electricity with excess gas, whichit uses to serve certain of its operating facilities in California.  Any excess electricity is sold to thewholesale power market and the revenue is recorded on the accrual basis.  This revenue is included in “other income” onthe consolidated statements of operations.

The Company is paid a monthly operating fee for each wellit operates for outside owners.  The feecovers monthly operating and accounting costs, insurance, and other recurringcosts.  General and administrativeexpenses are presented net of approximately $1.1 million, $1.2 million and $0.6million for the years ended December 31, 2006, 2005 and 2004,respectively, which represent reimbursements from other working interest owners.

***DerivativeInstruments and Hedging******Activities***

We use derivative financial instruments to achieve a morepredictable cash flow from our oil and gas production by reducing our exposureto price fluctuations.  Currently, thesetransactions consist of fixed price swaps and puts.  Additionally, we use derivative financialinstruments in the form of interest rate swaps to mitigate our interest rateexposure.  We account for these activitiespursuant to SFAS 133.  This statementestablishes accounting and reporting standards requiring that derivativeinstruments (including certain derivative instruments embedded in othercontracts) be recorded at fair market value and included in the balance sheetas assets or liabilities.

The accounting for changes in the fair market value of a derivativeinstrument depends on the intended use of the derivative instrument and theresulting designation, which is established at the inception of a derivativeinstrument.  SFAS 133 requires that acompany formally document, at the inception of a hedge, the hedgingrelationship and the company’s risk management objective and strategy forundertaking the hedge, including identification of the hedging instrument, thehedged item or transaction, the nature of the risk being hedged, the methodthat will be used to assess effectiveness and the method that will be used tomeasure hedge ineffectiveness of derivative instruments that receive hedgeaccounting treatment.

A put option requires us to pay the counterparty the fair value of theoption at the purchase date and receive from the counterparty the excess, ifany, of the fixed floor over the floating market price.  The costs incurred to enter into thetransactions are expensed as incurred, and the change in fair market value ofthe instrument is reported in the statement of operations each period.

We did not designate any of our derivative instruments as hedges underSFAS 133, even though they protected us from changes in commodity prices.  Therefore, the changes in fair value of theseinstruments were recorded in our current earnings.  These amounts are non-cash gains or losses.

See Item 7A. “Quantitativeand Qualitative Disclosure About Market Risk” for discussion regarding theCompany’s sensitivity analysis for the Company’s financial instruments andinterest rate swaps.

54

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**Item 7.    Management’s Discussionand Analysis of Financial Condition and Results of Operation - Continued**

***PurchaseAccounting***

The establishment of our asset base through December 31, 2006 hasincluded 14 acquisitions of oil and gas properties.  Three additional acquisitions were completedin February 2007.  These acquisitionshave been accounted for using the purchase method of accounting as prescribedin SFAS No. 141, *“Business Combinations.”*  See Note 2 in Notes to Consolidated FinancialStatements.

In connection with a purchase business combination, the acquiringcompany must allocate the cost of the acquisition to assets acquired andliabilities assumed based on fair values as of the acquisition date.  The purchase price allocations are based onindependent appraisals, discounted cash flows, quoted market prices andestimates by management.  In addition,when appropriate, the Company reviews comparable purchases and sales of oil andgas properties within the same regions, and uses that data as a proxy for fairmarket value; i.e., the amount a willing buyer and seller would enter into anexchange for such properties.  Any excessof purchase price over amounts assigned to assets and liabilities is recordedas goodwill.  The amount of goodwillrecorded in any particular business combination can vary significantlydepending upon the value attributed to assets acquired and liabilitiesassumed.  In each of our acquisitions itwas determined that the purchase price did not exceed the fair value of the netassets acquired.  Therefore, no goodwillwas recorded.

In estimating the fair values of assets acquired andliabilities assumed we made various assumptions.  The most significant assumptions related tothe estimated fair values assigned to proved and unproved oil and gasproperties.  To estimate the fair valuesof these properties, we prepared estimates of oil and gas reserves.  We estimated future prices to apply to theestimated reserve quantities acquired, and estimated future operating anddevelopment costs, to arrive at estimates of future net revenues.  For estimated proved reserves, the future netrevenues were discounted using a market-based weighted average cost of capitalrate determined appropriate at the time of the acquisition.  The market-based weighted average cost ofcapital rate was subjected to additional project-specific risking factors.  To compensate for the inherent risk ofestimating and valuing unproved properties, the discounted future net revenuesof probable and possible reserves were reduced by additional risk-weightingfactors.

Deferred taxes must be recorded for any differencesbetween the assigned values and tax bases of assets and liabilities.  Estimated deferred taxes are based onavailable information concerning the tax basis of assets acquired andliabilities assumed and loss carryforwards at the acquisition date, althoughsuch estimates may change in the future as additional information becomesknown.

While the estimates of fair value for the assets acquiredand liabilities assumed have no effect on our cash flows, they can have aneffect on the future results of operations. Generally, higher fair values assigned to oil and gas properties resultin higher future depreciation, depletion and amortization expense, whichresults in a decrease in future net earnings. Also, a higher fair value assigned to oil and gas properties, based on higherfuture estimates of oil and gas prices, could increase the likelihood of animpairment in the event of lower commodity prices or higher operating coststhan those originally used to determine fair value.  An impairment would have no effect on cash flowsbut would result in a decrease in net income for the period in which theimpairment is recorded.

***Unit-BasedCompensation***

We account for unit-based compensation pursuant to SFAS No. 123 (revised 2004), *“Shared Based Payment”*(“SFAS 123R”).  SFAS 123R requires an entity to recognize thegrant-date fair-value of stock options and other equity-based compensationissued to employees in the income statement and eliminates the alternative touse the intrinsic value method of accounting that was provided under theoriginal provisions of SFAS 123, which resulted in no compensation expenserecorded in the financial statements related to the issuance of equity awardsto employees.  It establishes fair valueas the measurement objective in accounting for share-based payment arrangementsand requires companies to apply a fair-value-based measurement method inaccounting for share-based payment transactions with employees.  We also follow the guidance in StaffAccounting Bulletin (“SAB”) No. 107,*“Share-BasedPayment,”* which contains the express views of the SEC staffregarding the interaction between SFAS 123R and certain SEC rules andregulations and provides the staff’s views regarding the valuation ofshare-based payment arrangements for public companies.  We recorded no unit-based compensationexpense for the years ended December 31, 2005 and 2004, as there were nounit-based payments made during the respective periods.

**New Accounting Pronouncements**

There have been no newaccounting standards that materially affected the Company this period*.*

55

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**Item 7A. **Quantitative andQualitative Disclosures About Market Risk

The primary objective of the following information isto provide forward-looking quantitative and qualitative information about ourpotential exposure to market risks.  Theterm “market risk” refers to the risk of loss arising from adverse changes ingas prices and interest rates.  Thedisclosures are not meant to be precise indicators of expected future losses,but rather indicators of reasonably possible losses.  This forward-looking information providesindicators of how we view and manage our ongoing market risk exposures.  All of our market risk sensitive instrumentswere entered into for purposes other than speculative trading.

**Commodity PriceRisk**

Our major market risk exposure is in the pricingapplicable to our oil and gas production. Realized pricing is primarily driven by the spot market pricesapplicable to our oil and gas production and the prevailing price for oil.  Pricing for oil and gas production has beenvolatile and unpredictable for several years, and we expect this volatility tocontinue in the future.  The prices wereceive for production depend on many factors outside of our control.

We periodically have entered into and anticipateentering into hedging arrangements with respect to a portion of our projectedoil and gas production through various transactions that hedge the futureprices received.  These transactions mayinclude price swaps whereby we will receive a fixed price for our productionand pay a variable market price to the contract counterparty.  At the settlement date, we receive theexcess, if any, of the fixed floor over the floating rate.  Additionally, we have put options for whichwe pay the counterparty the fair value at the purchase date.  These hedging activities are intended tosupport oil and gas prices at targeted levels and to manage our exposure to oiland gas price fluctuations.  We do nothold or issue derivative instruments for speculative trading purposes.

At December 31, 2006, the fair value of hedgesthat have settled during 2006 was an asset of approximately $37.8 million and aliability of approximately $0.5 for a net asset of approximately $37.3 million,which we are owed from the counterparty. A 10% increase in the index oil and gas prices above theDecember 31, 2006 prices for the next twelve months would result in areduction of approximately $26.8 million in the value of our hedges;conversely, a 10% decrease in the index oil and gas prices would result in anincrease of approximately $26.8 million.

Our derivatives as of December 31, 2006 through2011, are summarized in the table presented in Note 15 in Notes to ConsolidatedFinancial Statements.

**Interest Rate Risk**

At December 31, 2006, we had long-term debtoutstanding of $425.8 million under our Credit Facility, which incurredinterest at floating rates in accordance the Credit Facility agreement.  As of December 31, 2006, our rate basedon the one-month LIBOR was approximately 7.125%.  A 1% increase in the one-month LIBOR wouldresult in an estimated $4.3 million increase in annual interest expense.

In order to finance the Stallion acquisition and theacquisitions of certain gas properties in West Virginia, in February 2007, theCompany modified its Credit Facility, increasing the borrowing base to $725.0million.  See Note 8 in Notes toConsolidated Financial Statements.

We have periodically entered into interest rate swapagreements to minimize the effect of fluctuations in interest rates.  We are required to pay our counterparties thedifference between and the fixed rate in the contract and the actual rate ifthe actual rate is lower than the fixed rate and conversely, our counterpartiesare required to pay us if the actual rate is higher than the fixed rate in thecontract.  At December 31, 2006, wehad two interest rate swaps outstanding with notional amounts of $50.0 millionfor 2007 and 2008, and fixed interest rates of 5.30% and 5.79%, respectively.

A 1% change in LIBOR as of December 31, 2006would result in an estimated $1.0 million change in annual interest expenseassociated with our interest swap agreements.

Under the terms of the swap agreements, we receivequarterly interest payments at the three-month LIBOR rate.

We did not designate the interest rate swap agreementswe entered into as hedges under SFAS 133, even though they protect us fromchanges in interest rates.  Therefore,the changes in fair value of these instruments were recorded in our currentearnings.  These amounts are non-cashgains and losses.

56

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**Item 8.**                          FinancialStatements and Supplementary Data

**INDEX TO FINANCIALSTATEMENTS and SUPPLEMENTARY DATA**
|                                                                                                                              | ** ** | **Page** |
|------------------------------------------------------------------------------------------------------------------------------|------------|----------|
|                                                                                                                         |       |     |
| Report of Independent Registered Public Accounting  Firm                                                                     |       | 58       |
| Consolidated Balance Sheets, as of December 31,  2006 and 2005                                                          |       | 59       |
| Consolidated Statements of Operations, for the years  ended December 31, 2006, 2005 and 2004                            |       | 61       |
| Consolidated  Statements of Unitholders’ Capital (Deficit), for the years ended  December 31, 2006, 2005, and 2004 |       | 62       |
| Consolidated  Statements of Cash Flows, for the years ended December 31, 2006, 2005,  and 2004                          |       | 63       |
| Notes to Consolidated Financial Statements                                                                                   |       | 65       |
| Supplementary Oil and Gas Data (Unaudited)                                                                                   |       | 89       |
| Supplementary Quarterly Data (Unaudited)                                                                                     |       | 93       |

 

57

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**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

TheBoard of Directors

Linn Energy, LLC:

We have audited the accompanying consolidated balancesheets of Linn Energy, LLC and subsidiaries as of December 31, 2006 and2005, and the related consolidated statements of operations, unitholders’capital (deficit), and cash flows for each of the years in the three-yearperiod ended December 31, 2006. These consolidated financial statements are the responsibility of theCompany’s management.  Our responsibilityis to express an opinion on these consolidated financial statements based onour audits.

We conducted our audits in accordance with the standardsof the Public Company Accounting Oversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting theamounts and disclosures in the financial statements.  An audit also includes assessing theaccounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonablebasis for our opinion.

In our opinion, the consolidated financial statementsreferred to above present fairly, in all material respects, the financialposition of Linn Energy, LLC and subsidiaries as of December 31, 2006 and2005, and the results of their operations and their cash flows for each of theyears in the three-year period ended December 31, 2006, in conformity withU.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston,Texas

March 29, 2007

58

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**LINN ENERGY, LLCCONSOLIDATED BALANCE SHEETS**
| ** **                                                                | ** ** | **December 31,**   | ** ** |
|---------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                                                | ** ** | **(in thousands)** | ** ** |
| **Assets**                                                                | ** ** | ** **              | ** ** | ** ** | ** ** |
| **Current assets:**                                                       | ** ** | ** **              | ** ** | ** ** | ** ** |
| Cash and cash  equivalents                                                |       | $                       | 6,595      |   | $ | 11,041 |   |
| Receivables - trade,  net                                                 |       | 19,124                  |       | 17,753 |   |
| Fair value of interest  rate swaps                                        |       | 44                      |       | 202 |   |
| Inventory                                                                 |       | 578                     |       | 68 |   |
| Current portion of oil  and gas derivatives                               |       | 37,773                  |       | 1,601 |   |
| Current portion of  deferred tax assets, net                              |       | 3,344                   |       | — |   |
| Other current assets                                                      |       | 2,218                   |       | 4,068 |   |
| Total current  assets                                                     |       | 69,676                  |       | 34,733 |   |
| ** **                                                                | ** ** | ** **              | ** ** | ** ** | ** ** |
| Oil and gas properties  and related equipment (successful efforts method) |       | 766,638                 |       | 250,000 |   |
| Less accumulated  depreciation, depletion and amortization                |       | (33,349                 | )          | (10,707 | ) |
|                                                                      |       | 733,289                 |       | 239,293 |   |
|                                                                      |       |                    |       |   |   |
| Property and equipment,  net                                              |       | 20,754                  |       | 2,525 |   |
|                                                                      |       |                    |       |   |   |
| **Other assets:**                                                         |       |                    |       |   |   |
| Long-term portion of  oil and gas derivatives                             |       | 70,435                  |       | 2,795 |   |
| Deferred tax assets,  net                                                 |       | 16                      |       | — |   |
| Deposit for oil and gas  properties                                       |       | 20,086                  |       | — |   |
| Deferred financing fees  and other assets, net                            |       | 2,052                   |       | 1,578 |   |
|                                                                      |       | 92,589                  |       | 4,373 |   |
| Total assets                                                              |       | $                       | 916,308    |   | $ | 280,924 |   |

 

*The accompanying notes are an integral part ofthese consolidated financial statements.*

59

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**LINN ENERGY, LLCCONSOLIDATED BALANCE SHEETS**
| ** **                                                                | ** ** | **December 31,**                                   | ** ** |
|---------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                                                | ** ** | **2006**                                                | ** ** | **2005** | ** ** |
| ** **                                                                | ** ** | **(in thousands,  except unit amounts)** | ** ** |
| **Liabilities  and Unitholders’ Capital (Deficit)**                  | ** ** | ** **                                              | ** ** | ** ** | ** ** |
| ** **                                                                | ** ** | ** **                                              | ** ** | ** ** | ** ** |
| **Current liabilities:**                                                  | ** ** | ** **                                              | ** ** | ** ** | ** ** |
| Current portion  of long-term notes payable                               |       | $                                                       | 873        |   | $ | 113 |   |
| Subordinated  term loan                                                   |       | —                                                  |       | 60,000 |   |
| Accounts payable  and accrued expenses                                    |       | 12,506                                                  |       | 5,612 |   |
| Current portion  of oil and gas derivatives                               |       | 462                                                     |       | 12,094 |   |
| Revenue  distribution                                                     |       | 1,839                                                   |       | 6,082 |   |
| Accrued interest  payable                                                 |       | 2,084                                                   |       | 1,448 |   |
| Gas purchases  payable                                                    |       | 253                                                     |       | 1,208 |   |
| Total current  liabilities                                                |       | 18,017                                                  |       | 86,557 |   |
|                                                                      |       |                                                    |       |   |   |
| **Long-term liabilities:**                                                | ** ** | ** **                                              | ** ** | ** ** | ** ** |
| Notes payable                                                             |       | 2,487                                                   |       | 695 |   |
| Credit facility                                                           |       | 425,750                                                 |       | 207,000 |   |
| Interest rate  swaps                                                      |       | 423                                                     |       | 663 |   |
| Asset retirement  obligation                                              |       | 8,594                                                   |       | 5,443 |   |
| Oil and gas  derivatives                                                  |       | 9,934                                                   |       | 27,139 |   |
| Other long-term  liabilities                                              |       | 149                                                     |       | 258 |   |
| Total long-term  liabilities                                              |       | 447,337                                                 |       | 241,198 |   |
| Total  liabilities                                                        |       | 465,354                                                 |       | 327,755 |   |
| ** **                                                                | ** ** | ** **                                              | ** ** | ** ** | ** ** |
| **Unitholders’ capital (deficit):**                                  | ** ** | ** **                                              | ** ** | ** ** | ** ** |
| 33,617,187 units issued  and outstanding at December 31, 2006        |       | 246,034                                                 |       | 16,024 |   |
| 9,185,965 Class B units  issued and outstanding at December 31, 2006 |       | 188,590                                                 |       | — |   |
| Accumulated income  (loss)                                                |       | 16,330                                                  |       | (62,855 | ) |
|                                                                      |       | 450,954                                                 |       | (46,831 | ) |
| Total liabilities and  unitholders’ capital (deficit)                |       | $                                                       | 916,308    |   | $ | 280,924 |   |

 

*The accompanying notes are an integral part ofthese consolidated financial statements.*

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**LINN ENERGY, LLCCONSOLIDATED STATEMENTS OF OPERATIONS**
| ** **                                             | ** ** | **Year Ended December 31,**                           | ** ** |
|--------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                                             | ** ** | **2006**                                                             | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                             | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                          | ** ** | ** **                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and gas  sales                                     |       | $                                                                    | 80,393     |   | $ | 44,645 |   | $ | 19,502 |   |
| Gain (loss) on  oil and gas derivatives                |       | 103,308                                                              |       | (76,193 | ) | (11,004 | ) |
| Natural gas  marketing revenues                        |       | 5,598                                                                |       | 4,722 |   | 520 |   |
| Other revenues                                         |       | 1,759                                                                |       | 345 |   | 160 |   |
|                                                   |       | 191,058                                                              |       | (26,481 | ) | 9,178 |   |
| **Expenses:**                                          | ** ** | ** **                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  expenses                                    |       | 18,099                                                               |       | 7,356 |   | 4,756 |   |
| Natural gas  marketing expenses                        |       | 4,862                                                                |       | 4,401 |   | 482 |   |
| General and  administrative expenses                   |       | 39,993                                                               |       | 3,332 |   | 1,488 |   |
| Depreciation,  depletion and amortization              |       | 24,173                                                               |       | 7,294 |   | 3,656 |   |
|                                                   |       | 87,127                                                               |       | 22,383 |   | 10,382 |   |
|                                                   |       | 103,931                                                              |       | (48,864 | ) | (1,204 | ) |
| **Other income and (expenses):**                       | ** ** | ** **                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest income                                        |       | 761                                                                  |       | 47 |   | 7 |   |
| Interest  expense, net of amounts capitalized          |       | (25,494                                                              | )          | (7,040 | ) | (3,530 | ) |
| Write-off of  deferred financing fees and other losses |       | (3,415                                                               | )          | (420 | ) | (89 | ) |
|                                                   |       | (28,148                                                              | )          | (7,413 | ) | (3,612 | ) |
| Income (loss) before  income taxes                     |       | 75,783                                                               |       | (56,277 | ) | (4,816 | ) |
| Income tax  benefit (provision)                        |       | 3,402                                                                |       | (74 | ) | — |   |
| Net income  (loss)                                     |       | $                                                                    | 79,185     |   | $ | (56,351 | ) | $ | (4,816 | ) |
| ** **                                             | ** ** | ** **                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income (loss) per  unit:                           |       |                                                                 |       |   |   |   |   |
| Units - basic                                          |       | $                                                                    | 2.64       |   | $ | (2.75 | ) | $ | (0.23 | ) |
| Units - diluted                                        |       | $                                                                    | 2.61       |   | $ | (2.75 | ) | $ | (0.23 | ) |
|                                                   |       |                                                                 |       |   |   |   |   |
| Class B units -  basic                                 |       | $                                                                    | 2.64       |   | $ | — |   | $ | — |   |
| Class B units -  diluted                               |       | $                                                                    | 2.61       |   | $ | — |   | $ | — |   |
|                                                   |       |                                                                 |       |   |   |   |   |
| Weighted average units  outstanding:                   |       |                                                                 |       |   |   |   |   |
| Units - basic                                          |       | 28,281                                                               |       | 20,518 |   | 20,518 |   |
| Units - diluted                                        |       | 30,385                                                               |       | 20,518 |   | 20,518 |   |
|                                                   |       |                                                                 |       |   |   |   |   |
| Class B units -  basic                                 |       | 1,737                                                                |       | — |   | — |   |
| Class B units -  diluted                               |       | 1,737                                                                |       | — |   | — |   |
|                                                   |       |                                                                 |       |   |   |   |   |
| Distributions declared per unit                        |       | $                                                                    | 1.15       |   | $ | — |   | $ | — |   |

 

*The accompanying notes are an integral part ofthese consolidated financial statements.*

61

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**LINN ENERGY, LLC**

**CONSOLIDATEDSTATEMENTS OF UNITHOLDERS’ CAPITAL (DEFICIT)**

|                                                                             | ** ** | **Unitholders’  Capital** | ** ** | **Accumulated  Income  (Loss)** | ** ** | **Treasury  Units  (at Cost)** | ** ** | **Total  Unitholders’  Capital  (Deficit)** | ** ** |
|-----------------------------------------------------------------------------|------------|--------------------------------|------------|---------------------------------|------------|-------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                                                  | ** ** | **(in thousands)**        | ** ** |
| ** **                                                                  |       |                           |       |                            |       |                                |       |                                             |       |
| **Balance as of December 31,  2003**                                   |       | $                              | 16,024     |                            | $          | (1,688                              | )          | $                                                | —     |   | $ | 14,336 |   |
| Net loss                                                                    |       | —                         |       | (4,816                          | )          | —                              |       | (4,816                                           | )          |
| **Balance as of December 31, 2004**                                         |       | 16,024                         |       | (6,504                          | )          | —                              |       | 9,520                                            |       |
| Net loss                                                                    |       | —                         |       | (56,351                         | )          | —                              |       | (56,351                                          | )          |
| **Balance as of December 31, 2005**                                         |       | 16,024                         |       | (62,855                         | )          | —                              |       | (46,831                                          | )          |
| Sale of initial  public offering units, net of   offering expense of $4,339 |       | 225,139                        |       | —                          |       | 13,671                              |       | 238,810                                          |       |
| Sale of private  placement units, net of   expense of $348                  |       | 304,652                        |       | —                          |       | —                              |       | 304,652                                          |       |
| Redemption of  member units                                                 |       | —                         |       | —                          |       | (114,449                            | )          | (114,449                                         | )          |
| Cancellation of  member units                                               |       | (100,778                       | )          | —                          |       | 100,778                             |       | —                                           |       |
| Distribution to  members                                                    |       | (32,056                        | )          | —                          |       | —                              |       | (32,056                                          | )          |
| Unit-based  compensation                                                    |       | 21,643                         |       | —                          |       | —                              |       | 21,643                                           |       |
| Net income                                                                  |       | —                         |       | 79,185                          |       | —                              |       | 79,185                                           |       |
| **Balance as of December 31, 2006**                                         |       | $                              | 434,624    |                            | $          | 16,330                              |       | $                                                | —     |   | $ | 450,954 |   |

 

*The accompanying notes are anintegral part of these consolidated financial statements.*

62

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**LINNENERGY, LLC**

**CONSOLIDATED STATEMENTS OF CASHFLOWS**

 

|                                                                                                               | ** ** | **Year Ended December 31** | ** ** |
|---------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                                                                    | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                    | ** ** | **(in thousands)**                   | ** ** |
| **Cash flow from operating  activities:**                                                                     |       |                                      |       |   |   |   |   |
| Net  income (loss)                                                                                            |       | $                                         | 79,185     |   | $ | (56,351 | ) | $ | (4,816 | ) |
| **Adjustments  to reconcile net income (loss) to net cash provided by (used in)  operating activities:** |       |                                      |       |   |   |   |   |
| Depreciation,  depletion and amortization                                                                     |       | 24,173                                    |       | 7,294 |   | 3,656 |   |
| Amortization  and write-off of deferred financing fees and other losses                                       |       | 4,548                                     |       | 875 |   | 212 |   |
| Accretion  of asset retirement obligation                                                                     |       | 314                                       |       | 172 |   | 74 |   |
| Unit-based  compensation                                                                                      |       | 21,643                                    |       | — |   | — |   |
| Deferred  income tax                                                                                          |       | (3,434                                    | )          | — |   | — |   |
| **Mark-to-market on oil and gas and interest rate  derivatives:**                                             |       |                                      |       |   |   |   |   |
| Total  (gains) losses                                                                                         |       | (103,390                                  | )          | 75,207 |   | 12,263 |   |
| Realized  gains (losses)                                                                                      |       | 20,442                                    |       | (51,417 | ) | (2,239 | ) |
| **Premiums paid for oil and gas derivatives**                                                                 |       | (49,807                                   | )          | (1,628 | ) | —— |   |
| **Changes in assets and liabilities:**                                                                        |       |                                      |       |   |   |   |   |
| Increase  in accounts receivable                                                                              |       | (371                                      | )          | (12,208 | ) | (3,725 | ) |
| (Increase)  decrease in inventory and other assets                                                            |       | 2,833                                     |       | (399 | ) | 5 |   |
| Decrease  in accounts payable and accrued expenses                                                            |       | 1,633                                     |       | 2,670 |   | 1,563 |   |
| Increase  in interest rate derivatives payable                                                                |       | —                                    |       | — |   | 759 |   |
| Increase  (decrease) in revenue distribution                                                                  |       | (4,243                                    | )          | 3,589 |   | 1,909 |   |
| Increase  in accrued interest payable                                                                         |       | 636                                       |       | 1,036 |   | 189 |   |
| Increase  (decrease) in gas purchases payable                                                                 |       | (955                                      | )          | 726 |   | 482 |   |
| Increase  (decrease) in other liabilities                                                                     |       | (12                                       | )          | 916 |   | 19 |   |
| Net  cash provided by (used in) operating activities                                                          |       | (6,805                                    | )          | (29,518 | ) | 10,351 |   |
| **Cash flow from investing activities:**                                                                      |       |                                      |       |   |   |   |   |
| Acquisition  of oil and gas properties                                                                        |       | (469,274                                  | )          | (122,065 | ) | (47,356 | ) |
| Development  of oil and gas properties                                                                        |       | (46,963                                   | )          | (27,145 | ) | (14,719 | ) |
| Deposit  for oil and gas properties                                                                           |       | (20,086                                   | )          | — |   | — |   |
| Purchases  of property and equipment                                                                          |       | (15,414                                   | )          | (1,639 | ) | (1,519 | ) |
| Other  investing activities                                                                                   |       | 106                                       |       | (49 | ) | 2,221 |   |
| Net  cash used in investing activities                                                                        |       | (551,631                                  | )          | (150,898 | ) | (61,373 | ) |
| **Cash flow from financing activities:**                                                                      |       |                                      |       |   |   |   |   |
| Proceeds  from sale of initial public offering units                                                          |       | 243,149                                   |       | — |   | — |   |
| Proceeds  from private placement of units                                                                     |       | 305,000                                   |       | — |   | — |   |
| Redemption  of member units                                                                                   |       | (114,449                                  | )          | — |   | — |   |
| Proceeds  from notes payable                                                                                  |       | —                                    |       | 65,295 |   | 604 |   |
| Principal  payments on notes payable                                                                          |       | (493                                      | )          | (5,085 | ) | (6 | ) |
| Proceeds  from credit facility                                                                                |       | 334,000                                   |       | 210,000 |   | 30,805 |   |
| Principal  payments on credit facility                                                                        |       | (115,250                                  | )          | (75,605 | ) | — |   |
| Proceeds  from subordinated bridge loan                                                                       |       | 250,000                                   |       | — |   | — |   |
| Principal  payments on subordinated bridge loan                                                               |       | (250,000                                  | )          | — |   | — |   |
| Principal  payments on subordinated term loan                                                                 |       | (60,000                                   | )          | — |   | — |   |
| Distribution  to members                                                                                      |       | (32,056                                   | )          | — |   | — |   |
| Offering  costs                                                                                               |       | (1,210                                    | )          | (3,532 | ) | — |   |
| Financing  fees                                                                                               |       | (4,701                                    | )          | (1,804 | ) | (236 | ) |
| Net  cash provided by financing activities                                                                    |       | 553,990                                   |       | 189,269 |   | 31,167 |   |
| Net  increase (decrease) in cash                                                                              |       | (4,446                                    | )          | 8,853 |   | (19,855 | ) |
| **Cash and cash equivalents:**                                                                                |       |                                      |       |   |   |   |   |
| Beginning                                                                                                     |       | 11,041                                    |       | 2,188 |   | 22,043 |   |
| Ending                                                                                                        |       | $                                         | 6,595      |   | $ | 11,041 |   | $ | 2,188 |   |

 

*The accompanying notes are anintegral part of these consolidated financial statements.*

63

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**LINN ENERGY, LLCCONSOLIDATED STATEMENTS OF CASH FLOWS — SUPPLEMENTAL DISCLOSURES**
| ** **                                                                                        | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                        | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                        | ** ** | **(in thousands)**                    | ** ** |
| **Supplemental disclosure of cash  flow information:**                                            |       |                                       |       |   |   |   |   |
| Cash payments  for interest                                                                       |       | $                                          | 24,147     |   | $ | 6,510 |   | $ | 1,960 |   |
| **Supplemental disclosures of non  cash investing and financing activities:**                     |       |                                       |       |   |   |   |   |
| Acquisitions of  vehicles and equipment through issuance of notes payable                         |       | $                                          | 3,046      |   | $ | 421 |   | $ | — |   |
| In connection  with the purchase of oil and gas properties, liabilities were assumed as  follows: |       |                                       |       |   |   |   |   |
| Fair value of  assets acquired                                                                    |       | $                                          | 472,499    |   | $ | 123,514 |   | $ | 49,954 |   |
| Cash paid                                                                                         |       | (469,274                                   | )          | (122,065 | ) | (47,356 | ) |
| Liabilities assumed                                                                               |       | $                                          | 3,225      |   | $ | 1,449 |   | $ | 2,598 |   |

 

*The accompanying notes are anintegral part of these consolidated financial statements.*

64

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**LINN ENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**(1)****                                 Basis of Presentation and Significant AccountingPolicies**

***(a)******                                 Organization and Description of Business***

Linn Energy, LLC (“Linn”or the “Company”) is an independent oil andgas company focused on the development and acquisition of long-lived propertiesin the United States that began operations in March 2003 and was formed asa Delaware limited liability company in April 2005.  Linn is a holding company that conducts itsoperations through, and its operating assets are owned by, its wholly-ownedsubsidiaries.

***(b)******                                 Basis of Presentation***

The Company presents itsfinancial statements in accordance with U.S. generally acceptedaccounting principles (“GAAP”).  Certain amounts in the consolidatedfinancial statements and notes thereto have been reclassified to conform to the2006 financial statement presentation.

***(c)******                                  Principles of Consolidation***

The consolidated financialstatements include the accounts of the Company and its wholly-ownedsubsidiaries.  All significantintercompany transactions and balances have been eliminated upon consolidation.

***(d)******                                 Use of Estimates***

Management of the Company hasmade a number of estimates and assumptions relating to the reporting of assetsand liabilities and revenues and expenses and the disclosure of contingentassets and liabilities to prepare these consolidated financial statements inconformity with GAAP.  Actual resultscould differ from those estimates.  Theestimates that are particularly significant to the financial statements includeestimates of oil and gas reserves, future cash flows from oil and gasproperties, depreciation, depletion and amortization, asset retirementobligations, the fair value of derivatives and unit-based compensation expense.

The Company’s estimate of provedreserves is based on the quantities of oil and gas that engineering andgeological analyses demonstrate, with reasonable certainty, to be recoverablefrom established reservoirs in the future under current operating and economicparameters.  DeGolyer and MacNaughtonprepared a reserve and economic evaluation of all the Company’s properties on awell-by-well basis at December 31, 2006.

Reserves and their relation toestimated future net cash flows impact the Company’s depletion and impairmentcalculations.  As a result, adjustmentsto depletion and impairment are made concurrently with changes to reserveestimates.  The Company prepares itsreserve estimates, and the projected cash flows derived from these reserveestimates, in accordance with Securities and Exchange Commission (“SEC”)guidelines.  The independent engineeringfirm adheres to the same guidelines when preparing their reserve reports.  The accuracy of the Company’s reserveestimates is a function of many factors including the following: the qualityand quantity of available data, the interpretation of that data, the accuracyof various mandated economic assumptions, and the judgments of the individualspreparing the estimates.

The Company’s proved reserveestimates are a function of many assumptions, all of which could deviatesignificantly from actual results.  Assuch, reserve estimates may materially vary from the ultimate quantities ofgas, natural gas liquids and oil eventually recovered.

***(e)******                                  Cash Equivalents***

For purposes of the statement ofcash flows, the Company considers all highly liquid debt instruments withoriginal maturities of three months or less to be cash equivalents.

***(f)******                                    Trade Accounts Receivable, Net***

Trade accounts receivable arerecorded at the invoiced amount and do not bear interest.  The Company routinely assesses the financialstrength of its customers and bad debts are recorded based on anaccount-by-account review after all means of collection have been exhausted andthe potential recovery is considered remote. The Company does not have any off-balance-sheet credit exposure relatedto its customers.

65

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

The changes in the Company’s allowance for doubtfulaccounts are as follows:
| ** **                          | ** ** | ** **                                   | ** ** | **Additions**                                 | ** ** | **Deductions**                       | ** ** | ** **                 | ** ** |
|-------------------------------------|------------|----------------------------------------------|------------|-----------------------------------------------|------------|--------------------------------------|------------|----------------------------|------------|
| **Description**                     | ** ** | **Balance at  beginning  of year** | ** ** | **Charged to  costs and  expenses** | ** ** | **Charged to  other  accounts** | ** ** | **Write-off  adjustments** | ** ** | **Balance at  end of  year** | ** ** |
| ** **                          | ** ** | **(in thousands)**                      | ** ** |
| Year Ended  December 31, 2006: |       |                                         |       |                                          |       |                                 |       |                       |       |   |   |
| Allowance for  doubtful accounts    |       | $                                            | 100        |                                          | $          | —                               |       | $                          | —     |   | $ | — |   | $ | 100 |   |
|                                |       |                                         |       |                                          |       |                                 |       |                       |       |   |   |
| Year Ended  December 31, 2005: |       |                                         |       |                                          |       |                                 |       |                       |       |   |   |
| Allowance for  doubtful accounts    |       | $                                            | 50         |                                          | $          | 50                                   |       | $                          | —     |   | $ | — |   | $ | 100 |   |
|                                |       |                                         |       |                                          |       |                                 |       |                       |       |   |   |
| Year Ended  December 31, 2004: |       |                                         |       |                                          |       |                                 |       |                       |       |   |   |
| Allowance for doubtful  accounts    |       | $                                            | —     |                                          | $          | 50                                   |       | $                          | —     |   | $ | — |   | $ | 50 |   |

 

***(g)           Inventory***

Inventory of well equipment,parts, and supplies are valued at cost, determined by the first-in-first-outmethod.

***(h)******                                 Oil and Gas Properties***

The Company accounts for oil andgas properties by the successful efforts method.  Leasehold acquisition costs arecapitalized.  If proved reserves arefound on an undeveloped property, leasehold costs are transferred to provedproperties.  Under this method ofaccounting, costs relating to the development of proved areas are capitalizedwhen incurred.

Depreciation and depletion ofproducing oil and gas properties is recorded based on units of production.  Unit rates are computed for unamortizeddrilling and development costs using proved developed reserves and forunamortized leasehold costs using all proved reserves.  Statement of Financial Accounting Standards (“SFAS”)No. 19, as amended, *“Financial Accounting andReporting by Oil and Gas Producing Companies”*(“SFAS 19”)**requires that acquisition costs of proved properties beamortized on the basis of all proved reserves, developed and undeveloped, andthat capitalized development costs (wells and related equipment and facilities)be amortized on the basis of proved developed reserves.

Proved reserves are estimated byan independent petroleum engineering firm and are subject to future revisionsbased on availability of additional information.  As described in Note 11, the Company accountsfor asset retirement obligations in accordance with SFAS No. 143, *“Accounting for Asset Retirement Obligations”* (“SFAS 143”).  In accordance with SFAS 143, estimated assetretirement costs are recognized when the obligation is incurred, and areamortized over proved developed reserves using the units of production method.  Asset retirement costs are estimated by theCompany’s engineers using existing regulatory requirements and anticipatedfuture inflation rates.

Geological, geophysical, andexploratory dry hole costs on oil and gas properties relating to unsuccessfulexploratory wells are charged to expense as incurred.

Upon sale or retirement ofcomplete fields of depreciable or depleted property, the book value thereof,less proceeds or salvage value, is charged or credited to income.  On sale or retirement of an individual well theproceeds are credited to accumulated depreciation and depletion.

In accordance with SFAS No. 144, *“Accounting for the Impairment or Disposal of Long-Lived Assets,”*we assess proved oil and gas properties for possible impairment when events orcircumstances indicate that the recorded carrying value of the properties maynot be recoverable.  We recognize animpairment loss as a result of a triggering event and when the estimatedundiscounted future cash flows from a property are less than the carryingvalue.  If impairment is indicated, thecash flows are discounted at a rate approximate to our cost of capital andcompared to the carrying value for determining the amount of the impairmentloss to record.  Estimated future cashflows are based on management’s expectations for the future and includeestimates of oil and gas reserves and future commodity prices and operatingcosts.  Downward revisions in estimatesof

66

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

reserve quantities orexpectations of falling commodity prices or rising operating costs could resultin a reduction in undiscounted future cash flows and could indicate propertyimpairment.  The Company recordedapproximately $1.0 million of impairments in 2006, primarily related todownward reserve revisions in one field in the Appalachian Basin.  The impairment expense is included indepreciation, depletion and amortization on the consolidated statement ofoperations.  No impairments were recordedin 2005 or 2004.

Unproven properties that are individuallyinsignificant are amortized.  Unprovedproperties that are individually significant are assessed for impairment on aproperty-by-property basis.  Ifconsidered impaired, costs are charged to expense when such impairment isdeemed to have occurred.

***(i)******                                    Property, Plant and Equipment***

Property, plant and equipmentother than oil and gas properties is carried at cost.  Depreciation is provided principally on thestraight-line method over useful lives as follows:

| Buildings, leasehold  improvements and aircraft |   | 7-39 years |   |
|-------------------------------------------------|--------|------------|--------|
| Furniture and equipment                         |   | 3-7 years  |   |
| Vehicles                                        |   | 5 years    |   |

 

Tangible long-lived assets are evaluated in accordancewith SFAS No. 144, *“Accounting for theDisposal of Long-Lived Assets,”* when events and circumstancesindicate that the carrying value of an asset may not be recoverable.  Recoverabilityof assets to be held and used is measured by a comparison of the carryingamount of an asset to estimated undiscounted future cash flows expected to begenerated by the asset.  If the carryingamount of an asset exceeds its estimated future cash flows, an impairmentcharge is recognized by the amount by which the carrying amount of the assetexceeds the fair value of the asset.  Noimpairments were recorded in 2006, 2005 or 2004.

Maintenance and repairs arecharged to expense as incurred.  Majorrenewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulateddepreciation, depletion, and amortization are removed from the accounts, theproceeds applied thereto, and any resulting gain or loss is reflected in incomefor the period.

***(j)******                                    Derivative Instruments and Hedging Activities***

The Company uses derivativefinancial instruments to achieve a more predictable cash flow from its oil andgas production by reducing its exposure to price fluctuations.  As of December 31, 2006, thesetransactions were in the form of swaps and puts.  Additionally, the Company uses derivativefinancial instruments in the form of interest rate swaps to mitigate itsinterest rate exposure.  The Companyaccounts for its derivatives at fair value as an asset or liability and thechange in the fair value of derivatives is included in income.  TheCompany accounts for these activities pursuant to SFAS No. 133, “*Accounting for Derivative Instruments and HedgingActivities,”* as amended, (“SFAS 133”).  This statement establishes accounting andreporting standards requiring that derivative instruments (including certainderivative instruments embedded in other contracts) be recorded at fair valueand included in the balance sheet as assets or liabilities.

The accounting for changes in thefair value of a derivative instrument depends on the intended use of thederivative and the resulting designation, which is established at the inceptionof a derivative.  SFAS 133 requires thata company formally document, at the inception of a hedge, the hedgingrelationship and the entity’s risk management objective and strategy forundertaking the hedge, including identification of the hedging instrument, thehedged item or transaction, the nature of the risk being hedged, the methodthat will be used to assess effectiveness and the method that will be used tomeasure hedge ineffectiveness of derivative instruments that receive hedgeaccounting treatment.  None of theCompany’s commodity or interest rate derivatives are designated as hedges andtherefore the change in the fair value of the derivatives is included in theconsolidated statements of operations. See Note 10 and Note 15 for discussion related to derivative financialinstruments.

***(k)******                                 Unit-Based Compensation***

SFAS No. 123 (revised 2004),*“ShareBased Payment”* (“SFAS 123R”) requires the recognition ofcompensation expense, over the requisite service period, in an amount equal tothe fair value of unit-based

67

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

payments granted to employees and non-employee directors.  The fair value of the unit-based payments,excluding liability awards, is computed at the date of grant and will not beremeasured.  The fair value of liabilityawards is remeasured at each reporting date through the settlement date withthe change in fair value recognized as compensation expense over thatperiod.  The Company currently does nothave any awards accounted for as liability awards.  SFAS 123R also requires the benefits of taxdeductions in excess of recognized compensation costs to be reported asfinancing cash flow, rather than as an operating cash flow as required underprior guidance.  This requirement willreduce net operating cash flows and increase net financing cash flows inperiods after adoption in which such tax deduction exists.  The Company had no excess tax deductionsduring 2006.

The Company has made a policy decision, in accordance with theprovisions of SFAS 123R, to recognize compensation cost for service-basedawards on a straight-line basis over the requisite service period.  The Company did not issue any unit-basedcompensation awards prior to January 2006. See Note 7 for a discussion of the Company’s accounting for unit-basedcompensation expense.

***(l)******                                    Revenue Distribution***

Revenue distribution on theconsolidated balance sheets of $1.8 million and $6.1 million represents amountsowed to working interest and royalty interest owners as of December 31,2006 and 2005, respectively.

***(m)******                              Offering Costs***

Other current assets atDecember 31, 2006 include approximately $56,000 of costs incurred inconnection with a private placement in February 2007 (see Note 4).  These were reclassified to unitholders’capital upon receipt of the proceeds in the first quarter of 2007.  At December 31, 2005 other currentassets include costs of $3.5 million incurred in connection with the Company’sinitial public offering (“IPO”).  TheCompany reclassified these deferred offering costs to unitholders’ capital uponreceipt of the proceeds from the IPO during the first quarter of 2006 (see Note3).

***(n)******                                 Deferred Financing Fees***

The Company incurred legal andbank fees related to the issuance of debt (see Note 8).  The financing fees incurred for the yearsended December 31, 2006, 2005 and 2004 were $4.7 million, $1.8 million and$0.2 million, respectively.  These debtissuance costs are amortized over the life of the debt agreement.  For the years ended December 31, 2006,2005 and 2004, amortization expense of $1.1 million, $0.5 million and $0.1million, respectively, is included in interest expense.  Deferred financing fees of approximately $3.3million, $0.4 million and zero were written-off in connection with refinancingsduring the years ended December 31, 2006, 2005 and 2004,respectively.  In the first quarter of2007, the company wrote-off approximately $0.5 million of deferred financingfees in connection with an amendment to its credit facility (see Note 8).

***(o)******                                 Fair Value of Financial Instruments***

The carrying values of theCompany’s receivables, payables and debt are estimated to be substantially thesame as their fair values at December 31, 2006 and 2005.

***(p)******                                 Unitholders’ Capital***

The operations of the Company are governed by theprovisions of a limited liability company agreement executed by and among itsmembers.  The agreement includes specificprovisions with respect to the maintenance of the capital accounts of each ofthe Company’s unitholders.  The totalcapital contributed by the members as of December 31, 2005 was $16.3million.  Quantum Energy Partners’ shareof the contribution was $15.0 million.

Pursuant to applicable provisions of the DelawareLimited Liability Company Act (the “Delaware Act”) and the Second Amended andRestated Limited Liability Company Agreement of Linn Energy, LLC (the “Agreement”),unitholders have no liability for the debts, obligations and liabilities of theCompany, except as expressly required in the Agreement or the DelawareAct.  Pursuant to the terms of theAgreement, unitholders are entitled to vote on the following matters:

·  the annualelection of the Company’s Board of Directors;

·  specifiedamendments to the Agreement;

68

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

·  the mergerof the Company or the sale of all or substantially all of the Company’s assets;and

·  the dissolution of the Company.

The Company will remain in existence unless and until dissolved in accordancewith the terms of the Agreement.  SeeNote 4 for discussion of our Class B units and Class C units.

***(q)******                                 Operating Fee***

The Company is paid a monthlyoperating fee for each well it operates for outside owners.  The fee covers monthly operating and accountingcosts, insurance, and other recurring costs. As the operating fee is a reimbursement for costs incurred on behalf ofthird parties, the portion of the fee that exceeds the reimbursement ofoperating costs has been netted against general and administrativeexpense.  For the years endedDecember 31, 2006, 2005 and 2004, the operating fees netted againstgeneral and administrative expense were approximately $1.1 million, $1.2million and $0.6 million, respectively.

***(r)******                                   Income Taxes***

The Company is a limitedliability company treated as a partnership for federal and state income taxpurposes with all income tax liabilities and/or benefits of the Company beingpassed through to the unitholders.  Assuch, no recognition of federal or state income taxes for the Company or itssubsidiaries that are organized as limited liability companies have beenprovided for in the accompanying financial statements except as describedbelow.

Certain of the Company’ssubsidiaries are Subchapter C-corporations subject to corporate income taxes,which are accounted for under the provisions of SFAS No. 109 *“Accounting for Income Taxes”* (“SFAS 109”), which uses theasset and liability method.  Deferred taxassets and liabilities are recognized for the future tax consequences attributableto differences between the financial statement carrying amounts of existingassets and liabilities and their respective tax basis and operating loss andtax credit carryforwards.  Deferred taxassets and liabilities are measured using enacted tax rates expected to applyto taxable income in the years in which those temporary differences areexpected to be recovered or settled.  Theeffect on deferred tax assets and liabilities of a change in tax rates is recognizedin income in the period that includes the enactment date.  See Note 17 for detail of amounts recorded inour consolidated financial statements.

***(s)******                                   Revenue Recognition***

Sales of oil and gas arerecognized when oil or gas has been delivered to a custody transfer point,persuasive evidence of a sales arrangement exists, the rights andresponsibility of ownership pass to the purchaser upon delivery, collection ofrevenue from the sale is reasonably assured, and the sales price is fixed ordeterminable.  Oil and gas is sold by theCompany on a monthly basis.  Virtuallyall of the Company’s contracts’ pricing provisions are tied to a market index,with certain adjustments based on, among other factors, whether a well deliversto a gathering or transmission line, quality of oil and gas, and prevailingsupply and demand conditions, so that the price of the oil and gas fluctuate toremain competitive with other available oil and gas suppliers.

Gas imbalances occur when theCompany sells more or less than its entitled ownership percentage of total gasproduction.  Any amount received inexcess of the Company’s share is treated as a liability.  If the Company receives less than itsentitled share, the underproduction is recorded as a receivable.  The Company did not have any significant gasimbalance positions at December 31, 2006 or 2005.

Natural gas marketing is recordedon the gross accounting method because the Company takes title to the gas itpurchases from the various producers and bears the risks and enjoys thebenefits of that ownership.  Natural gasmarketing revenues and natural gas marketing expenses, titled as such, arereported on the consolidated statements of operations for the years endedDecember 31, 2006, 2005 and 2004.

The Company currently uses the “Net-Back”method of accounting for transportation arrangements of its gas sales.  The Company sells gas at the wellhead andcollects a price and recognizes revenues based on the wellhead sales pricesince transportation costs downstream of the wellhead are incurred by itscustomers and reflected in the wellhead price.

69

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

The Company generates electricitywith excess gas, which it uses to serve certain of its operating facilities inCalifornia.  Any excess electricity issold to the wholesale power market and the revenue is recorded on the accrualbasis.  This revenue is included in “otherincome” on the consolidated statements of operations.

***(t)******                                    Production Taxes***

Oil and gas revenues arepresented on a gross basis on the consolidated statements of operations.  Production taxes are included in operatingexpenses on the consolidated statements of operations and were approximately$2.0 million, $0.7 million and $0.4 million for the years endedDecember 31, 2006, 2005 and 2004, respectively.

***(u)******                                 Recently Issued Accounting Standards***

In June 2006, the FASB issuedFinancial Interpretation No. 48, *“Accounting forUncertainty in Income Taxes - an interpretation of FASB Statement No. 109”*(“FIN48”).  The interpretation sets forth a consistentrecognition threshold and measurement attribute, and criteria for subsequentlyrecognizing, derecognizing and measuring uncertain tax positions for financialstatement purposes.  FIN 48 also requiresexpanded disclosure with respect to the uncertainty in income taxes.  The interpretation is effective for fiscalyears beginning after December 31, 2006. The Company is currently evaluating the effect that the adoption of FIN48 will have on its results of operations and financial condition, but does notexpect it will have a material impact.

In September 2006, the FASBissued SFAS No. 157, *“Fair Value Measurements”*(“SFAS 157”), which provides guidance for using fair value to measure assetsand liabilities.  SFAS 157 applieswhenever other standards require (or permit) assets or liabilities to bemeasured at fair value and clarifies that for items that are not activelytraded, such as certain kinds of derivatives, fair value should reflect theprice in a transaction with a market participant, including an adjustment forrisk, not just the company’s mark-to-market value.  SFAS 157 also requires expanded disclosure ofthe effect on earnings for items measured using unobservable data.  The provisions of SFAS 157 are effective forfinancial statements issued for fiscal years beginning after November 15, 2007,and interim periods within those fiscal years. The Company is currently evaluating the effect that the implementationof SFAS 157 will have on its results of operations and financial condition, butdoes not expect it will have a material impact.

In September 2006, the SEC issued Staff AccountingBulletin No. 108 (“SAB 108”).  SAB 108expresses the SEC staff’s views regarding the process of quantifying financialstatement misstatements.  The SEC staff believesregistrants should quantify errors using both a balance sheet and an incomestatement approach and evaluate whether either approach results in quantifyinga misstatement that, when all relevant quantitative and qualitative factors areconsidered, is material.  The SEC staffwill not object if a registrant records a one-time cumulative effect adjustmentto correct errors existing in prior years that previously had been consideredimmaterial, quantitatively and qualitatively, based on appropriate use of theregistrant’s approach.  SAB 108 describesthe circumstances where this would be appropriate as well as requireddisclosures to investors.  SAB 108 iseffective for fiscal years ending on or after November 15, 2006.  The initial adoption of SAB 108 had noeffect on our results of operations or financial position.

70

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**LINN ENERGY, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

**(2)****                                 Acquisitions**

The Company accounts for its acquisitions using thepurchase method of accounting as prescribed in SFAS No. 141, “*Business Combinations.”* The following provides a summary of the Company’s acquisitions during2006 and 2005, as well as acquisitions subsequent to December 31, 2006.

***Acquisitions — 2006***

In the second quarter of 2006, the Company purchasedfrom the owners of property operated by Devonian Gas Production, Inc., ExcelEnergy, Inc. and T&F Exploration LP, oil and gas properties and tangiblewellhead equipment in West Virginia, for an aggregate purchase price ofapproximately $27.5 million.  Also in thesecond quarter of 2006, the Company purchased a gas gathering pipeline systemin western Pennsylvania for approximately $1.0 million.

In the third quarter of2006, the Company acquired certain affiliated entities of Blacksand Energy, LLC(“Blacksand”), located in the Los Angeles Basin, for an aggregate purchase price,including transaction costs and assumed liabilities, of approximately $301.0million and certain Mid-Continent assets of Kaiser-Francis Oil Company (“Kaiser-FrancisAssets”) located in Oklahoma for an aggregate purchase price, includingtransaction costs and assumed liabilities, of approximately $126.4 million.

The acquisition ofBlacksand was completed on August 1, 2006. The acquisition of the Kaiser-Francis Assets was completed on August 14,2006, effective September 1, 2006.  Theresults of operations of Blacksand and the Kaiser-Francis Assets are includedin the consolidated results of the Company effective August 1, 2006 andSeptember 1, 2006, respectively.

The acquisitions of theKaiser-Francis Assets and Blacksand were financed with a combination ofborrowings under our senior secured revolving credit facility and a $250.0million subordinated bridge loan (see Note 8).

The following table presents the aggregate purchaseprices of the Blacksand and Kaiser-Francis acquisitions as of the respective acquisitiondates:

|                                       | ** ** | **Blacksand**           | ** ** | **Kaiser-Francis** | ** ** |
|---------------------------------------|------------|-------------------------|------------|--------------------|------------|
| ** **                            | ** ** | **(in thousands)** | ** ** |
|                                  |       |                    |       |               |       |
| Cash                                  |       | $                       | 298,113    |               | $          | 125,000 |   |
| Estimated transaction  costs          |       | 472                     |       | 1,010              |       |
| Total purchase price                  |       | 298,585                 |       | 126,010            |       |
| Liabilities assumed                   |       | 2,373                   |       | 359                |       |
| Total purchase price plus liabilities |       | $                       | 300,958    |               | $          | 126,369 |   |

 

71

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**LINN ENERGY, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

The following table presents, as of the respectiveacquisition dates, allocations of the purchase prices based on estimates of fairvalue:

|                        | ** ** | **Blacksand**           | ** ** | **Kaiser-Francis** | ** ** |
|------------------------|------------|-------------------------|------------|--------------------|------------|
| ** **             | ** ** | **(in thousands)** | ** ** |
|                   |       |                    |       |               |       |
| Field inventory        |       | $                       | 284        |               | $          | — |   |
| Oil and gas properties |       | 300,187                 |       | 126,369            |       |
| Vehicles and buildings |       | 487                     |       | —             |       |
|                   |       | $                       | 300,958    |               | $          | 126,369 |   |

 

The purchase price allocations are based onindependent appraisals, discounted cash flows, quoted market prices andestimates by management.  The most significant assumptions related to theestimated fair values assigned to proved and unproved oil and gasproperties.  To estimate the fair valuesof these properties, we prepared estimates of oil and gas reserves.  We estimated future prices to apply to theestimated reserve quantities acquired, and estimated future operating anddevelopment costs, to arrive at estimates of future net revenues.  For estimated proved reserves, the future netrevenues were discounted using a market-based weighted average cost of capitalrate determined appropriate at the time of the acquisition.  The market-based weighted average cost ofcapital rate was subjected to additional project-specific risking factors.  To compensate for the inherent risk ofestimating and valuing unproved properties, the discounted future net revenuesof probable and possible reserves were reduced by additional risk-weightingfactors.  In addition, when appropriate,the Company also reviewed comparable purchases and sales of oil and gasproperties within the same regions, and used that data as a proxy for fairmarket value; i.e., the amount a willing buyer and seller would enter into anexchange for such properties.

The following unaudited pro formafinancial information presents a summary of Linn’s consolidated results ofoperations for the years ended December 31, 2006 and 2005, assuming theacquisitions of Blacksand, the Kaiser-Francis Assets and Exploration Partners,LLC (“Exploration Partners”) had been completed as of January 1, 2005,including adjustments to reflect the allocation of the purchase prices to theacquired net assets.  The ExplorationPartners acquisition (see “Acquisitions — 2005” below) was effective October27, 2005, and its results are included in the actual results of the Company asof that date.  The pro forma financialinformation is not necessarily indicative of the results of operations if theacquisitions had been effective as of these dates.

|                              | ** ** | **For the Year Ended  December 31,** | ** ** |
|------------------------------|------------|----------------------------------------------------------|------------|
| ** **                   | ** ** | **2006**                                                 | ** ** | **2005** | ** ** |
| ** **                   | ** ** | **(in thousands)**                                  | ** ** |
|                         |       |                                                     |       |   |   |
| Total revenues               |       | $                                                        | 255,686    |   | $ | 34,656 |   |
| Total operating  expenses    |       | 105,974                                                  |       | 55,580 |   |
| Net income (loss)            |       | 104,142                                                  |       | (70,926 | ) |
|                         |       |                                                     |       |   |   |
| Net income (loss) per  unit: |       |                                                     |       |   |   |
| Units - basic                |       | $                                                        | 3.47       |   | $ | (3.46 | ) |
| Units - diluted              |       | $                                                        | 3.43       |   | $ | (3.46 | ) |
|                         |       |                                                     |       |   |   |
| Class B units -  basic       |       | $                                                        | 3.47       |   | $ | —— |   |
| Class B units - diluted      |       | $                                                        | 3.43       |   | $ | —— |   |

 

The pro forma results ofoperations present net income (loss) per unit allocated to the units and ClassB units.  In January 2007, at a specialmeeting of Linn unitholders, unitholders approved the one-for-one conversion ofeach of the Class B units into units (see Note 4).  Therefore, pro forma net income (loss) perunit assumes that the units and Class B units share equally in the pro formanet income (loss) of the Company.

72

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**LINN ENERGY, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

The pro forma results ofoperations for the year ended December 31, 2006 includes a Blacksandhistorical gain on property sale of $32.7 million.  Had this gain been excluded, pro forma netincome for the year ended December 31, 2006 would have been reduced by thegain recorded.

***Acquisitions— 2005***

In the second quarter of 2005, the Company purchasedfrom Columbia Natural Resources, LLC, oil and gas properties, tangible wellheadequipment and a gathering system in West Virginia and western Virginia, for apurchase price of $4.4 million.  In thethird quarter of 2005, the Company purchased, from GasSearch Corporation, oiland gas properties and tangible wellhead equipment in West Virginia, for apurchase price of $5.4 million and from Exploration Partners, oil and gasproperties, oil field equipment and tangible wellhead equipment in WestVirginia and Virginia, for a purchase price of $111.4 million.  Results ofoperations for each acquisition are included in the consolidated results ofoperations of the Company as of the acquisition dates.

***SubsequentEvent — Acquisitions***

On February 1, 2007, effective January 1, 2007, theCompany completed the acquisition of certain oil and gas properties and relatedassets in the Texas Panhandle from Cavallo Energy LP, acting through itsgeneral partner, Stallion Energy LLC (“Stallion”) for a contract price of$415.0 million, subject to customary post-closing adjustments.  In addition, in January 2007, the Companycompleted the acquisitions of certain gas properties located in the AppalachianBasin of West Virginia for an aggregate contract price of $39.0 million,subject to customary post-closing adjustments. The purchase price includes a payment of $20.0 million paid by theCompany to the seller in December 2006. At December 31, 2006, this amount is reported separately on theconsolidated balance sheet within other assets, along with Stallion acquisitioncosts incurred prior to year end.  Theseacquisitions were financed with a combination of private placements of ourunits (see Note 4) and borrowings under the Company’s senior secured revolving credit facility.  In connection with these acquisitions, theCompany amended its credit facility to increase the borrowing base from $480.0million to $725.0 million (see Note 8).

The following table presents the preliminary purchaseprice for the Stallion acquisition based on preliminary estimates of fairvalue:

|                                       | ** ** | **Stallion**            | ** ** |
|---------------------------------------|------------|-------------------------|------------|
| ** **                            | ** ** | **(in thousands)** | ** ** |
|                                  |       |                    |       |
| Cash                                  |       | $                       | 409,763    |   |
| Estimated transaction  costs          |       | 3,300                   |       |
| Total purchase price                  |       | 413,063                 |       |
| Liabilities assumed                   |       | 912                     |       |
| Total purchase price plus liabilities |       | $                       | 413,975    |   |

 

The following table presents the preliminaryallocation of the purchase price based on preliminary estimates of fair value:

|                                       | ** ** | **Stallion**            | ** ** |
|---------------------------------------|------------|-------------------------|------------|
| ** **                            | ** ** | **(in thousands)** | ** ** |
|                                  |       |                    |       |
| Oil and gas properties                |       | $                       | 413,494    |   |
| Vehicles and buildings                |       | 481                     |       |
| Total purchase price plus liabilities |       | $                       | 413,975    |   |

 

The preliminary purchase price allocation is based onpreliminary information and estimates by management as final appraisals ofassets acquired and liabilities assumed are not yet complete.  The purchase price allocation will becompleted within one year of the acquisition date.

73

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**LINN ENERGY, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

**(3)****                                 Initial Public Offering**

In the first quarter of 2006, theCompany completed its IPO of 12,450,000 units representing limited liabilityinterest in the Company at $21.00 per unit, for net proceeds, afterunderwriting discounts of $18.3 million and offering expenses of $4.3 million,of $238.8 million, of which $122.0 million was used to reduce indebtednessunder the Company’s senior secured revolving credit facility and repay, infull, the subordinated term loan, $114.4 million was used to redeem a portionof the membership interests in the Company and units held by certain affiliatedand non-affiliated holders and approximately $2.0 million was used to paybonuses to certain executive officers of the Company.

**(4)****                                 Private Placements of Equity**

***Class B Units***

In October 2006, the Companycompleted a Class B Unit and Unit Purchase Agreement with a group of institutional investors whereby it privately placed 9,185,965 Class Bunits at a price of $20.55 per unit, and 5,534,687 units at a price of $21.00per unit, for aggregate gross proceeds of $305.0 million (the “Class B PrivatePlacement”).  In January 2007, at aspecial meeting of Linn unitholders, unitholders approved the one-for-oneconversion of each of the Class B units into units.  In connection with the Class B PrivatePlacement, the Company agreed to file a registration statement with the SECcovering the units and the units underlying the Class B units.  In accordance with the agreement, theregistration statement must be declared effective by the SEC no later than 210days following the closing (extended by separate agreement from 165 days).

All proceeds from the Class BPrivate Placement were used to repay in full the Company’s $250.0 millionsubordinated bridge loan and $53.3 million of borrowings under its creditfacility (see Note 8).  In connectionwith the repayment of the subordinated bridge loan, the Company wrote offapproximately $2.7 million of deferred financing fees, which was recognized asexpense in the fourth quarter of 2006.

***Subsequent Event — Class CUnits***

In February 2007, the Company completed a Class C Unit and UnitPurchase Agreement with a group ofinstitutional investors whereby it privately placed 7,465,946 Class Cunits at a price of $25.06 per unit, and 6,650,144 units at a price of $26.00per unit, for aggregate gross proceeds of $360.0 million (the “Class C PrivatePlacement”).  The proceeds from the ClassC Private Placement were used to finance the Stallion acquisition and theacquisitions of certain gas properties in West Virginia (see Note 2).

The Class C units represent a new class of equitysecurities that is entitled to a special quarterly distribution equal to 115%of the distribution received by the existing units.  The Class C units have no voting rights otherthan as required by law and are subordinated to the units on dissolution andliquidation.  If approved by a vote ofthe Company’s unitholders at the special meeting to be held in April 2007, theClass C units will convert to unitson a one-for-one basis.  In connectionwith the Class C Private Placement, the Company agreed to file a registrationstatement with the SEC covering the units and the units underlying the Class Cunits.  In accordance with the agreement,the registration statement must be declared effective by the SEC no later than 165days following the closing.

Under the terms of the Class B Private Placement andthe Class C Private Placement, if the registration statements are not declaredeffective in accordance with the respective agreements, the Company could berequired to pay purchasers, as liquidated damages and not as a penalty, certainamounts as defined in the agreements. The Company does not believe it is probable that it will be required tomake such payments; therefore, has not recorded a liability at this time.  Such amounts, if any, would not be expected tobe material to the Company’s financial position or results of operations.

74

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**LINN ENERGY, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

**(5)****                                 Business and Credit Concentrations**

***Cash***

The Company maintains its cash inbank deposit accounts, which, at times, may exceed federally insuredamounts.  The Company has not experiencedany losses in such accounts.  The Companybelieves it is not exposed to any significant credit risk on its cash.

***Revenue and Trade Receivables***

The Company has a concentrationof customers who are engaged in oil and gas production within the UnitedStates.  This concentration of customersmay impact the Company’s overall exposure to credit risk, either positively ornegatively, in that the customers may be similarly affected by changes ineconomic or other conditions.  TheCompany performs ongoing credit evaluations of its customers and typically doesnot require collateral.

A majority of the Company’slargest customers are oil and gas producers, suppliers and operators.  For the year ended December 31, 2006,the Company’s two largest customers represented 54% and 17% of the Company’ssales.  The Company’s three largestcustomers represented approximately 48%, 14%, and 10% of the Company’s salesfor the year ended December 31, 2005. For the year ended December 31, 2004, the Company’s four largestcustomers represented approximately 33%, 19%, 16%, and 13% of the Company’ssales.

At December 31, 2006, threecustomers’ trade accounts receivable from oil and gas sales accounted for morethan 10% of the Company’s total trade accounts receivable.  As of December 31, 2006, trade accountsreceivable from our three largest customers represented approximately 41%, 22%and 16% of the Company’s receivables.  AtDecember 31, 2005, two customers’ trade accounts receivable from oil andgas sales accounted for more than 10% of the Company’s total trade accountsreceivable.  Trade accounts receivablefor the two largest customers represented approximately 70% and 13% of theCompany’s receivables as of December 31, 2005.

**(6)****                                 Property and Equipment**

Property and equipment consists of the following:

|                                       | ** ** | **December 31,**   | ** ** |
|---------------------------------------|------------|-------------------------|------------|
| ** **                            | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                            | ** ** | **(in thousands)** | ** ** |
|                                  |       |                    |       |   |   |
| Land                                  |       | $                       | 308        |   | $ | 203 |   |
| Buildings and leasehold  improvements |       | 2,759                   |       | 608 |   |
| Vehicles                              |       | 3,097                   |       | 1,317 |   |
| Aircraft                              |       | 5,890                   |       | — |   |
| Drilling equipment                    |       | 8,611                   |       | — |   |
| Furniture and equipment               |       | 1,966                   |       | 888 |   |
|                                  |       | 22,631                  |       | 3,016 |   |
|                                  |       |                    |       |   |   |
| Less: accumulated  depreciation       |       | (1,877                  | )          | (491 | ) |
|                                  |       |                    |       |   |   |
|                                  |       | $                       | 20,754     |   | $ | 2,525 |   |

 

Depreciation expense onthe above assets for the years ended December 31, 2006, 2005 and 2004 wasapproximately $1.4 million, $0.9 million and $0.2 million, respectively.

75

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**LINN ENERGY, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

**(7)****                                 Unit-Based Compensation and Other Benefit Plans**

***Incentive Plan Summary***

The Linn Energy, LLC Long-Term Incentive Plan (the “Plan”) becameeffective in December 2005.  The Plan,which is administered by the Compensation Committee of the Board of Directors,permits the granting of unit grants, unit options, restricted units, phantomunits and unit appreciation rights to employees, consultants and non-employeedirectors under the terms of the Plan. The unit options and restricted units vest ratably over one to threeyears from the grant date of the award, unless other contractual arrangementsare made.  The contractual life of unitoptions is 10 years.  Unit awards wereissued for the first time in January 2006, in conjunction with the Company’sIPO.  No unit options were exercisedduring the year ended December 31, 2006.

The Plan limits the number of units that may be delivered pursuant toawards to 3.9 million units, provided that no more than 1.5 million units(increased from 500,000 units by a January 2007 Plan amendment) may be issuedas restricted units.  The Board ofDirectors and the Compensation Committee of the Board of Directors have theright to alter or amend the Plan or any part of the Plan from time to time,including increasing the number of units that may be granted, subject tounitholder approval as required by the exchange upon which the units are listedat that time.  However, no change in anyoutstanding grant may be made that would materially reduce the benefits to theparticipant without the consent of the participant.

Upon exercise or vesting of an award of, or settled in, units, theCompany will issue new units, acquire units on the open market or directly fromany person or use any combination of the foregoing, at the CompensationCommittee’s discretion.  If we issue newunits upon exercise or vesting of an award of, or settled in, units, the totalnumber of units outstanding will increase. To date, the Company has issued awards of unit grants, unit options,restricted units and phantom units.  ThePlan provides for all of the following types of awards:

*Unit Grants*  A unit grant is a unit that vests immediatelyupon issuance.

*Unit Options*  A unit option is a right to purchase a unitat a specified price at terms determined by the Compensation Committee.  Unit options will have an exercise price thatwill not be less than the fair market value of the units on the date of grant,and in general, will become exercisable over a vesting period but mayaccelerate upon the achievement of specified financial objectives, or upon achange in control of the Company.  If agrantee’s employment or relationship terminates for any reason, the grantee’sunvested unit options will be automatically forfeited unless the optionagreement or the Compensation Committee provides otherwise.

*Restricted Units*  A restricted unit is a unit that vests over aperiod of time and that during such time is subject to forfeiture, and maycontain such terms as the Compensation Committee shall determine, including theperiod over which restricted units (and distributions related to such units)will vest.  The Company intends therestricted units under the plan to serve as a means of incentive compensationfor performance and not primarily as an opportunity to participate in theequity appreciation of our units. Therefore, plan participants will not pay any consideration for therestricted units they receive.  If agrantee’s employment, consulting relationship or membership on the Board ofDirectors terminates for any reason, the grantee’s unvested restricted unitswill be automatically forfeited unless the Compensation Committee or the termsof the award agreement provide otherwise.

*Phantom Units/Unit Appreciation Rights*  These awards may be settled in units, cash ora combination thereof.  Such grants willcontain terms as determined by the Compensation Committee, including the periodor terms over which phantom units will vest. If a grantee’s employment or service relationship terminates for anyreason, the grantee’s phantom units or unit appreciation rights will be automaticallyforfeited unless, and to the extent, the Compensation Committee or the terms ofthe award agreement provide otherwise. While phantom units require no payment from the grantee, unitappreciation rights will have an exercise price that will not be less than thefair market value of the units on the date of grant.  At December 31, 2006, the Company had9,000 phantom units issued and outstanding. To date, the Company has not issued unit appreciation rights.

76

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**LINN ENERGY, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

***Securities Authorized forIssuance Under the Plan***

As of December 31, 2006, approximately 2.1 million units wereissuable under the Plan pursuant to outstanding award or other agreements andan additional 1.7 million units were reserved for future issuance under thePlan.

***Accounting for Unit-BasedCompensation***

SFAS 123R requires an entity to recognize as expense beginning at thegrant date, the fair value of unit options and other equity-based compensationissued to employees and non-employee directors. The value of the portion of the award that is ultimately expected tovest is recognized as expense over the requisite service period using thestraight-line method in the Company’s consolidated statements of operations.

SFAS 123R provides specific guidance on income tax accounting andclarifies how SFAS No.109, *“Accounting for IncomeTaxes*” (“SFAS 109”) should be applied to unit-basedcompensation.  For example, the expensefor types of option grants is only deductible for tax purposes at the time thatthe taxable event takes place.  SFAS 123Rdoes not allow companies to “predict” when these taxable events will takeplace.  Furthermore, it requires that thebenefits associated with the tax deductions in excess of recognized compensationcost be reported as a financing cash flow, rather than as an operating cashflow as required under SFAS No. 123 *“Accounting forStock-Based Compensation.”* This requirement will reduce net operating cash flows and increase netfinancing cash flows.  These futureamounts cannot be estimated, because they depend on, among other things, whenemployees exercise unit options.

For the year ended, December 31, 2006, we recorded unit-basedcompensation expense of approximately $21.6 million, as a charge against incomebefore income taxes and it is included in general and administrative expense onthe consolidated statement of operations. No related income tax benefit was recognized due to non-deductibility andrecognition of a valuation allowance for resulting net operating losses.  The Company recorded no unit-basedcompensation for the years ended December 31, 2005 or 2004, as there wereno unit-based awards granted during those periods.

***Restricted/UnrestrictedUnits***

The fair value of unrestricted unit grants and restricted units issuedis determined based on the fair market value of the Company units on the dateof grant.  This value is amortized overthe vesting period, which varied from one month to two years from the date ofgrant for certain officers.  A summary ofthe status of the non-vested units as of December 31, 2006, is presentedbelow:

|                                             | ** ** | **Number of  Non-vested  Units** | ** ** | **Weighted  Average  Grant Date  Fair Value** | ** ** |
|---------------------------------------------|------------|---------------------------------------|------------|---------------------------------------------------------|------------|
| Non-vested units  at December 31, 2005 |       | —                                |       | $                                                       | —     |   |
| Granted                                     |       | 1,239,145                             |       | 22.98                                                   |       |
| Vested                                      |       | (114,455                              | )          | 21.00                                                   |       |
| Forfeited                                   |       | —                                |       | —                                                  |       |
|                                        |       |                                  |       |                                                    |       |
| Non-vested units at  December 31, 2006 |       | 1,124,690                             |       | $                                                       | 23.19      |   |

 

As of December 31, 2006, there was approximately $7.5 million ofunrecognized compensation cost related to non-vested restricted units.  The cost is expected to be recognized over aweighted average period of approximately 1.3 years.  The total fair value of units that vestedduring the period was approximately $2.4 million.  The terms of these units provided immediatevesting at the grant date.  Subsequent toDecember 31, 2006, the Company granted an aggregate 400,500 restrictedunits to employees as part of its annual review of employee compensation and50,000 restricted units to a new officer of the Company.

77

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**LINNENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

***Changes in Unit Options and Unit OptionsOutstanding***

The following table provides information related tounit option activity for the year ended December 31, 2006:

| `                                      | ** ** | **Number of  Units  Underlying  Options** | ** ** | **Weighted  Average  Exercise Price  Per Unit** | ** ** | **Weighted  Average  Grant Date  Fair Value** | ** ** | **Weighted  Average  Remaining  Contractual  Life in Years** | ** ** |
|----------------------------------------|------------|------------------------------------------------|------------|-----------------------------------------------------------|------------|---------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| Outstanding at  December 31, 2005 |       | —                                         |       | $                                                         | —     |                                                    | $          | —                                                                 |       |   |   |
| Granted                                |       | 1,019,584                                      |       | 23.90                                                     |       | 3.59                                                    |       |                                                                   |       |
| Exercised                              |       | —                                         |       | —                                                    |       | —                                                  |       |                                                                   |       |
| Forfeited                              |       | (89,084                                        | )          | 20.39                                                     |       | 2.62                                                    |       |                                                                   |       |
|                                   |       |                                           |       |                                                      |       |                                                    |       |                                                                   |       |
| Outstanding at  December 31, 2006 |       | 930,500                                        |       | $                                                         | 24.24      |                                                    | $          | 3.68                                                                   |       | 9.51 |   |
|                                   |       |                                           |       |                                                      |       |                                                    |       |                                                                   |       |
| Exercisable at December 31, 2006  |       | 30,000                                         |       | $                                                         | 20.18      |                                                    | $          | 2.52                                                                   |       | 9.17 |   |

 

The following table summarizes information about unit optionsoutstanding at December 31, 2006:

|                                     | ** ** | **Options Outstanding**                             | ** ** | **Options Exercisable**                            | ** ** |
|-------------------------------------|------------|----------------------------------------------------------|------------|---------------------------------------------------------|------------|
| **Range of  Exercise  Prices** | ** ** | **Number  Outstanding at  December 31,  2006** | ** ** | **Weighted  Average  Remaining  Contractual Life** | ** ** | **Weighted  Average  Exercise  Prices** | ** ** | **Number  Exercisable at  December 31,  2006** | ** ** | **Weighted  Average  Exercise  Prices** | ** ** |
| $19.74 - $23.50(a)                  |       | 499,500                                                  |       | 9.15                                                    |       | $ | 20.61 |   | 30,000 |   | $ | 20.18 |   |
| $27.94 - $32.18(b)                  |       | 431,000                                                  |       | 9.92                                                    |       | $ | 28.43 |   | — |   |   |   |
|                                |       | 930,500                                                  |       |                                                    |       |   |   | 30,000 |   |   |   |
|                                     |            |                                                          |            |                                                         |            |  |  |  |  |  |  |  |  |

----

(a)  Represents options issued between January andAugust 2006.

(b)  Represents options issued in December 2006.

As of December 31, 2006, there was approximately $2.7 million oftotal unrecognized compensation cost related to non-vested unit options.  The cost is expected to be recognized over aweighted average period of approximately 1.8 years.  In addition, the exercisable unit options atDecember 31, 2006 have an aggregate intrinsic value of approximately $0.4million and all outstanding unit options have an aggregate intrinsic value ofapproximately $7.2 million.  The totalfair value of all options that vested during the year was approximately$76,000.  No options expired during theyear.  Subsequent to December 31,2006, the Company granted 50,000 unit options to a new officer of the Company.

The fair value of unit-based compensation for unit options wasestimated on the date of grant using a Black-Scholes pricing model based oncertain assumptions.  The Company’sdetermination of the fair value of unit-based payment awards is affected by theCompany’s unit price as well as assumptions regarding a number of highlycomplex and subjective variables.  TheCompany’s employee unit options have various restrictions including vestingprovisions and restrictions on transfers and hedging, among others, and oftenare expected to be exercised prior to their contractual maturity.  Expected volatilities used in the estimationof fair value have been determined using available volatility data for theCompany as well as an average of volatility computations of other identifiedpeer companies in the oil and gas industry. Expected distributions are estimated based on the Company’s distributionrate at the date of grant.  Historicaldata of the Company and other identified peer companies is used to estimateunit option exercises and expected term. Forfeitures are estimated using historical Company data and are revised,if necessary, in subsequent periods if actual forfeitures differ from estimates.  All employees granted awards have beendetermined to have similar behaviors for purposes of determining the expectedterm used to estimate fair value.  The 

78

----

**LINNENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

risk-free rate for periods within the contractual term of the unitoption is based on the U.S. Treasury yield curve in effect at the time ofgrant.  The fair values of the unitoption grants were based upon the following assumptions:
| Expected volatility    |   | 29.70 | %     |  -  |   |     31.30% |   |
|------------------------|--------|-------|-------|---------------|--------|--------------------------------|--------|
| Expected distributions |   | 7.20  | %     |  -  |   | 8.50%                          |   |
| Risk free rate         |   | 4.31  | %     |  -  |   | 5.04%                          |   |
| Expected term          |   | 5.0   | years |          |   |                           |   |

 

Although the fair value of unit option grants is determined inaccordance with SFAS 123R using a Black-Scholes option-pricing model, thatvalue may not be indicative of the fair value observed in a willingbuyer/willing seller market transaction.

***Defined Contribution Plan***

The Company sponsors a 401(k) defined contribution plan for eligibleemployees, effective in January 2005. Company contributions to the 401(k) plan consist of a discretionarymatching contribution equal to 100% of the first 4% of eligible compensationcontributed by the employee on a before-tax basis.  The Company contributed approximately $0.2million and $0.1 million during the years ended December 31, 2006 and2005, respectively, to the 401(k) plan’s trustee account.  The 401(k) plan funds are held in a trusteeaccount on behalf of the plan participants.

**(8)           Debt**

***Credit Facility***

AtDecember 31, 2006, the Company had an $800.0 million senior securedrevolving credit facility with a maturity of August 2010, and a borrowing baseof $480.0 million (“Credit Facility”). In February 2007, in conjunction with the Stallion acquisition and twoacquisitions in West Virginia (see Note 2) the Company amended its CreditFacility, increasing the borrowing base to $725.0 million.  In connection with this amendment, in thefirst quarter of 2007, the Company paid fees of approximately $1.5 million,which will be amortized over the remaining term of the Credit Facility, andwrote-off deferred financing fees of approximately $0.5 million.

Theborrowing base under the Credit Facility will be redetermined semi-annually bythe lenders in their sole discretion, based on, among other things, reservereports as prepared by reserve engineers taking into account the oil and gasprices at such time.  Our obligationsunder the Credit Facility are secured by mortgages on our oil and gasproperties as well as a pledge of all ownership interests in our operatingsubsidiaries.  We are required tomaintain the mortgages on properties representing at least 80% of our oil andgas properties.  Additionally, theobligations under the Credit Facility are guaranteed by all of our operatingsubsidiaries and may be guaranteed by any future subsidiaries.

Atour election, interest on the Credit Facility is determined by reference toLIBOR plus an applicable margin between 1.00% and 1.75% per annum; or adomestic bank rate plus an applicable margin between 0.00% and 0.25% per annum.  LIBOR margins increased by 0.25% during theterm of the Subordinated Bridge Loan, which was repaid in October 2006.  Interest is payable quarterly for domesticbank rate loans and at the applicable maturity date for LIBOR loans.

The Credit Facilitycontains various covenants that limit the Company’s ability to incur additionalindebtedness, make acquisitions or certain capital expenditures; makedistributions other than from available cash; merge or consolidate; and engagein certain asset dispositions.  The CreditFacility also contains covenants that, among other things, require us tomaintain the following financial ratios:

·                  consolidatednet income plus interest expense, income taxes, depreciation, depletion,amortization and other similar changes, minus all non-cash income added toconsolidated net income, and giving pro forma effect to any acquisitions orcapital expenditures, to interest expense of not less than 2.5 to 1.0

·                  consolidatedcurrent assets, including the unused amount of the total commitments, toconsolidated current liabilities of not less than 1.0 to 1.0, excludingnon-cash assets and liabilities under SFAS 133, which includes the currentportion of oil and gas and interest rate derivatives

79

----

**LINNENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

The Credit Facility doesnot contain a minimum debt to equity ratio requirement.  The Company is in compliance with allfinancial and other covenants of its Credit Facility.

As of December 31,2006 and 2005, the Credit Facility consisted of the following:

|                           | ** ** | **December 31,**   | ** ** |
|---------------------------|------------|-------------------------|------------|
| ** **                | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                | ** ** | **(in thousands)** | ** ** |
|                      |       |                    |       |   |   |
| Total (1)                 |       | $                       | 425,750    |   | $ | 207,113 |   |
| Less: Current  maturities |       | —                  |       | (113 | ) |
|                      |       | $                       | 425,750    |   | $ | 207,000 |   |

----

(1)       Variable rate of 7.125% and6.110% at December 31, 2006 and 2005, respectively

AtDecember 31, 2006, the Company also had $4.0 million outstanding lettersof credit, which reduce its borrowing availability under the CreditFacility.  At December 31, 2006,available borrowing under our Credit Facility was $50.2 million.

Totalaccrued interest on the Credit Facility was approximately $2.1 million atDecember 31, 2006.  Total accruedinterest on the prior credit facility was approximately $1.1 million atDecember 31, 2005.  The Companyrepaid $53.3 million of borrowingsunder its Credit Facility in October 2006 (see****Note 4).

***Subordinated Bridge Loan***

In August 2006, in order to fund a portion of the acquisitions ofBlacksand and the Kaiser-Francis Assets, we entered into a $250.0 millionsubordinated bridge loan (“Subordinated Bridge Loan”) with a termination ofAugust 1, 2007.  At our election,interest was determined by reference to LIBOR plus an applicable margin of4.00% per annum; or a domestic bank rate plus an applicable margin of 2.50% perannum.  In October 2006, all proceedsfrom the Class B Private Placement (see Note 4) were used to repay in full theCompany’s $250.0 million Subordinated Bridge Loan.  In connection with the repayment of theSubordinated Bridge Loan, the Company wrote off approximately $2.7 million ofdeferred financing fees, which was recognized as expense in the fourth quarterof 2006.

***Subordinated Term Loan***

During 2005, the Companyhad a $60.0 million second lien senior subordinated term loan.  The borrowings under the subordinated termloan were used to fund a portion of the purchase price for the acquisition ofoil and gas properties from Exploration Partners.  The outstanding balance was paid in full in2006, with proceeds from our IPO.  Totalaccrued interest on this loan was approximately $0.4 million atDecember 31, 2005.

80

----

**LINNENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

**(9)****                                 Long-term Notes Payable**

The Company has the followinglong-term notes payable outstanding:

|                                                                                                                                                                                                                                                                                                                                                              | ** ** | **December 31,**   | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                                                                                                                                                                                                                                                                                                   | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                                                                                                                                                                                                                                                                                                                                   | ** ** | **(in thousands)** | ** ** |
| Note payable to a bank  with an interest rate of 6.14%, payable in monthly installments of $3  including interest, through September 2024. The note is secured by an office  building.                                                                                                                                                                       |       | $                       | 372        |   | $ | 387 |   |
| Various notes for the  purchase of vehicles and equipment, payable in monthly installments totaling  approximately $88 and $11 as of December 31, 2006 and 2005,  respectively, including interest. The interest rates range from 3.9%-9.11%.  The notes are secured by the vehicles purchased and expire at various dates  from 2008 through 2011. (1) |       | 2,989                   |       | 421 |   |
|                                                                                                                                                                                                                                                                                                                                                         |       | 3,361                   |       | 808 |   |
| Less current portion                                                                                                                                                                                                                                                                                                                                         |       | (874                    | )          | (113 | ) |
|                                                                                                                                                                                                                                                                                                                                                         |       | $                       | 2,487      |   | $ | 695 |   |

----

(1)       At December 31, 2006, includes approximately $1.0 million of notespayable on which interest was imputed at 7.0%.

As of December 31, 2006,maturities on the aforementioned long-term notes payable were as follows:

|            | ** ** | **(in thousands)** | ** ** |
|------------|------------|-------------------------|------------|
|       |       |                    |       |
| 2007       |       | $                       | 874        |   |
| 2008       |       | 870                     |       |
| 2009       |       | 641                     |       |
| 2010       |       | 446                     |       |
| 2011       |       | 229                     |       |
| Thereafter |       | 301                     |       |
|       |       | $                       | 3,361      |   |

 

**(10)****                          Interest Rate Swaps**

We have periodically entered intointerest rate swap agreements to minimize the effect of fluctuations ininterest rates.  We are required to payour counterparties the difference between and the fixed rate in the contractand the actual rate if the actual rate is lower than the fixed rate andconversely, our counterparties are required to pay us if the actual rate ishigher than the fixed rate in the contract. We did not designate the interest rate swap agreements we entered intoas cash flow hedges under SFAS 133; therefore, the changes in fair value ofthese instruments were recorded in our current earnings.  These amounts are non-cash gains or losses.

The following summarizes theCompany’s interest rate swaps outstanding:

|                                           | ** ** | **December 31,**   | ** ** |
|-------------------------------------------|------------|-------------------------|------------|
| ** **                                | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                | ** ** | **(in thousands)** | ** ** |
|                                      |       |                    |       |   |   |
| Long-term liability,  interest rate swaps |       | $                       | 423        |   | $ | 663 |   |
| Less current asset                        |       | (44                     | )          | (202 | ) |
|                                      |       | $                       | 379        |   | $ | 461 |   |

 

81

----

**LINNENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

Unrealized gains (losses) due tothe change in the fair value of approximately $82,000 in 2006, $1.0 million in2005 and $(1.3) million in 2004 are recorded in interest and financing expensein the consolidated statements of operations.

The following presents theinterest rate swaps entered into during the year ended December 31, 2004(the Company has not entered into any additional interest rate swaps):

|                                                  | ** ** | **Notional  Amount**    | ** ** |
|--------------------------------------------------|------------|-------------------------|------------|
| ** **                                       | ** ** | **(in thousands)** | ** ** |
|                                             |       |                    |       |
| Interest rate, 5.79%,  settles quarterly in 2008 |       | $                       | 50,000     |   |
| Interest rate, 5.30% , settles quarterly in 2007 |       | $                       | 50,000     |   |
| Interest rate,  4.42%, settled quarterly in 2006 |       | $                       | 20,000     |   |
| Interest rate, 3.08%, settled quarterly in 2005  |       | $                       | 20,000     |   |

 

**(11)****                          Asset Retirement Obligation**

The Company accounts for assetretirement obligations in accordance with SFAS 143, which requires that thefair value of a liability for an asset retirement obligation be recognized inthe period in which it is incurred if a reasonable estimate of fair value canbe made.  The associated asset retirementcost is capitalized as part of the carrying amount of the long-livedasset.  Subsequently, the assetretirement cost is allocated to expense using a systematic and rational methodover the asset’s useful life.  The assetretirement obligations recorded by the Company relate to the plugging andabandonment of oil and gas wells.

At December 31, 2006 and2005, there were no assets legally restricted for purposes of settling assetretirement obligations.  Additionalretirement obligations increase the liability associated with new oil and gaswells and other facilities as these obligations are incurred.  Under certain operating agreements, theCompany withholds funds from the working interest owners for future pluggingcosts.  These liabilities from theamounts withheld are included in the total asset retirement obligation on theaccompanying consolidated balance sheets.

The following table reflects thechanges in the asset retirement obligation during the years presented:

|                                                                                                     | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                          | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                          | ** ** | **(in thousands)**                    | ** ** |
| Carrying amount of  asset retirement obligation at beginning of year                                |       | $                                          | 5,443      |   | $ | 3,857 |   | $ | 2,053 |   |
| Liabilities added  during the current year related to acquisitions or drilling of additional  wells |       | 2,806                                      |       | 1,390 |   | 1,711 |   |
| Cash withheld during  the current year from unrelated third parties who own working interests       |       | 31                                         |       | 24 |   | 19 |   |
| Current year accretion  expense                                                                     |       | 314                                        |       | 172 |   | 74 |   |
| Carrying amount of asset retirement obligation at end of year                                       |       | $                                          | 8,594      |   | $ | 5,443 |   | $ | 3,857 |   |

 

The discount rate used incalculating the asset retirement obligation was 7.0%, 5.8% and 4.3% in 2006,2005 and 2004, respectively.  These ratesapproximate the Company’s credit adjusted risk-free rates.  See Note 8.

**(12)****                          Commitments and Contingencies**

The Company would be exposed tooil and gas price fluctuations on underlying sale contracts should thecounterparties to the Company’s derivative instruments or the counterparties tothe Company’s oil and gas marketing contracts not perform.  Such nonperformance is not anticipated.  There were no counterparty default lossesduring the years ended December 31, 2006, 2005 or 2004.

82

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**LINNENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

From time to time the Company isa party to various legal proceedings or is subject to industry rulings thatcould bring rise to claims in the ordinary course of business.  The Company is not currently a party to anylitigation or pending claims that it believes would have a materially adverseeffect on the Company’s business, financial condition, results of operations orliquidity.

**(13)****                          Related Party Transactions**

For the year ended December 31, 2006, theCompany made payments of approximately $0.4 million to a company ownedby one of our senior executives.  Thepayments reflect reimbursement for maintenance and hourly usage fees forbusiness use of an aircraft that was partially owned by the seniorexecutive.  These costs are included ingeneral and administrative expense on the consolidated statement ofoperations.  The fees and expensesassociated with the reimbursements were consummated on terms equivalent tothose that prevail in arm’s-length transactions.  In the third quarter of 2006, the Companypurchased an ownership interest in an airplane for corporate travel from athird party; therefore, these reimbursements will not be ongoing.  Simultaneous with this transaction, thesenior executive was able to fully liquidate the investment in the aircraftowned by his company.

Under the terms of its limited liability company agreement, during 2005Linn paid to Quantum Energy Partners, the majority member, a fee of 2.0% ofeach capital contribution made to the Company by Quantum Energy Partners.  Management believes the 2.0% fee was fairvalue.  The 2.0% fee was initiallynegotiated on an arms-length basis among unrelated third parties.  Fees paid during the year endedDecember 31, 2005 were approximately $0.3 million.  No such fees were paid in other years.  The payments were recognized as a return ofcapital on the consolidated statement of unitholders’ capital.

Mr. Eric P. Linn is President of Mid Atlantic Well Service, Inc., awholly owned subsidiary of Linn.  Mr.Linn’s 2007 annual base salary is $175,000 and he is provided with use of aCompany vehicle.  Mr. Linn is the brother of the Company’s Chairman, President and ChiefExecutive Officer, Michael C. Linn.

**(14)****                          Earnings Per Unit**

Basic earnings per unit iscomputed by dividing net earnings attributable to unitholders by the weightedaverage number of units outstanding during each period.  Diluted earnings per unit is computed byadjusting the average number of units outstanding for the dilutive effect, ifany, of unit equivalents.  The Companyuses the treasury stock method to determine the dilutive effect.  At December 31, 2006, the Company hadtwo classes of units outstanding, (i) units representing limitedliability company interests (“units”) listed on The NASDAQ Global Market underthe symbol “LINE” and (ii) Class B units. See Note 4 for details regarding the Class B units.

In accordance with SFAS No. 128, *“Earnings Per Share”* (“SFAS 128”) dual presentation of basicand diluted earnings per unit has been presented in the consolidated statementsof operations for each class of units issued and outstanding atDecember 31, 2006, units and Class B units.  Net income per unit is allocated to the unitsand the Class B units on an equal basis. Certain existing holders of Linn units totaling over 50% committed inadvance to vote a at unitholder meeting in favor of the conversion of class Bunits to units and the Class B units were converted to units on a one-for-onebasis in January 2007 (see Note 4); therefore, the Class B units share equallywith the units in the net income of the Company.  Since the Class B units were convertedto units in January 2007, they share equally in the February 2007 distributionsand all future distributions.  TheCompany made no distributions to Class B unitholders during the period theClass B units were outstanding.

For the periods prior to theCompany’s IPO, equivalent units were calculated by adjusting pre-IPO members’membership interests by the exchange ratio to reflect the exchange of pre-IPOmembership interests for post-IPO units and cash immediately prior tocompletion of the IPO (see Note 3).

83

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

The following reconciliation presents the impact onthe unit amounts of potential common units and the earnings per unit amounts:

|                                                           | ** ** | **Year Ended December 31,**                           | ** ** |
|-----------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                                                | ** ** | **2006**                                                             | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                | ** ** | **(in thousands, except per unit amounts)** | ** ** |
|                                                      |       |                                                                 | ** ** | ** ** |   |   |   |
| Net income (loss)                                         |       | $                                                                    | 79,185     |   | $ | (56,351 | ) | $ | (4,816 | ) |
| ** **                                                |       |                                                                 |       |   |   |   |   |
| Weighted average units  outstanding:                      |       |                                                                 |       |   |   |   |   |
|                                                      |       |                                                                 |       |   |   |   |   |
| Basic units  outstanding                                  |       | 28,281                                                               |       | 20,518 |   | 20,518 |   |
| Dilutive effect of  unit equivalents and Class B units(a) |       | 2,104                                                                |       | — |   | — |   |
| Diluted units  outstanding                                |       | 30,385                                                               |       | 20,518 |   | 20,518 |   |
|                                                      |       |                                                                 |       |   |   |   |   |
| Weighted average Class  B units outstanding:              |       |                                                                 |       |   |   |   |   |
|                                                      |       |                                                                 |       |   |   |   |   |
| Basic Class B  units outstanding                          |       | 1,737                                                                |       | — |   | — |   |
| Dilutive effect  of unit equivalents                      |       | —                                                               |       | — |   | — |   |
| Diluted Class B  units outstanding                        |       | 1,737                                                                |       | — |   | — |   |
|                                                      |       |                                                                 |       |   |   |   |   |
| Net income (loss) per  unit:                              |       |                                                                 |       |   |   |   |   |
| Units - basic                                             |       | $                                                                    | 2.64       |   | $ | (2.75 | ) | $ | (0.23 | ) |
| Units - diluted                                           |       | $                                                                    | 2.61       |   | $ | (2.75 | ) | $ | (0.23 | ) |
|                                                      |       |                                                                 |       |   |   |   |   |
| Class B units -  basic                                    |       | $                                                                    | 2.64       |   | $ | — |   | $ | — |   |
| Class B units - diluted                                   |       | $                                                                    | 2.61       |   | $ | — |   | $ | — |   |

----

(a)                 Excludesthe effect of average anti-dilutive common stock equivalents related toout-of-the-money options and restricted units of 234,016 for the year endedDecember 31, 2006. 

Subsequent to December 31, 2006, the Companygranted an aggregate 150,000 unit options to non-employees.  These options will be evaluated for inclusionin diluted earnings per unit in accordance with SFAS 128.

84

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

**(15)****                          Oil and Gas Derivatives**

The Company sells oil and gas in the normal course ofits business and utilizes derivative instruments to minimize the variability inforecasted cash flows due to price movements in oil and gas.  The Company enters into derivativeinstruments such as swap contracts and put options to hedge a portion of itsforecasted oil and gas sales.

Settled derivatives on gas production for the yearended December 31, 2006 included a volume of 9,262 MMBtu at an averagecontract price of $9.16.  Settledderivatives on oil production for the year ended December 31, 2006included a volume of 186 MBbls at an average contract price of $76.87.  Currently, we use fixed price swaps and putsto manage commodity prices.  The oil andgas transactions are settled based upon the closing NYMEX future price of gason the settlement date, which occurs on the third day of the production monthproceeding the production month.  The oiltransactions are settled based upon the average daily NYMEX price of light oil andsettlement occurs on the final day of the production month.

The following tables summarize open positions as ofDecember 31, 2006 and represents, as of such date, our derivatives inplace through December 31, 2011, on annual production volumes:

|                          | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | ** ** | ** ** | ** ** | ** ** |
|--------------------------|------------|----------------|------------|----------------|------------|----------------|------------|------------|------------|------------|------------|
| **Gas Positions**        | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** ** | ** ** | ** ** | ** ** |
| Fixed Price Swaps:       |       |           |       | ** **     |       | ** **     |       |       |       |       |       |
| Hedged Volume  (MMBtu)   |       | 8,203          |       | 10,264         |       | 8,005          |       |       |       |       |       |
| Average Price  ($/MMBtu) |       | $              | 8.72       |           | $          | 8.37           |       | $          | 7.89       |       |       |   |   |   |
| Puts:                    |       |           |       |           |       |           |       |       |       |       |       |
| Hedged Volume  (MMBtu)   |       | 3,018          |       | 2,013          |       | —         |       |       |       |       |       |
| Average Price  ($/MMBtu) |       | $              | 9.22       |           | $          | 9.50           |       | $          | —     |       |       |   |   |   |
| Total:                   |       |           |       |           |       |           |       |       |       |       |       |
| Hedged Volume  (MMBtu)   |       | 11,221         |       | 12,277         |       | 8,005          |       |       |       |       |       |
| Average Price ($/MMBtu)  |       | $              | 8.86       |           | $          | 8.56           |       | $          | 7.89       |       |       |   |   |   |

 

|                        | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** |
|------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Oil Positions**      | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Fixed Price Swaps:     |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls) |       | 500            |       | 500            |       | 500            |       | 500            |       | —         |       |
| Average Price  ($/Bbl) |       | $              | 75.83      |           | $          | 75.83          |       | $              | 75.83      |           | $          | 75.83 |   | $ | — |   |
| Puts:                  |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls) |       | 1,300          |       | 1,400          |       | 1,400          |       | 1,400          |       | 1,200          |       |
| Average Price  ($/Bbl) |       | $              | 66.54      |           | $          | 66.43          |       | $              | 66.43      |           | $          | 66.43 |   | $ | 65.00 |   |
| Total:                 |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls) |       | 1,800          |       | 1,900          |       | 1,900          |       | 1,900          |       | 1,200          |       |
| Average Price ($/Bbl)  |       | $              | 69.12      |           | $          | 68.90          |       | $              | 68.90      |           | $          | 68.90 |   | $ | 65.00 |   |

 

The oil and gas derivatives arenot designated as cash flow hedges under SFAS 133 and, accordingly, the changesin fair value are recorded in current period earnings.

85

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

Thefollowing table presents the outstanding notional amounts and maximum number ofmonths outstanding of our derivatives on annual production volumes:

|                                                     | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **2006**              | ** ** | **2005** | ** ** |
| ** **                                          | ** ** | ** **            | ** ** | ** ** | ** ** |
| Outstanding notional  amounts of gas hedges (MMBtu) |       | 31,503                |       | 28,069 |   |
| Maximum number of  months gas hedges outstanding    |       | 35                    |       | 48 |   |
| Outstanding notional  amounts of oil hedges (MBbls) |       | 8,700                 |       | — |   |
| Maximum number of months oil hedges outstanding     |       | 60                    |       | — |   |

 

By using derivative instrumentsto hedge exposures to changes in commodity prices, the Company exposes itselfto credit risk and market risk.  Creditrisk is the failure of the counterparty to perform under the terms of thederivative contract.  When the fair valueof a derivative contract is positive, the counterparty owes the Company, whichcreates credit risk.  The Companyminimizes the credit risk in derivative instruments by entering intotransactions with high-quality counterparties.

During 2005, the Company canceled(before their original settlement date) a portion of out-of-the-money gas swapsand realized a loss of $38.3 million. The Company subsequently hedged similar volumes at higher prices.

**(16)****                          Operating Leases**

The Company leases office spaceand equipment under lease agreements expiring on various dates through2015.  For the years endedDecember 31, 2006, 2005 and 2004, the Company recognized expense underoperating leases of approximately $0.5 million, $0.4 million and $0.2 million,respectively.  The Company accounts forleases with escalation clauses and rent holidays on a straight-line basis inaccordance with SFAS No. 13,*“Accounting forLeases.”*

Asof December 31, 2006, future minimum lease payments were as follows:

|            |   | (in thousands) |   |
|------------|--------|----------------|--------|
|       |   |           |   |
| 2007       |   | $              | 825    |   |
| 2008       |   | 1,039          |   |
| 2009       |   | 1,065          |   |
| 2010       |   | 1,101          |   |
| 2011       |   | 1,131          |   |
| Thereafter |   | 3,676          |   |
|       |   | $              | 8,837  |   |

 

**(17)****                         ****Income Taxes**

TheCompany is treated as a partnership for federal and state income taxpurposes.  As such, it is not a taxableentity and does not directly pay federal and state income tax.  Its taxable income or loss, which may varysubstantially from the net income or net loss reported in the consolidatedstatements of operations, is includable in the federal and state income taxreturns of each unitholder.  Accordingly,no recognition has been given to federal and state income taxes for theoperations of the Company except as described below.  The aggregate difference in the basis of netassets for financial and tax reporting purposes cannot be readily determined aswe do not have access to information about each unitholder’s tax attributes inthe Company.

On June1, 2005, Linn Operating, LLC (“Linn Operating”) was converted to a SubchapterC-corporation.  Additionally, on October12, 2005, the Company incorporated Mid Atlantic Well Service, Inc. (“MidAtlantic”).  Prior to June 1, 2005, theCompany and its subsidiaries were structured as limited liability companiestreated as partnerships or disregarded entities for federal income taxpurposes.

86

----

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

The income tax provision attributable to the Company’sSubchapter C-corporation subsidiaries’ losses before income taxes consisted ofthe following:

|                                | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|
| ** **                     | ** ** | **2006**                                   | ** ** | **2005** | ** ** |
| ** **                     | ** ** | **Current**                                | ** ** | **Deferred** | ** ** | **Total** | ** ** | **Current** | ** ** | **Deferred** | ** ** | **Total** | ** ** |
| ** **                     | ** ** | **(in thousands)**                    | ** ** |
|                           |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Federal                        |       | $                                          | —     |   | $ | 2,999 |   | $ | 2,999 |   | $ | — |   | $ | (57 | ) | $ | (57 | ) |
| State                          |       | (32                                        | )          | 435 |   | 403 |   | — |   | (17 | ) | (17 | ) |
| Income tax benefit (provision) |       | $                                          | (32        | ) | $ | 3,434 |   | $ | 3,402 |   | $ | — |   | $ | (74 | ) | $ | (74 | ) |

 

As ofDecember 31, 2006 and 2005, the Company’s taxable entities hadapproximately $10.1 million and $0.5 million, respectively, of net operatingloss carryforwards for federal income tax purposes, which will begin expiringin 2025.

Income tax expense differed from amounts computed byapplying the federal income tax rate of 35% to pre tax income as a result ofthe following:

|                                               | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                    | ** ** | **2006**                                   | ** ** | **2005** | ** ** |
| ** **                                    | ** ** | **(in thousands)**                    | ** ** |
|                                          |       |                                       |       |   |   |   |   |   |   |
| Federal statutory rate                        |       | $                                          | (26,174    | ) | (35.0 | )% | $ | 19,134 |   | 34.0 | % |
| State, net of federal  tax benefit            |       | 307                                        |       | 0.4 | % | (12 | ) | (0.0 | )% |
| (Income) loss from  non-taxable entities      |       | 37,874                                     |       | 50.6 | % | (19,168 | ) | (34.0 | )% |
| Non-deductible  compensation                  |       | (6,803                                     | )          | (9.1 | )% | — |   | — |   |
| Other items                                   |       | (1,802                                     | )          | (2.4 | )% | (28 | ) | (0.1 | )% |
| Income tax benefit (provision)/effective rate |       | $                                          | 3,402      |   | 4.6 | % | $ | (74 | ) | (0.1 | )% |

 

Significant components of the deferred tax assetsand liabilities were as follows:

|                                                                        | ** ** | **December 31,**   | ** ** |
|------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                             | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                                             | ** ** | **(in thousands)** | ** ** |
| Deferred tax assets:                                                   |       |                    |       |   |   |
| Net operating  loss carryforwards                                      |       | $                       | 4,227      |   | $ | 3 |   |
| Unit-based  compensation                                               |       | 1,766                   |       | — |   |
| Other                                                                  |       | 358                     |       | 24 |   |
| Valuation  allowance                                                   |       | (2,318                  | )          | 40 |   |
| Total deferred tax  assets                                             |       | 4,033                   |       | 67 |   |
|                                                                   |       |                    |       |   |   |
| Deferred tax  liabilities:                                             |       |                    |       |   |   |
| Property and  equipment principally due to differences in depreciation |       | (673                    | )          | (141 | ) |
| Total deferred tax  liabilities                                        |       | (673                    | )          | (141 | ) |
|                                                                   |       |                    |       |   |   |
| Net deferred tax assets (liabilities)                                  |       | $                       | 3,360      |   | $ | (74 | ) |

 

87

----

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

Net deferred tax liabilities were classified in theconsolidated balance sheets as follows:

|                                       | ** ** | **2006**                | ** ** | **2005** | ** ** |
|---------------------------------------|------------|-------------------------|------------|----------|------------|
| ** **                            | ** ** | **(in thousands)** | ** ** |
|                                  |       |                    |       |     |       |
| Deferred tax asset                    |       | $                       | 4,033      |     | $          | 67 |   |
| Deferred tax liability                |       | (673                    | )          | (141     | )          |
| Net deferred tax assets (liabilities) |       | $                       | 3,360      |     | $          | (74 | ) |

 

In assessing the realizability of deferred tax assets,management considers whether it is more likely than not that some portion orall of the deferred tax assets will not be realized.  The ultimate realization of deferred taxassets is dependent upon the generation of future taxable income during theperiods in which those temporary differences become deductible.  Management considers the scheduled reversalof deferred tax liabilities, projected future taxable income and tax planningstrategies in making this assessment. Based upon the level of historical taxable income and projections forfuture taxable income over the periods in which the deferred tax assets aredeductible, management believes it is more likely than not that we will realizethe benefits of these deductible differences at December 31, 2006.  The amount of the deferred tax assetconsidered realizable could be reduced in the future if estimates of futuretaxable income during the carryforward period are reduced.

88

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**LINN ENERGY, LLCSUPPLEMENTARY OIL AND GAS DATA (Unaudited)**

**(A)****                               Costs Incurred in Oil and Gas PropertyAcquisition, Exploration and Development Activities**

Costs incurred in oil and gasproperty acquisition and development are presented below:

|                                                                                                             | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                  | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                  | ** ** | **(in thousands)**                    | ** ** |
| Property  acquisition costs:                                                                                |       |                                       |       |   |   |   |   |
| Proved (1)                                                                                                  |       | $                                          | 450,232    |   | $ | 118,489 |   | $ | 27,271 |   |
| Unproved                                                                                                    |       | 4,062                                      |       | 579 |   | 2,940 |   |
| Development  costs (1)                                                                                      |       | 47,112                                     |       | 27,145 |   | 14,719 |   |
| Gas compression plant  and pipelines                                                                        |       | 15,232                                     |       | 4,043 |   | 1,537 |   |
| Company’s share of  equity investee’s costs of property acquisition, exploration, and development |       | —                                     |       | — |   | 15 |   |
|                                                                                                             |            |                                            |            |  |  |  |  |  |  |  |

----

(1)                Includes areclassification of approximately $112.0 million and $16.8 million fromdevelopment costs to proved acquisition costs for the years endedDecember 31, 2005 and 2004, respectively, in order to conform to currentyear presentation.

Property acquisition costs include costs incurred topurchase, lease, or otherwise acquire a property.  Development costs include costs incurred togain access to and prepare development well locations for drilling, to drilland equip development wells and to provide facilities to extract, treat andgather oil and gas.

The Company capitalizes costs related to drilling anddevelopment of oil and gas properties for specific activities related todrilling its wells, which included site preparation, drilling labor, meterinstallation, pipeline connection and site reclamation.  Such costs totaled approximately $8.5 million,$1.6 million and $0.2 million during the years ended December 31, 2006,2005 and 2004, respectively.

Additionally, development costs include the assetretirement obligation for future plugging costs.  See Note 11 in Notes to ConsolidatedFinancial Statements.

89

----

**LINN ENERGY, LLCSUPPLEMENTARY OIL AND GAS DATA (Unaudited) - Continued**

**(B)****                               Oil and Gas Capitalized Costs**

Aggregate capitalized costsrelated to oil and gas production activities with applicable accumulateddepreciation, depletion and amortization are presented below:

 

|                                                            | ** ** | **December 31,**   | ** ** |
|------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                 | ** ** | **2006**                | ** ** | **2005** | ** ** |
| ** **                                                 | ** ** | **(in thousands)** | ** ** |
|                                                       |       |                    |       |   |   |
| Unproved  properties                                       |       | $                       | 8,624      |   | $ | 4,562 |   |
| Proved  properties:                                        |       |                    |       |   |   |
| Leasehold, equipment and drilling                          |       | 737,202                 |       | 239,858 |   |
| Gas compression plant and pipelines                        |       | 20,812                  |       | 5,580 |   |
|                                                       |       | 766,638                 |       | 250,000 |   |
| Less accumulated  depletion, depreciation and amortization |       | (33,349                 | )          | (10,707 | ) |
| Net capitalized costs                                      |       | $                       | 733,289    |   | $ | 239,293 |   |

 

**(C)****                               Results of Oil and Gas Producing Activities**

The results of operations for oiland gas producing activities (excluding corporate overhead and interest costs)are presented below:

|                                                                                                               | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                    | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                    | ** ** | **(in thousands)**                    | ** ** |
| **Revenues:**                                                                                                 |       |                                       |       |   |   |   |   |
| Oil and gas sales, excluding natural gas marketing  revenues                                                  |       | $                                          | 80,393     |   | $ | 44,645 |   | $ | 19,502 |   |
| Gain (loss) on oil and gas derivatives                                                                        |       | 103,308                                    |       | (76,193 | ) | (11,004 | ) |
| Net oil and gas sales                                                                                         |       | 183,701                                    |       | (31,548 | ) | 8,498 |   |
| **Expenses:**                                                                                                 |       |                                       |       |   |   |   |   |
| Production costs                                                                                              |       | 18,099                                     |       | 7,356 |   | 4,756 |   |
| Depreciation, depletion and amortization                                                                      |       | 22,714                                     |       | 7,022 |   | 3,521 |   |
| Total expenses                                                                                                |       | 40,813                                     |       | 14,378 |   | 8,277 |   |
| Results of operations for oil and gas producing  activities (excluding corporate overhead and interest costs) |       | $                                          | 142,888    |   | $ | (45,926 | ) | $ | 221 |   |
| Company’s share  of equity method investee’s results of operations for producing activities.        |       | $                                          | —     |   | $ | (17 | ) | $ | (56 | ) |

 

Production costs include thosecosts incurred to operate and maintain productive wells and related equipment,including such costs as labor, repairs, maintenance, materials, supplies, fuelconsumed, insurance and other production taxes. In addition, production costs include administrative expenses applicableto support equipment associated with these activities.

Depreciation, depletion andamortization expense includes those costs associated with capitalizedacquisition and development costs and support equipment.  For the year ended December 31, 2006,depreciation, depletion and amortization expense also includes approximately $1.0million of impairments recorded on oil and gas properties (see Note 1 in Notesto Consolidated Financial Statements).

There is no tax provisionincluded in our results of oil and gas producing activities because all of ourtaxable income or loss is reported by the Company’s taxable subsidiaries, whichdo not own any of the Company’s oil and gas interests.  See Note 17 in Notes to ConsolidatedFinancial Statements for additional details about the Company’s income taxes

90

----

**LINN ENERGY, LLCSUPPLEMENTARY OIL AND GAS DATA (Unaudited) - Continued**

**(D)          NetProved Oil and Gas Reserves**

The proved reserves of oil andgas of the Company have been estimated by an independent petroleum engineeringfirm, DeGolyer and MacNaughton, at December 31, 2006.  Independent petroleum engineering firm,Schlumberger Data and Consulting Services provided the estimated reserves atDecember 31, 2005 and 2004.  Thesereserve estimates have been prepared in compliance with the SEC rules based onyear-end prices.  An analysis of thechange in estimated quantities of oil and gas reserves, all of which arelocated within the United States, is shown below:

|                                                 | ** ** | **Year Ended December 31, 2006** | ** ** |
|-------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                      | ** ** | **Gas (MMcf)**                                  | ** ** | **Oil (MBbls)** | ** ** | **Total (MMcfe)** | ** ** |
| **Proved  developed and undeveloped reserves:** |       |                                                 |       |   |   |   |   |
| Beginning of year                               |       | 191,856                                              |       | 226 |   | 193,210 |   |
| Revisions of previous estimates                 |       | (37,239                                              | )          | 370 |   | (35,018 | ) |
| Purchase of minerals in place                   |       | 84,951                                               |       | 29,784 |   | 263,655 |   |
| Extensions and discoveries                      |       | 43,037                                               |       | — |   | 43,037 |   |
| Production                                      |       | (8,599                                               | )          | (370 | ) | (10,818 | ) |
| End of year                                     |       | 274,006                                              |       | 30,010 |   | 454,066 |   |
| **Proved  developed reserves:**                 |       |                                                 |       |   |   |   |   |
| Beginning of year                               |       | 123,865                                              |       | 226 |   | 125,220 |   |
| End of year                                     |       | 166,007                                              |       | 24,675 |   | 314,057 |   |

 

|                                                 | ** ** | **Year Ended**   | ** ** |
|-------------------------------------------------|------------|-----------------------|------------|
| ** **                                      | ** ** | **December 31,** | ** ** |
| ** **                                      | ** ** | **2005**              | ** ** | **2004** | ** ** |
| ** **                                      | ** ** | **Gas (MMcfe)**  | ** ** |
| **Proved  developed and undeveloped reserves:** |       |                  |       |   |   |
| Beginning of year                               |       | 119,760               |       | 69,805 |   |
| Revisions of previous estimates                 |       | 2,415                 |       | 755 |   |
| Purchase of minerals in place                   |       | 53,976                |       | 35,827 |   |
| Extensions and discoveries                      |       | 21,898                |       | 16,485 |   |
| Production                                      |       | (4,839                | )          | (3,112 | ) |
| End of year                                     |       | 193,210               |       | 119,760 |   |
| **Proved  developed reserves:**                 |       |                  |       |   |   |
| Beginning of year                               |       | 74,366                |       | 41,760 |   |
| End of year                                     |       | 125,220               |       | 74,366 |   |

 

For the years endedDecember 31, 2005 and 2004, the above table includes changes in estimatedquantities of oil reserves shown in Mcf equivalents at a rate of one barrel persix Mcf.  Net oil production includedabove represents approximately 3% and 2% of total production in 2005 and 2004,respectively.

The 37,239 MMcfe decrease inprevious estimate in 2006 was due primarily to the decrease in gas prices.  The 2,415 MMcfe and 755 MMcfe increases inrevisions of previous estimates in 2005 and 2004, respectively, were due to theincrease in gas prices.

Extensions and discoveries of43,037 MMcfe, 21,898 MMcfe and 16,485 MMcfe in 2006, 2005 and 2004,respectively, are primarily due to the drilling of 159 wells during 2006, 110wells during 2005 and 90 wells during 2004, which increased the Company’sproved undeveloped drilling locations.

The Company made five, three andtwo acquisitions during 2006, 2005 and 2004, respectively, with total provedreserves of 263,655 MMcfe, 53,976 MMcfe and 35,827 MMcfe, respectively.

91

----

**LINN ENERGY, LLCSUPPLEMENTARY OIL AND GAS DATA (Unaudited) - Continued**

**(E)           StandardizedMeasure of Discounted Future Net Cash Flows and Changes Therein Relating toProved Reserves**

Summarized in the following tableis information for the Company with respect to the standardized measure ofdiscounted future net cash flows relating to proved reserves.  Future cash inflows are computed by applyingyear-end prices relating to the Company’s proved reserves to the year-endquantities of those reserves.  Futureproduction, development, site restoration and abandonment costs are derivedbased on current costs assuming continuation of existing economicconditions.  There are no future incometax expenses because the Company is a nontaxable entity (see Note 17 in Notesto Consolidated Financial Statements).

|                                                                     | ** ** | **December 31,**   | ** ** |
|---------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                          | ** ** | **2006**                | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                          | ** ** | **(in thousands)** | ** ** |
|                                                                |       |                    |       |   |   |   |   |
| Future estimated  revenues                                          |       | $                       | 3,053,772  |   | $ | 2,041,930 |   | $ | 840,127 |   |
| Future estimated  production costs                                  |       | (868,564                | )          | (332,839 | ) | (146,672 | ) |
| Future estimated  development costs                                 |       | (239,328                | )          | (96,542 | ) | (41,417 | ) |
| Future net cash flows                                               |       | 1,945,880               |       | 1,612,549 |   | 652,038 |   |
| 10% annual  discount for estimated timing of cash flows             |       | (1,393,620              | )          | (1,060,474 | ) | (437,004 | ) |
| Standardized  measure of discounted future estimated net cash flows |       | $                       | 552,260    |   | $ | 552,075 |   | $ | 215,034 |   |

 

The following table summarizesthe principal sources of change in the standardized measure of discountedfuture estimated net cash flows:

|                                                                    | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                         | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                         | ** ** | **(in thousands)**                    | ** ** |
|                                                               |       |                                       |       |   |   |   |   |
| Sales of oil and  gas production, net of production costs          |       | $                                          | (62,294    | ) | $ | (37,676 | ) | $ | (14,829 | ) |
| Changes in  estimated future development costs                     |       | (2,173                                     | )          | 55,125 |   | 17,341 |   |
| Net changes in  prices and production costs                        |       | (536,672                                   | )          | 135,701 |   | 4,443 |   |
| Purchase of  minerals in place                                     |       | 508,107                                    |       | 64,361 |   | 57,970 |   |
| Extensions,  discoveries, and improved recovery, less related cost |       | 17,872                                     |       | 192,412 |   | 26,507 |   |
| Development  costs incurred during the period                      |       | 47,112                                     |       | 26,406 |   | 16,733 |   |
| Revisions of  previous quantity estimates                          |       | (10,747                                    | )          | 1,026 |   | 3,671 |   |
| Change in  discount                                                |       | 55,208                                     |       | 21,503 |   | 12,634 |   |
| Changes in  production rates and other                             |       | (16,228                                    | )          | (121,817 | ) | (35,778 | ) |
|                                                               |       | $                                          | 185        |   | $ | 337,041 |   | $ | 88,692 |   |

 

It is necessary to emphasize thatthe data presented should not be viewed as representing the expected cash flowfrom, or current value of, existing proved reserves since the computations arebased on a large number of estimates and arbitrary assumptions.  Reserve quantities cannot be measured withprecision and their estimation requires many judgmental determinations andfrequent revisions.  The requiredprojection of production and related expenditures over time requires furtherestimates with respect to pipeline availability, rates of demand andgovernmental control.  Actual futureprices and costs are likely to be substantially different from the currentprices and costs utilized in the computation of reported amounts.  Any analysis or evaluation of the reportedamounts should give specific recognition to the computational methods utilizedand the limitations inherent therein.

92

----

**LINN ENERGY, LLCSUPPLEMENTARY QUARTERLY DATA (Unaudited)**

**(A)****                               Quarterly Financial Data**

|                                     | ** ** | **Quarters Ended**                                              | ** ** |
|-------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                          | ** ** | **March 31**                                                    | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| ** **                          | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **2006**                            |       |                                                                 |       |   |   |   |   |   |   |
| Oil and gas sales                   |       | $                                                                    | 16,375     |   | $ | 13,529 |   | $ | 23,506 |   | $ | 26,983 |   |
| Gain on oil and gas derivatives     |       | 24,246                                                               |       | 12,895 |   | 57,396 |   | 8,771 |   |
| Total revenues                      |       | 42,128                                                               |       | 27,974 |   | 82,257 |   | 38,699 |   |
| Operating expenses                  |       | 2,994                                                                |       | 2,933 |   | 4,845 |   | 7,327 |   |
| General and administrative expenses |       | 9,470                                                                |       | 6,928 |   | 6,536 |   | 17,059 |   |
| Net income (loss)                   |       | $                                                                    | 21,977     |   | $ | 10,239 |   | $ | 53,057 |   | $ | (6,088 | ) |
| Net income (loss) per unit:         |       |                                                                 |       |   |   |   |   |   |   |
| Units - basic                       |       | $                                                                    | 0.84       |   | $ | 0.37 |   | $ | 1.92 |   | $ | (0.16 | ) |
| Units - diluted                     |       | $                                                                    | 0.84       |   | $ | 0.36 |   | $ | 1.89 |   | $ | (0.15 | ) |
| Class B units - basic               |       | $                                                                    | —     |   | $ | — |   | $ | — |   | $ | (0.16 | ) |
| Class B units -  diluted            |       | $                                                                    | —     |   | $ | — |   | $ | — |   | $ | (0.15 | ) |

 

|                                       | ** ** | **Quarters Ended**                                              | ** ** |
|---------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                            | ** ** | **March 31**                                                    | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| ** **                            | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **2005**                              | ** ** | ** **                                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and gas sales                     |       | $                                                                    | 6,146      |   | $ | 7,855 |   | $ | 10,407 |   | $ | 20,237 |   |
| Loss on oil and gas derivatives       |       | (15,155                                                              | )          | (6,992 | ) | (50,463 | ) | (3,583 | ) |
| Total revenues                        |       | (8,121                                                               | )          | 1,582 |   | (38,418 | ) | 18,476 |   |
| Operating expenses                    |       | 1,817                                                                |       | 1,488 |   | 1,386 |   | 2,665 |   |
| General and administrative expenses   |       | 478                                                                  |       | 670 |   | 1,197 |   | 987 |   |
| Net income (loss)                     |       | $                                                                    | (12,399    | ) | $ | (5,276 | ) | $ | (45,590 | ) | $ | 6,914 |   |
|                                  |       |                                                                 |       |   |   |   |   |   |   |
| Net income (loss) per unit - basic    |       | $                                                                    | (0.60      | ) | $ | (0.26 | ) | $ | (2.22 | ) | $ | 0.34 |   |
| Net income  (loss) per unit - diluted |       | $                                                                    | (0.60      | ) | $ | (0.26 | ) | $ | (2.22 | ) | $ | 0.34 |   |

 

93

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**Item9. ****Changes in and Disagreements With Accountants on Accounting andFinancial Disclosure**

None.

**Item9A. ****Controls and Procedures**

***(a)******         Evaluation of disclosure controls and procedures***

The Company maintainsdisclosure controls and procedures that are designed to ensure that informationrequired to be disclosed in the Company’s reports under the Securities ExchangeAct of 1934, as amended (the “Exchange Act”) is recorded, processed, summarizedand reported within the time periods specified in the SEC’s rules and forms,and that such information is accumulated and communicated to management,including the Company’s Chief Executive Officer and Chief Financial Officer,and the Company’s Audit Committee of the Board of Directors, as appropriate, toallow timely decisions regarding required disclosure.  In designing and evaluating the disclosurecontrols and procedures, management recognizes that any controls andprocedures, no matter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives, andmanagement is required to apply its judgment in evaluating the cost-benefitrelationship of possible controls and procedures.

We carried out anevaluation under the supervision and with the participation of our management,including our Chief Executive Officer and Chief Financial Officer, of theeffectiveness of our disclosure controls and procedures as of the end of theperiod covered by this report.

Due to the materialweakness described below, our Chief Executive Officer and Chief FinancialOfficer continue to conclude that our disclosure controls and procedures werenot effective as of December 31, 2006. As noted below, we believe we have taken the necessary steps to addressthe matters related to the material weakness. However, before concluding that the material weakness has beenremediated, management believes that the new internal controls should beimplemented and operational for a sufficient period of time to demonstrate thatthe controls are operating effectively. We believe our consolidated financial statements included in this AnnualReport on Form 10-K fairly present in all material respects our financialposition, results of operations and cash flows for the periods presented inaccordance with United States generally accepted accounting principles.

*Materialweakness in internal control*. In connection with the preparation of the Company’s Annual Report onForm 10-K for the year ended December 31, 2005 (“2005 10-K”), anevaluation was performed under the supervision and with the participation ofthe Company’s management, including the Chief Executive Officer and the ChiefFinancial Officer, of the effectiveness of the design and operation of theCompany’s disclosure controls and procedures as defined in Rule 13a-15(e)and Rule 15d-15(e) under the Exchange Act. The Company concluded that the disclosure controls and procedures werenot effective as of December 31, 2005.

Specifically, the Companylacked (i) personnel with sufficient technical accounting and financialreporting expertise, (ii) adequate review controls over accountreconciliations and account analyses, (iii) policies and procedures inplace to determine and document the appropriate application of accountingprinciples and (iv) policies and procedures requiring a detailed andcomprehensive review of the underlying information supporting the amountsincluded in the annual and interim consolidated financial statements anddisclosures.  We undertook numerousremedial actions, as described below, to enhance controls.

*Remediationactivities.*  During2006, Company management has taken the following steps to strengthen internalcontrol over financial reporting.

1.               Werecruited an experienced accounting team with over 130 combined years ofexperience in oil and gas accounting and financial reporting.

2.               Weutilized outside consultants with extensive oil and gas financial reportingexperience and augmented our accounting resources to assist with requiredfilings and documentation of reconciliations and procedures.

3.               Accountingand reporting position papers were developed for critical accounting policiesinvolving judgment or application of complex accounting standards.

94

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**Item9A. ****Controls and Procedures - Continued**

4.               Weperformed additional analysis and other post-closing procedures to enable thepreparation of accurate consolidated financial statements, including allrequired disclosures.  In addition, weimplemented certain review and monitoring controls over accountreconciliations, and analysis and post-closing procedures.

5.               Wedeveloped and implemented a process for determining the effective accountingdate for an oil and gas property acquisition and formalized proceduresnecessary to appropriately account for future acquisitions.

6.               Weimplemented the use of disclosure checklists addressing the disclosurerequirements under GAAP as well as the incremental financial and nonfinancialinformation required by SEC regulations.

7.               Weprovided extensive training on our accounting software system to both new andestablished accounting personnel.

We believe we have takenthe necessary steps to address the matters related to the material weaknessdescribed above.  However, beforeconcluding that the material weakness has been remediated, management believesthat the new internal controls should be implemented and operational for asufficient period of time to demonstrate that the controls are operatingeffectively.

***(b)*  *Changes and remediation in the Company’s internal control overfinancial reporting***

In response to thematerial weakness noted in 4(a) above, during the three months endedDecember 31, 2006, Company management has taken the following remedialactions (i) hired additional experienced personnel with technical accounting,financial reporting and oil and gas experience, (ii) provided additionaltraining on our accounting software system to both new and establishedaccounting personnel and (iii) continued to perform and to enhance additionalanalysis and other post-closing procedures, including certain review andmonitoring controls over account reconciliation.  These three items constitute the changes inour internal control over financial reporting, as defined inRule 13(a)-15(f) under the Exchange Act, during the three months endedDecember 31, 2006, that have materially affected, or are reasonably likelyto materially affect, our internal control over financial reporting.

Further as previouslyreported, we expect to continue to make changes in our internal control overfinancial reporting during the periods prior to December 31, 2007, inconnection with our compliance efforts under Section 404 of the Sarbanes-OxleyAct of 2002.  As such, we will continueto assess the adequacy of our internal control over financial reporting,remediate any control weaknesses that may be identified, validate throughtesting that controls are functioning as designed and implement a continuousreporting and improvement process for internal control over financialreporting.

**Item9B. ****Other Information**

None.

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**Part III**

**Item 10.  Directors, Executive Officers and CorporateGovernance**

A list of our executiveofficers and biographical information appears in Part I. Item 1. “Business”in this Form 10-K.  Information about ourDirectors may be found under the caption “Election of Directors” of our ProxyStatement for the Annual Meeting of Unitholders to be held June 19, 2007 (the “2007Proxy Statement”).  That information isincorporated herein by reference.

The information in the2007 Proxy Statement set forth under the caption “Section 16(a) BeneficialOwnership Reporting Compliance” is incorporated herein by reference.

We have adopted the LinnEnergy, LLC Code of Ethics for Chief Executive Officer and Senior FinancialOfficers (the “finance code of ethics”), a code of ethics that applies to ourChief Executive Officer, Chief Financial Officer and other finance organizationexecutives.  The finance code of ethicsis publicly available on our website at www.linnenergy.com.  If we make any substantive amendments to thefinance code of ethics or grant any waiver, including any implicit waiver, froma provision of the code to our Chief Executive Officer, Chief Financial Officeror any other finance organization executive, we will disclose the nature ofsuch amendment or waiver on that website or in a Current Report on Form 8-K.

**Item11.  Executive Compensation**

Information required bythis item is incorporated herein by reference to the 2007 Proxy Statement.

**Item12.  Security Ownership of CertainBeneficial Owners and Management and Related Stockholder Matters**

Information required bythis item is incorporated herein by reference to the 2007 Proxy Statement.

**Item13.  Certain Relationships and RelatedTransactions, and Director Independence**

Information required bythis item is incorporated herein by reference to the 2007 Proxy Statement.

**Item14.  Principal Accounting Fees andServices**

Information required bythis item is incorporated herein by reference to the 2007 Proxy Statement.

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**Part IV**

**Item15.  Exhibits, Financial StatementSchedules**

(a) – 2.  Financial Statement Schedules:

See Note 1 in Notes toConsolidated Financial Statements for “Valuation and Qualifying Accounts andAllowances.”

All other schedules areomitted for the reason that they are not required or the information is otherwisesupplied under Part II.  Item  8.

(a) – 3.  Exhibits Filed:

The exhibits required tobe filed by this Item 15 are set forth in the Index to Exhibitsaccompanying this report.

 

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**SIGNATURES**

Pursuant to therequirements of the Securities Exchange Act of 1934, the Registrant has dulycaused this report to be signed on its behalf by the undersigned thereunto dulyauthorized.

|                      |     | LINN ENERGY, LLC |
|----------------------|----------|------------------|
|                 |     |             |   |   |
| Date: March 30, 2007 |     | By:              |   | /s/ MICHAEL C. LINN |
|                 |     |             |   | Michael C. Linn |
|                 | * * | * *         | * * | *Chairman, President and Chief Executive Officer* |
|                 | * * | * *         | * * | * * |
|                 | * * | * *         | * * | * * |
| Date: March 30, 2007 |     | By:              |   | /s/ LISA D. ANDERSON |
|                 |     |             |   | Lisa D. Anderson |
|                 | * * | * *         | * * | *Senior Vice President and Chief Accounting  Officer* |

 

Pursuant to therequirements of the Securities Exchange Act of 1934, this Annual Report hasbeen signed below by the following persons on behalf of the Registrant and inthe capacities and on the dates indicated.
| **Signature**                 | ** ** | **Title**                                             | ** ** | **Date**            |
|-------------------------------|------------|-------------------------------------------------------|------------|---------------------|
| /s/ MICHAEL C. LINN           |       | Chairman,  President and Chief Executive Officer      |       | March 30, 2007 |
| Michael C. Linn               |       | (Principal  Executive Officer)                        |       |                |
|                          |       |                                                  |       |                |
| /s/ KOLJA ROCKOV              |       | Executive  Vice President and Chief Financial Officer |       | March 30, 2007 |
| Kolja Rockov                  |       | (Principal  Financial Officer)                        |       |                |
|                          |       |                                                  |       |                |
| /s/ LISA D. ANDERSON          |       | Senior  Vice President and Chief Accounting Officer   |       | March 30, 2007 |
| Lisa D. Anderson              |       | (Principal  Accounting Officer)                       |       |                |
|                          |       |                                                  |       |                |
| /s/ GEORGE A. ALCORN          |       | Independent  Director                                 |       | March 30, 2007 |
| George A. Alcorn              |       |                                                  |       |                |
|                          |       |                                                  |       |                |
| /s/ TERRENCE S. JACOBS        |       | Independent  Director                                 |       | March 30, 2007 |
| Terrence S. Jacobs            |       |                                                  |       |                |
|                          |       |                                                  |       |                |
| /s/ ALAN L. SMITH             |       | Director                                              |       | March 30, 2007 |
| Alan L. Smith                 |       |                                                  |       |                |
|                          |       |                                                  |       |                |
| /s/ JEFFREY C. SWOVELAND |       | Independent  Director                                 |       | March 30, 2007 |
| Jeffrey C. Swoveland          |       |                                                  |       |                |

 

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**INDEXTO EXHIBITS**
| Exhibit Number  | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                              |
|-----------------|------------|------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.1             |       | —     |       | Purchase and Sale Agreement by and among Linn  Energy, LLC and Blacksand Energy, LLC, dated July 19, 2006 (incorporated  herein by reference to Exhibit 2.1 to our Current Report on Form 8-K filed on  July 25, 2006)                                                                                                                                                                                                       |
| 2.2             |       | —     |       | Purchase and Sale Agreement between Linn Energy, LLC  and Kaiser-Francis Oil Company dated July 21, 2006 (incorporated herein by  reference to Exhibit 2.2 to our Current Report on Form 8-K filed on July 25,  2006)                                                                                                                                                                                                        |
| 2.3             |       | —     |       | Purchase and Sale Agreement dated December 13, 2006,  by and between Cavallo Energy LP, a Delaware limited partnership, acting  through its general partner, Stallion Energy LLC, a Delaware limited  liability company and Linn Energy, LLC, a Delaware limited liability company  (Large Package Agreement) (incorporated herein by reference to Exhibit 2.1 to  our Current Report on Form 8-K filed on February 5, 2007) |
| 2.4             |       | —     |       | Purchase and Sale Agreement dated December 13, 2006,  by and between Cavallo Energy LP, a Delaware limited partnership, acting  through its general partner, Stallion Energy LLC, a Delaware limited  liability company and Linn Energy, LLC, a Delaware limited liability company  (Small Package Agreement) (incorporated herein by reference to Exhibit 2.2 to  our Current Report on Form 8-K filed on February 5, 2007) |
| 2.5             |       | —     |       | Gathering System Purchase Agreement dated February  1, 2007, by and between Cavallo Gathering Company LLC, a Texas limited  liability company, and Penn West Pipeline, LLC, a Delaware limited liability  company (incorporated herein by reference to Exhibit 2.3 to our Current  Report on Form 8-K filed on February 5, 2007)                                                                                             |
| 3.1             |       | —     |       | Certificate of Formation of Linn Energy Holdings,  LLC (now Linn Energy, LLC) (incorporated herein by reference to  Exhibit 3.1 to our Registration Statement on Form S-1 (File  No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)                                                                                                                                                              |
|  3.2  |       | —     |       | Certificate of Amendment to Certificate of Formation  of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by  reference to Exhibit 3.2 to our Form S-1 filed on June 3, 2005)                                                                                                                                                                                                                 |
|  3.3† |       | —     |       | Second Amended and Restated Limited Liability  Company Agreement of Linn Energy, LLC dated January 19, 2006                                                                                                                                                                                                                                                                                                                  |
|  3.4† |       | —     |       | Amendment No. 1 to Second Amended and Restated  Limited Liability Company Agreement of Linn Energy, LLC dated October 24,  2006                                                                                                                                                                                                                                                                                              |
|  3.5† |       | —     |       | Amendment No. 2 to Second Amended and Restated  Limited Liability Company Agreement of Linn Energy, LLC dated February 1,  2007                                                                                                                                                                                                                                                                                              |
| 4.1             |       | —     |       | Form of specimen unit certificate for the units of  Linn Energy, LLC (incorporated herein by reference to Exhibit 4.1 to the  Annual Report on our Form 10-K filed on May 31, 2006)                                                                                                                                                                                                                                          |
| 4.2             |       | —     |       | Form of Class C Unit Certificate (incorporated  herein by reference to Exhibit 4.2 to our Current Report on Form 8-K filed on  February 5, 2007)                                                                                                                                                                                                                                                                             |
| 10.1*      |       | —     |       | Form of Linn Energy, LLC Long-Term Incentive Plan  (incorporated herein by reference to Exhibit 10.10 to Amendment  No. 4 to our Registration Statement on Form S-1 filed on December 14,  2005)                                                                                                                                                                                                         |
| 10.2*      |       | —     |       | First Amendment to Linn Energy, LLC Long-Term  Incentive Plan dated January 18, 2007 (incorporated by reference to Exhibit  10.1 to our Current Report on Form 8-K filed on January 19, 2007)                                                                                                                                                                                                                                |
| 10.3*†     |       | —     |       | Second Amendment to Linn Energy, LLC Long-Term  Incentive Plan dated March 21, 2007                                                                                                                                                                                                                                                                                                                                          |
| 10.4*†     |       | —     |       | Form of Executive Unit Option Agreement pursuant to  the Linn Energy, LLC Long-Term Incentive Plan                                                                                                                                                                                                                                                                                                                           |
| 10.5*†     |       | —     |       | Form of Executive Restricted Unit Agreement pursuant  to the Linn Energy, LLC Long-Term Incentive Plan                                                                                                                                                                                                                                                                                                                       |
| 10.6*      |       | —     |       | Form of Phantom Unit Grant Agreement for Independent  Directors pursuant to the Linn Energy, LLC Long-Term Incentive Plan  (incorporated herein by reference to Exhibit 10.1 to our Current Report on  Form 8-K filed on August 9, 2006)                                                                                                                                                                                     |

 

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**INDEX TOEXHIBITS - Continued**
| Exhibit Number | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
|----------------|------------|------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.7*     |       | —     |       | Amended and Restated Employment Agreement, dated  effective as of December 14, 2005 between Linn Operating, Inc. and Michael C.  Linn (incorporated herein by reference to Exhibit 10.12 to Amendment No. 4 to  our Registration Statement on Form S-1 (File No. 333-125501) filed on  December 14, 2005)                                                                                                                                                                                     |
| 10.8*     |       | —     |       | Second Amended and Restated Employment Agreement,  dated as of September 15, 2005 between Linn Operating, Inc. and Kolja Rockov  (incorporated herein by reference to Exhibit 10.12 to Amendment No. 2 to our  Registration Statement on Form S-1 (File No. 333-125501) filed on October 31,  2005)                                                                                                                                                                                           |
| 10.9*          |       | —     |       | Employment Agreement, dated effective as of December  18, 2006 between Linn Operating, Inc. and Mark E. Ellis (incorporated herein  by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on  November 29, 2006)                                                                                                                                                                                                                                                               |
| 10.10*         |       | —     |       | Employment Agreement, dated effective as of  April 3, 2006 between Linn Operating, Inc. and Thomas A. Lopus  (incorporated herein by reference to Exhibit 10.1 to our Current Report  on Form 8-K filed on April 18, 2006)                                                                                                                                                                                                                                           |
| 10.11*         |       | —     |       | Employment Agreement, dated effective as of July 7,  2006 between Linn Operating, Inc. and Lisa D. Anderson (incorporated herein  by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on July  13, 2006)                                                                                                                                                                                                                                                                     |
| 10.12*         |       | —     |       | Second Amended and Restated Credit Agreement dated  as of August 1, 2006 among Linn Energy, LLC as Borrower, BNP Paribas, as  Administrative Agent, Royal Bank of Canada, as Syndication Agent, Societe  Generale, Comerica Bank and Citibank Texas, N.A. as Co-Documentation Agents  and the Lenders Party thereto (incorporated herein by reference to Exhibit  10.1 to our Current Report on Form 8-K filed on August 7, 2006)                                                             |
| 10.13          |       | —     |       | First Amendment to Second Amended and Restated  Credit Agreement dated as of February 1, 2007, among Linn Energy, LLC, as  borrower, BNP Paribas, as administrative agent, and the lenders party thereto  (incorporated herein by reference to Exhibit 10.4 to our Current Report on  Form 8-K filed on February 5, 2007)                                                                                                                                                                     |
| 10.14          |       | —     |       | Second Amended and Restated Guaranty and Pledge  Agreement dated as of August 1, 2006 made by Linn Energy, LLC and each of the  other Obligors in favor of BNP Paribas, as Administrative Agent (incorporated  herein by reference to Exhibit 10.3 to our Current Report on Form 8-K filed  on August 7, 2006)                                                                                                                                                                                |
| 10.15          |       | —     |       | Second Lien Guaranty and Pledge Agreement dated as  of August 1, 2006 made by Linn Energy, LLC and each of the other Obligors in  favor of BNP Paribas, as Administrative Agent (incorporated herein by  reference to Exhibit 10.4 to our Current Report on Form 8-K filed on August  7, 2006)                                                                                                                                                                                                |
| 10.16          |       | —     |       | Class B Unit and Unit Purchase Agreement, dated as  of October 24, 2006 by and between Linn Energy, LLC and the Purchasers named  therein (incorporated herein by reference to Exhibit 10.1 to our Current  Report on Form 8-K filed on October 25, 2006)                                                                                                                                                                                                                                     |
| 10.17          |       | —     |       | Registration Rights Agreement dated as of October  24, 2006 by and among Linn Energy, LLC and the Purchasers named therein  (incorporated herein by reference to Exhibit 10.2 to our Current Report on  Form 8-K filed on October 25, 2006)                                                                                                                                                                                                                                                   |
| 10.18          |       | —     |       | Class C Unit and Unit Purchase Agreement, dated as  of February 1, 2007 by and among the Company and the Purchasers named therein  (incorporated herein by reference to Exhibit 10.1 to our Current Report on  Form 8-K filed on February 5, 2007)                                                                                                                                                                                                                                            |
| 10.19          |       | —     |       | Registration Rights Agreement dated February 1,  2007, by and among the Company and the Purchasers named therein (incorporated  herein by reference to Exhibit 10.2 to our Current Report on Form 8-K filed  on February 5, 2007)                                                                                                                                                                                                                                                             |
| 10.20          |       | —     |       | Transition Services Agreement Dated February 1,  2007, by and between Stallion Energy LLC, a Delaware limited liability  company, and Linn Energy, LLC, a Delaware limited liability company, Linn  Energy Holdings, LLC, a Delaware limited liability company, Linn Operating,  Inc., a Delaware corporation and Penn West Pipeline, LLC, a Texas limited  liability company (incorporated herein by reference to Exhibit 10.3 to our  Current Report on Form 8-K filed on February 5, 2007) |
| 21.1†     |       | —     |       | Significant Subsidiaries of Linn Energy, LLC                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| 23.1†     |       | —     |       | Consent of KPMG LLP for Linn Energy, LLC                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 23.2†     |       | —     |       | Consent of DeGolyer and MacNaughton Data and  Consulting Services                                                                                                                                                                                                                                                                                                                                                                                                                             |
| 23.3†     |       | —     |       | Consent of Schlumberger Technology Corporation                                                                                                                                                                                                                                                                                                                                                                                                                                                |

 

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**INDEX TOEXHIBITS - Continued**
| Exhibit Number | ** ** | ** ** | ** ** | **Description**                                                                                                           |
|----------------|------------|------------|------------|---------------------------------------------------------------------------------------------------------------------------|
| 31.1†     |       | —     |       | Section 302 Certification of Michael C. Linn,  Chairman, President and Chief Executive Officer of Linn Energy, LLC        |
| 31.2†     |       | —     |       | Section 302 Certification of Kolja Rockov, Executive  Vice President and Chief Financial Officer of Linn Energy, LLC      |
| 32.1†     |       | —     |       | Section 906 Certification of Michael C. Linn,  Chairman, President and Chief Executive Officer of Linn Energy, LLC   |
| 32.2†     |       | —     |       | Section 906 Certification of Kolja Rockov,  Executive Vice President and Chief Financial Officer of Linn Energy, LLC |

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†                     Filedherewith.

*                    ManagementContract or Compensatory Plan or Arrangement required to be filed as an exhibithereto pursuant to Item 601 of Regulation S-K.

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