**UNITED STATES SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**Form 10-Q**

 
| **x**                                                      | ** ** | **QUARTERLY  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**  |
|------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------|
| ** **                                                 | ** ** | ** **                                                                                    |
| **For the Quarterly Period Ended September 30, 2007** |
| ** **                                                 | ** ** | ** **                                                                                    |
| **OR**                                                     |
| ** **                                                 | ** ** | ** **                                                                                    |
| **o**                                                      | ** ** | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |

 

**for thetransition period from                    to                    **

 

**CommissionFile Number: 000-51719**

 

**LINNENERGY, LLC**

**(**Exact name of registrant as specified in itscharter)

 

| **Delaware**                                                     | ** ** | **65-1177591**                     |
|------------------------------------------------------------------|------------|------------------------------------|
| (State or other  jurisdiction of incorporation or  organization) |       | (IRS Employer  Identification No.) |
|                                                             |       |                               |
| **600  Travis, Suite 5100****Houston, Texas**                    | ** ** | **77002**                          |
| (Address of principal  executive offices)                        |       | (Zip Code)                         |

 

**(281) 840-4000**

(Registrant’s telephonenumber, including area code)

 

Indicate by check markwhether the 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 check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

 

Large acceleratedfiler  o        Acceleratedfiler    o      Non-acceleratedfiler  x

 

Indicate by check markwhether registrant is a shell company (as defined in Rule 12b-2 of the ExchangeAct).   Yes  o   No  x

 

As of November 2, 2007, there were 113,712,436 units outstanding.

 

 

----

 

**TABLE OFCONTENTS**

 
| ** ** | ** **                                                                                                                            | **Page**   |
|------------|---------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** ** | **Glossary  of Terms**                                                                                                                | ii         |
|       |                                                                                                                                  |       |
|       | **Part I - Financial Information**                                                                                                    | ** ** |
| Item 1.    | Financial  Statements                                                                                                                 |       |
|       | Condensed Consolidated  Balance Sheets as of September 30, 2007 and December 31, 2006                                  | 1          |
|       | Condensed Consolidated  Statements of Operations for the three and nine months ended  September 30, 2007 and 2006                | 3          |
|       | Condensed Consolidated  Statements of Unitholders’ Capital for the three and nine months ended  September 30, 2007 and 2006 | 4          |
|       | Condensed Consolidated  Statements of Cash Flows for the nine months ended September 30, 2007  and 2006                          | 5          |
|       | Notes to  Condensed Consolidated Financial Statements (Unaudited)                                                                     | 7          |
| Item 2.    | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                                           | 24         |
| Item 3.    | Quantitative  and Qualitative Disclosures About Market Risk                                                                           | 42         |
| Item 4.    | Controls and  Procedures                                                                                                              | 44         |
|       | **Part II - Other  Information**                                                                                                      |       |
| Item 1.    | Legal Proceedings                                                                                                                     | 46         |
| Item 1A.   | Risk  Factors                                                                                                                         | 46         |
| Item 2.    | Unregistered  Sales of Equity Securities and Use of Proceeds                                                                          | 52         |
| Item 3.    | Defaults Upon  Senior Securities                                                                                                      | 52         |
| Item 4.    | Submission of  Matters to a Vote of Security Holders                                                                                  | 52         |
| Item 5.    | Other Information                                                                                                                     | 52         |
| Item 6.    | Exhibits                                                                                                                              | 53         |
|       |                                                                                                                                  |       |
| ** ** | **Signature**                                                                                                                         | 54         |

 

i

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**GLOSSARYOF TERMS**

 

As commonly used in the oil and gas industry and as used in thisQuarterly Report on Form10-Q, the following terms have the following meanings:

 

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

 

*Bcf.*One billioncubic feet.

 

*Bcfe.*One billioncubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl ofoil, condensate or natural gas liquids.

 

*Btu.*One Britishthermal unit, which is the heat required to raise the temperature of aone-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

 

*Development well.*Awell drilled within the proved area of an oil or gas reservoir to the depth ofa stratigraphic horizon known to be productive.

 

*Dth.*Onedecatherm, equivalent to one million British thermal units.

 

*Developed acres.*Acresspaced or assigned to productive wells.

 

*Dry hole* or*well.*A well found to be incapable ofproducing hydrocarbons in sufficient quantities such that proceeds from thesale of such production would exceed production expenses and taxes.

 

*Field.*An areaconsisting of a single reservoir or multiple reservoirs all grouped on orrelated to the same individual geological structural feature and/orstratigraphic condition.

 

*FERC.*Federal Energy RegulatoryCommission.

 

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

 

*LIBOR.*London Interbank Offered Rate.

 

*MBbls.*Onethousand barrels of oil or other liquid hydrocarbons.

 

*Mcf.*One thousandcubic feet.

 

*Mcfe.*One thousandcubic feet equivalent, determined using the ratio of six Mcf of gas to one Bblof oil, condensate or natural gas liquids.

 

*MMBbls.*Onemillion barrels of oil or other liquid hydrocarbons.

 

*MMboe.*One millionbarrels of oil equivalent determined using a ratio of six Mcf of gas to one Bblof oil, condensate or natural gas liquids.

 

*MMBtu.*One millionBritish thermal units.

 

*MMcf.*One millioncubic feet.

 

*MMcfe.*One millioncubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl ofoil, condensate or natural gas liquids.

 

*MMcfe/d.*One MMcfeper day.

 

*MMMBtu.*Onebillion British thermal units.

 

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

 

*NGL.*Natural gasliquids, which are the hydrocarbon liquids contained within gas.

 

*NYMEX.*The NewYork Mercantile Exchange.

 

*Oil.*Crude oil,condensate and natural gas liquids.

 

*PEPL.*Panhandle Eastern Pipeline.

 

ii

----

 

*Productive well.*Awell that is found to be capable of producing hydrocarbons in sufficientquantities such that proceeds from the sale of such production exceedsproduction expenses and taxes.

 

*Proved developed reserves.*Reservesthat can be expected to be recovered through existing wells with existingequipment and operating methods. Additional oil and gas expected to be obtainedthrough 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.

 

*Proved reserves.*Provedoil and gas reserves are the estimated quantities of gas, natural gas liquidsand oil which geological and engineering data demonstrate with reasonablecertainty to be recoverable in future years from known reservoirs underexisting economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Pricesinclude consideration of changes in existing prices provided only bycontractual arrangements, but not on escalations based on future conditions. Thedefinition of proved reserves is in accordance with the Securities and ExchangeCommission’s definition set forth in Regulation S-X Rule 4-10(a) and itssubsequent staff interpretations and guidance.

 

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

 

*Proved undeveloped reserves*or*PUDs.*Reserves that areexpected to be recovered from new wells on undrilled acreage or from existingwells where a relatively major expenditure is required for recompletion. Reserveson undrilled acreage are limited to those drilling units offsetting productiveunits that are reasonably certain of production when drilled. Proved reserves forother undrilled units are claimed only where it can be demonstrated withcertainty that there is continuity of production from the existing productiveformation. Estimates for proved undeveloped reserves are not attributed to anyacreage for which an application of fluid injection or other improved recoverytechnique is contemplated, unless such techniques have been proved effective byactual tests in the area and in the same reservoir.

 

*Recompletion.*Thecompletion for production of an existing wellbore in another formation fromthat which the well has been previously completed.

 

*Reservoir.*Aporous and permeable underground formation containing a natural accumulation ofeconomically productive oil and/or gas that is confined by impermeable rock orwater barriers and is individual and separate from other reserves.

 

*Royalty interest.*An interest that entitles the owner of suchinterest to a share of the mineral production from a property or to a share ofthe proceeds therefrom. It does not contain the rights and obligations ofoperating the property and normally does not bear any of the costs ofexploration, development, and operation of the property.

 

*Standardized Measure.*StandardizedMeasure, or standardized measure of discounted future net cash flows relatingto proved oil and gas reserve quantities, is the present value of estimatedfuture net revenues to be generated from the production of proved reserves,determined in accordance with the rules and regulations of the Securities andExchange Commission (using prices and costs in effect as of the date ofestimation) without giving effect to non-property related expenses such asgeneral and administrative expenses, debt service and future income taxexpenses or to depreciation, depletion and amortization and discounted using anannual discount rate of 10%. The Company’s Standardized Measure does notinclude future income tax expenses because the reserves are owned by itssubsidiaries which are not subject to income taxes.

 

*Successful well.*Awell capable of producing oil and/or gas in commercial quantities.

 

*Undeveloped acreage.*Leaseacreage on which wells have not been drilled or completed to a point that wouldpermit the production of commercial quantities of oil and gas regardless ofwhether such acreage contains proved reserves.

 

*Unproved reserves.*Leaseacreage on which wells have not been drilled and where it is either probable orpossible that the acreage contains reserves.

 

*Working interest.*Theoperating interest that gives the owner the right to drill, produce and conductoperating activities on the property and a share of production.

 

*Workover.*Operationson a producing well to restore or increase production.

 

iii

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**PART I – FINANCIAL INFORMATION**

 

**Item 1.       Financial Statements**

 

**LINN ENERGY, LLC**

 

**CONDENSEDCONSOLIDATED BALANCE SHEETS**

 
| ** **                                                                | ** ** | **September 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|---------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                                | ** ** | **(Unaudited)**              | ** ** | ** **                  | ** ** |
| ** **                                                                | ** ** | **(in thousands)**      | ** ** |
| **Assets**                                                                |       |                         |       |                        |       |
|                                                                      |       |                         |       |                        |       |
| **Current  assets:**                                                      |       |                         |       |                        |       |
| Cash and cash  equivalents                                                |       | $                            | 33,588     |                        | $          | 6,595 |   |
| Receivables –  trade, net                                            |       | 96,645                       |       | 19,124                      |       |
| Inventories                                                               |       | 2,781                        |       | 578                         |       |
| Current portion  of derivatives                                           |       | 77,884                       |       | 37,817                      |       |
| Current portion  of deferred tax assets, net                              |       | —                       |       | 3,344                       |       |
| Other current  assets                                                     |       | 1,186                        |       | 2,218                       |       |
| Total current  assets                                                     |       | 212,084                      |       | 69,676                      |       |
|                                                                      |       |                         |       |                        |       |
| Oil and gas  properties and related equipment (successful efforts method) |       | 3,416,788                    |       | 766,638                     |       |
| Less accumulated  depreciation, depletion and amortization                |       | (79,702                      | )          | (33,349                     | )          |
|                                                                      |       | 3,337,086                    |       | 733,289                     |       |
|                                                                      |       |                         |       |                        |       |
| Property and  equipment, net                                              |       | 34,956                       |       | 20,754                      |       |
|                                                                      |       |                         |       |                        |       |
| **Other  assets:**                                                        |       |                         |       |                        |       |
| Derivatives                                                               |       | 265,696                      |       | 70,435                      |       |
| Deposit for oil  and gas properties                                       |       | —                       |       | 20,086                      |       |
| Deferred  financing fees and other assets, net                            |       | 9,209                        |       | 2,068                       |       |
|                                                                      |       | 274,905                      |       | 92,589                      |       |
| Total assets                                                              |       | $                            | 3,859,031  |                        | $          | 916,308 |   |

 

*Theaccompanying notes are an integral part of these condensed consolidatedfinancial statements**.*

 

1

----

 

**LINN ENERGY, LLC**

 

**CONDENSED CONSOLIDATED BALANCESHEETS**

 
| ** **                                                                                                                         | ** ** | **September 30,  2007**                            | ** ** | **December 31,  2006** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                         | ** ** | **(Unaudited)**                                         | ** ** | ** **                  | ** ** |
| ** **                                                                                                                         | ** ** | **(in thousands,  except unit amounts)** | ** ** |
| **Liabilities and Unitholders’ Capital**                                                                                      | ** ** | ** **                                              | ** ** | ** **                  | ** ** |
|                                                                                                                               |       |                                                    |       |                        |       |
| **Current  liabilities:**                                                                                                          |       |                                                    |       |                        |       |
| Accounts payable  and accrued expenses                                                                                             |       | $                                                       | 55,674     |                        | $          | 12,759 |   |
| Current portion  of derivatives                                                                                                    |       | 31,256                                                  |       | 462                         |       |
| Joint interest  payable                                                                                                            |       | 9,294                                                   |       | 1,839                       |       |
| Accrued interest  payable                                                                                                          |       | 5,267                                                   |       | 2,084                       |       |
| Other  liabilities                                                                                                                 |       | 666                                                     |       | 873                         |       |
| Total current  liabilities                                                                                                         |       | 102,157                                                 |       | 18,017                      |       |
|                                                                                                                               |       |                                                    |       |                        |       |
| **Long-term  liabilities:**                                                                                                        |       |                                                    |       |                        |       |
| Credit facility                                                                                                                    |       | 1,302,000                                               |       | 425,750                     |       |
| Asset retirement  obligation                                                                                                       |       | 27,124                                                  |       | 8,594                       |       |
| Derivatives                                                                                                                        |       | 136,408                                                 |       | 10,357                      |       |
| Other long-term  liabilities                                                                                                       |       | 2,547                                                   |       | 2,636                       |       |
| Total long-term  liabilities                                                                                                       |       | 1,468,079                                               |       | 447,337                     |       |
| Total  liabilities                                                                                                                 |       | 1,570,236                                               |       | 465,354                     |       |
|                                                                                                                               |       |                                                    |       |                        |       |
| **Unitholders’  capital:**                                                                                                    |       |                                                    |       |                        |       |
| 78,640,050 units  and 33,617,187 units issued and outstanding at September 30, 2007 and  December 31, 2006, respectively |       | 1,366,035                                               |       | 246,034                     |       |
| 9,185,965  Class B units issued and outstanding at December 31, 2006                                                     |       | —                                                  |       | 188,590                     |       |
| 34,997,005 Class  D units issued and outstanding at September 30, 2007                                                        |       | 1,067,625                                               |       | —                      |       |
| Accumulated  income (loss)                                                                                                         |       | (144,865                                                | )          | 16,330                      |       |
|                                                                                                                               |       | 2,288,795                                               |       | 450,954                     |       |
| Total  liabilities and unitholders’ capital                                                                                   |       | $                                                       | 3,859,031  |                        | $          | 916,308 |   |

 

*Theaccompanying notes are an integral part of these condensed consolidatedfinancial statements**.*

 

2

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**LINN ENERGY, LLC**

 

**CONDENSEDCONSOLIDATED STATEMENTS OF OPERATIONS**

 

**(Unaudited)**

 
| ** **                                     | ** ** | **Three Months Ended  September 30,**                 | ** ** | **Nine Months Ended  September 30,** | ** ** |
|------------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                     | ** ** | **2007**                                                             | ** ** | **2006**                                            | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                     | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                  |       |                                                                 |       |                                                |       |   |   |   |   |
| Oil, gas and  natural gas liquid sales         |       | $                                                                    | 75,062     |                                                | $          | 23,506 |   | $ | 163,483 |   | $ | 53,410 |   |
| Gain (loss) on  oil and gas derivatives        |       | (65,440                                                              | )          | 57,396                                              |       | (143,588 | ) | 94,537 |   |
| Natural gas  marketing revenues                |       | 8,434                                                                |       | 1,090                                               |       | 11,351 |   | 3,654 |   |
| Other revenues                                 |       | 423                                                                  |       | 265                                                 |       | 3,652 |   | 758 |   |
|                                           |       | 18,479                                                               |       | 82,257                                              |       | 34,898 |   | 152,359 |   |
| **Expenses:**                                  |       |                                                                 |       |                                                |       |   |   |   |   |
| Operating  expenses                            |       | 27,465                                                               |       | 4,845                                               |       | 54,635 |   | 10,772 |   |
| Natural gas  marketing expenses                |       | 7,207                                                                |       | 954                                                 |       | 9,433 |   | 3,126 |   |
| General and  administrative expenses           |       | 13,202                                                               |       | 6,536                                               |       | 36,360 |   | 22,934 |   |
| Depreciation,  depletion and amortization      |       | 24,320                                                               |       | 5,654                                               |       | 49,109 |   | 13,470 |   |
|                                           |       | 72,194                                                               |       | 17,989                                              |       | 149,537 |   | 50,302 |   |
|                                           |       | (53,715                                                              | )          | 64,268                                              |       | (114,639 | ) | 102,057 |   |
| **Other  income and (expenses):**              |       |                                                                 |       |                                                |       |   |   |   |   |
| Interest  expense, net of amounts capitalized  |       | (16,613                                                              | )          | (10,700                                             | )          | (36,675 | ) | (16,873 | ) |
| Gain (loss) on  interest rate swaps            |       | (3,151                                                               | )          | (504                                                | )          | (2,954 | ) | 334 |   |
| Other expenses,  net                           |       | (2,422                                                               | )          | (7                                                  | )          | (2,944 | ) | (319 | ) |
|                                           |       | (22,186                                                              | )          | (11,211                                             | )          | (42,573 | ) | (16,858 | ) |
| Income (loss)  before income taxes             |       | (75,901                                                              | )          | 53,057                                              |       | (157,212 | ) | 85,199 |   |
| Income tax  benefit (provision)                |       | (321                                                                 | )          | —                                              |       | (3,983 | ) | 74 |   |
| Net income  (loss)                             |       | $                                                                    | (76,222    | )                                                   | $          | 53,057 |   | $ | (161,195 | ) | $ | 85,273 |   |
|                                           |       |                                                                 |       |                                                |       |   |   |   |   |
| **Net  income (loss) per unit:**               |       |                                                                 |       |                                                |       |   |   |   |   |
| Units – basic                             |       | $                                                                    | (0.94      | )                                                   | $          | 1.92 |   | $ | (2.60 | ) | $ | 3.14 |   |
| Units – diluted                           |       | $                                                                    | (0.94      | )                                                   | $          | 1.89 |   | $ | (2.60 | ) | $ | 3.12 |   |
| Class D – basic                           |       | $                                                                    | (0.94      | )                                                   | $          | — |   | $ | (2.60 | ) | $ | — |   |
| Class D –  diluted                        |       | $                                                                    | (0.94      | )                                                   | $          | — |   | $ | (2.60 | ) | $ | — |   |
|                                           |       |                                                                 |       |                                                |       |   |   |   |   |
| **Weighted  average units  outstanding:** |       |                                                                 |       |                                                |       |   |   |   |   |
| Units – basic                             |       | 69,207                                                               |       | 27,584                                              |       | 58,072 |   | 27,118 |   |
| Units – diluted                           |       | 69,207                                                               |       | 28,044                                              |       | 58,072 |   | 27,341 |   |
| Class D – basic                           |       | 11,792                                                               |       | —                                              |       | 3,974 |   | — |   |
| Class D –  diluted                        |       | 11,792                                                               |       | —                                              |       | 3,974 |   | — |   |
|                                           |       |                                                                 |       |                                                |       |   |   |   |   |
| Distributions  declared per unit               |       | $                                                                    | 0.57       |                                                | $          | 0.40 |   | $ | 1.61 |   | $ | 0.72 |   |

 

*Theaccompanying notes are an integral part of these condensed consolidatedfinancial statements**.*

 

3

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**LINN ENERGY, LLC**

 

**CONDENSEDCONSOLIDATED STATEMENTS OF UNITHOLDERS’ CAPITAL**

 

**(Unaudited)**

 
| ** **                                                               | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|--------------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                               | ** ** | **2007**                                             | ** ** | **2006**                                            | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                               | ** ** | **(in thousands)**                              | ** ** |
| **Unitholders’  capital:**                                          |       |                                                 |       |                                                |       |   |   |   |   |
| Balance,  beginning of period                                            |       | $                                                    | 990,702    |                                                | $          | 141,355 |   | $ | 434,624 |   | $ | 16,024 |   |
| Sale of units,  net of expenses of $4,339                                |       | —                                               |       | —                                              |       | — |   | 225,139 |   |
| Sale of private  placement units, net of expenses of $22,804 and $34,272 |       | 1,477,196                                            |       | —                                              |       | 2,085,728 |   | — |   |
| Cancellation of  member interests                                        |       | —                                               |       | —                                              |       | — |   | (100,778 | ) |
| Cancellation of  units                                                   |       | —                                               |       | —                                              |       | (7,399 | ) | — |   |
| Distribution to  unitholders                                             |       | (37,419                                              | )          | (11,033                                             | )          | (90,165 | ) | (19,859 | ) |
| Unit-based  compensation and unit warrant expense                        |       | 3,199                                                |       | 4,068                                               |       | 10,890 |   | 13,864 |   |
| Exercise of unit  options                                                |       | (18                                                  | )          | —                                              |       | (18 | ) | — |   |
| Balance, end of  period                                                  |       | 2,433,660                                            |       | 134,390                                             |       | 2,433,660 |   | 134,390 |   |
| **Accumulated  income (loss):**                                          |       |                                                 |       |                                                |       |   |   |   |   |
| Balance,  beginning of period                                            |       | (68,643                                              | )          | (30,639                                             | )          | 16,330 |   | (62,855 | ) |
| Net income  (loss)                                                       |       | (76,222                                              | )          | 53,057                                              |       | (161,195 | ) | 85,273 |   |
| Balance, end of  period                                                  |       | (144,865                                             | )          | 22,418                                              |       | (144,865 | ) | 22,418 |   |
| **Treasury  units (at cost):**                                           |       |                                                 |       |                                                |       |   |   |   |   |
| Balance,  beginning of period                                            |       | —                                               |       | —                                              |       | — |   | — |   |
| Purchase of  units                                                       |       | —                                               |       | —                                              |       | (7,399 | ) | — |   |
| Sale of units                                                            |       | —                                               |       | —                                              |       | — |   | 13,671 |   |
| Redemption of  member interests                                          |       | —                                               |       | —                                              |       | — |   | (114,449 | ) |
| Cancellation of  member interests                                        |       | —                                               |       | —                                              |       | — |   | 100,778 |   |
| Cancellation of  units                                                   |       | —                                               |       | —                                              |       | 7,399 |   | — |   |
| Balance, end of  period                                                  |       | —                                               |       | —                                              |       | — |   | — |   |
| Total  unitholders’ capital                                         |       | $                                                    | 2,288,795  |                                                | $          | 156,808 |   | $ | 2,288,795 |   | $ | 156,808 |   |

 

*Theaccompanying notes are an integral part of these condensed consolidatedfinancial statements**.*

 

4

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**LINN ENERGY, LLC**

 

**CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS**

 

**(Unaudited)**

 
| ** **                                                                                        | ** ** | **Nine Months Ended September 30,** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                                                                        | ** ** | **2007**                                                | ** ** | **2006** | ** ** |
| ** **                                                                                        | ** ** | **(in thousands)**                                 | ** ** |
| **Cash  flow from operating activities:**                                                         |       |                                                    |       |   |   |
| Net income  (loss)                                                                                |       | $                                                       | (161,195   | ) | $ | 85,273 |   |
| **Adjustments  to reconcile net income to net cash provided by (used in) operating  activities:** |       |                                                    |       |   |   |
| Depreciation,  depletion and amortization                                                         |       | 49,109                                                  |       | 13,470 |   |
| Amortization and  write-off of deferred financing fees and other                                  |       | 3,531                                                   |       | 1,650 |   |
| Gain on sale of  assets                                                                           |       | (867                                                    | )          | — |   |
| Accretion of  asset retirement obligation                                                         |       | 577                                                     |       | 180 |   |
| Unit-based  compensation and unit warrant expense                                                 |       | 10,890                                                  |       | 13,864 |   |
| Deferred income  tax                                                                              |       | 3,359                                                   |       | (307 | ) |
| **Mark-to-market  on derivatives:**                                                               |       |                                                    |       |   |   |
| Total (gains)  losses                                                                             |       | 146,542                                                 |       | (94,637 | ) |
| Realized gains                                                                                    |       | 24,896                                                  |       | 11,447 |   |
| **Premiums  paid for derivatives**                                                                |       | (257,092                                                | )          | (14,228 | ) |
| **Changes  in assets and liabilities:**                                                           |       |                                                    |       |   |   |
| (Increase)  decrease in accounts receivable                                                       |       | (47,163                                                 | )          | (3,089 | ) |
| Decrease in  inventory and other assets                                                           |       | 3,443                                                   |       | 3,542 |   |
| Increase  (decrease) in derivative receivables                                                    |       | 7,171                                                   |       | (474 | ) |
| Increase  (decrease) in accounts payable and accrued expenses                                     |       | 16,750                                                  |       | (5,821 | ) |
| Increase in  accrued interest payable                                                             |       | 3,183                                                   |       | 2,284 |   |
| Increase  (decrease) in joint interest payable                                                    |       | 7,455                                                   |       | (5,101 | ) |
| Increase  (decrease) in other liabilities                                                         |       | 1,443                                                   |       | (69 | ) |
| Net cash  provided by (used in) operating activities                                              |       | (187,968                                                | )          | 7,984 |   |
| **Cash  flow from investing activities:**                                                         |       |                                                    |       |   |   |
| Acquisition of  oil and gas properties                                                            |       | (2,572,614                                              | )          | (469,274 | ) |
| Development of  oil and gas properties                                                            |       | (54,170                                                 | )          | (33,573 | ) |
| Purchases of  property and equipment                                                              |       | (12,494                                                 | )          | (6,259 | ) |
| Proceeds from  sale of assets                                                                     |       | 2,974                                                   |       | 21 |   |
| Net cash used in  investing activities                                                            |       | (2,636,304                                              | )          | (509,085 | ) |
| **Cash  flow from financing activities:**                                                         |       |                                                    |       |   |   |
| Proceeds from  sale of units                                                                      |       | 2,120,000                                               |       | 243,149 |   |
| Redemption and  cancellation of units                                                             |       | (7,399                                                  | )          | (114,449 | ) |
| Principal  payments on notes payable                                                              |       | (2,197                                                  | )          | (597 | ) |
| Proceeds from  credit facilities                                                                  |       | 1,140,000                                               |       | 261,303 |   |
| Payments on  credit facilities                                                                    |       | (263,750                                                | )          | (62,000 | ) |
| Proceeds from  subordinated term loan                                                             |       | —                                                  |       | 250,000 |   |
| Principal  payments on subordinated term loan                                                     |       | —                                                  |       | (60,000 | ) |
| Distribution to  members                                                                          |       | (90,165                                                 | )          | (19,859 | ) |
| Offering costs                                                                                    |       | (34,272                                                 | )          | (844 | ) |
| Financing fees  and other                                                                         |       | (10,952                                                 | )          | (4,881 | ) |
| Net cash  provided by financing activities                                                        |       | 2,851,265                                               |       | 491,822 |   |
| Net increase  (decrease) in cash                                                                  |       | 26,993                                                  |       | (9,279 | ) |
| **Cash  and cash equivalents:**                                                                   |       |                                                    |       |   |   |
| Beginning                                                                                         |       | 6,595                                                   |       | 11,041 |   |
| Ending                                                                                            |       | $                                                       | 33,588     |   | $ | 1,762 |   |

 

*Theaccompanying notes are an integral part of these condensed consolidatedfinancial statements**.*

 

5

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**LINN ENERGY, LLC**

 

**CONDENSED CONSOLIDATED STATEMENTSOF CASH FLOWS – SUPPLEMENTAL DISCLOSURES**

 

**(Unaudited)**

 
| ** **                                                                                        | ** ** | **Nine Months Ended  September 30,** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                                        | ** ** | **2007**                                            | ** ** | **2006** | ** ** |
| ** **                                                                                        | ** ** | **(in thousands)**                             | ** ** |
| **Supplemental  disclosure of cash flow information:**                                            |       |                                                |       |   |   |
| Cash payments  for interest                                                                       |       | $                                                   | 29,339     |   | $ | 13,603 |   |
| **Supplemental  disclosures of non-cash investing and financing activities:**                     |       |                                                |       |   |   |
| Acquisitions of  vehicles and equipment through issuance of notes payable                         |       | $                                                   | 486        |   | $ | 2,648 |   |
| In connection  with the purchase of oil and gas properties, liabilities were assumed as  follows: |       |                                                |       |   |   |
| Fair value of  assets acquired                                                                    |       | $                                                   | 2,581,913  |   | $ | 472,499 |   |
| Cash paid                                                                                         |       | (2,572,614                                          | )          | (469,274 | ) |
| Liabilities  assumed, net                                                                         |       | $                                                   | 9,299      |   | $ | 3,225 |   |

 

*Theaccompanying notes are an integral part of these condensed consolidatedfinancial statements**.*

 

6

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**LINN ENERGY, LLC**

** **

**NOTES TOCONDENSED CONSOLIDATED FINANCIAL STATEMENTS**

 

**(Unaudited)**

 

**(1)****                                 Basis of Presentationand Significant Accounting Policies**

 

Linn Energy, LLC (“Linn”or the “Company”) is an independent oil and gas company focused on thedevelopment and acquisition of long-lived properties in the United States thatbegan operations in March 2003 and was formed as a Delaware limited liabilitycompany in April 2005.

 

The condensedconsolidated financial statements at September 30, 2007, and for the threeand nine months ended September 30, 2007 and 2006, are unaudited, but inthe opinion of management include all adjustments (consisting only of normalrecurring adjustments) necessary for a fair presentation of the results for theinterim periods. Certain information and note disclosures normally included inannual financial statements prepared in accordance with United States generallyaccepted accounting principles (“GAAP”) have been condensed or omitted underSecurities and Exchange Commission (“SEC”) rules and regulations. The resultsreported in these unaudited condensed consolidated financial statements shouldnot necessarily be taken as indicative of results that may be expected for theentire year.

 

The financial informationincluded herein should be read in conjunction with the financial statements andnotes in the Company’s Annual Report on Form 10-K for the year endedDecember 31, 2006. Certain amounts in the condensed consolidated financialstatements and notes thereto have been reclassified to conform to the 2007financial statement presentation.

 

The condensedconsolidated financial statements include the accounts of the Company and itswholly-owned subsidiaries. All significant intercompany transactions andbalances have been eliminated upon consolidation.

 

Management of the Companyhas made a number of estimates and assumptions relating to the reporting ofassets and liabilities and revenues and expenses and the disclosure ofcontingent assets and liabilities to prepare these condensed consolidatedfinancial statements in conformity with GAAP. Actual results could differ fromthose estimates. The estimates that are particularly significant to thefinancial statements include estimates of oil, gas and natural gas liquid (“NGL”)reserves, future cash flows from oil and gas properties, depreciation,depletion and amortization, asset retirement obligations, the fair value ofderivatives and unit-based compensation expense.

 

As of September 30,2007, there have been no significant changes with regard to the criticalaccounting policies disclosed in the Company’s Annual Report on Form 10-Kfor the year ended December 31, 2006. The policies disclosed included theaccounting for oil and gas properties, reserve quantities, revenue recognition,purchase accounting and derivative instruments. Several of the more significantaccounting policies are summarized below.

 

***Oiland Gas Properties***

*** ***

The Company accounts for oil and gas properties by thesuccessful efforts method. Leasehold acquisition costs are capitalized. Ifproved reserves are found on an undeveloped property, leasehold costs aretransferred to proved properties. Under this method of accounting, costsrelating to the development of proved areas are capitalized when incurred, andgeological and geophysical costs are charged to expense as incurred. Exploratorydry hole costs on oil and gas properties relating to unsuccessful exploratorywells are charged to expense as incurred.

 

7

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Depreciation and depletion of producing oil and gasproperties is recorded based on units of production. Unit rates are computed inaccordance with Statement of Financial Accounting Standards (“SFAS”)No. 19, as amended, “*Financial Accounting andReporting by Oil and Gas Producing Companies*” (“SFAS 19”),which requires that acquisition costs of proved properties be amortized on thebasis of all proved reserves, developed and undeveloped, and that capitalizeddevelopment costs (wells and related equipment and facilities) be amortized onthe basis of proved developed reserves.

 

***DerivativeInstruments and Hedging Activities***

*** ***

The Company uses derivative financial instruments to achievea more predictable cash flow from its oil, gas and NGL production by reducingits exposure to price fluctuations. As of September 30, 2007, thesetransactions were in the form of swaps and puts. Additionally, the Company usesderivative financial instruments in the form of interest rate swaps to mitigateits interest rate exposure. The Company accounts for its derivatives at fairvalue as an asset or liability and the change in the fair value of derivativesis included in income. The Company accounts for these activities pursuant toSFAS No. 133, “*Accounting forDerivative Instruments and Hedging Activities,”* as amended, (“SFAS 133”).This statement establishes accounting and reporting standards requiring thatderivative instruments (including certain derivative instruments embedded inother contracts) be recorded at fair value and included in the balance sheetsas assets or liabilities. None of the Company’s commodity or interest ratederivatives are designated as hedges under SFAS 133 and therefore thechange in the fair value of the derivatives is included in the condensedconsolidated statements of operations. See Note 11 for additionaldiscussion related to derivative financial instruments.

 

***Unit-BasedCompensation***

*** ***

Under the provisions of the Linn Energy, LLC Long-TermIncentive Plan, which is administered by the Compensation Committee of theBoard of Directors, the Company has awarded unit grants, unit options,restricted units, and phantom units to employees and non-employee directors. Theunit options and restricted units vest ratably over one to three years from thegrant date of the award, unless other contractual arrangements are made. Thecontractual life of unit options is ten years. See Note 13 for detailsregarding unit-based compensation granted during the nine months endedSeptember 30, 2007.

 

The Company accounts for unit-based compensation under theprovisions of SFAS No. 123 (revised 2004),*“Share Based Payment”* (“SFAS 123R”). SFAS 123Rrequires the recognition of compensation expense, over the requisite serviceperiod, in an amount equal to the fair value of unit-based payments granted.

 

***Inventories***

*** ***

Materials, supplies and commodity inventories are valued atthe lower of average cost or market, determined by the first-in-first-outmethod.

 

***RecentlyIssued Accounting Standards***

*** ***

In June 2007, the Financial Accounting Standards Board (“FASB”)ratified the consensus in Emerging Issues Task Force Issue 06-11 (“EITF 06-11”).EITF 06-11 is effective for fiscal years beginning after December 15, 2007 andrequires, among other things, recognition as an increase to additional paid-incapital the realized income tax benefit from dividends or dividend equivalentsthat are paid to employees and charged to retained earnings. The Company is inthe process of evaluating the impact of EITF 06-11 on its results of operationsand financial position, but does not expect it will be material.

 

In April 2007, the FASB issued Staff Position No. 39-1, “*Amendment of FASB Interpretation No. 39*” (“FSP No.FIN 39-1”). The terms “conditional contracts” and “exchange contracts”have been replaced with the more general term “derivative contracts.”  In addition, FSP No. FIN 39-1 permitsthe offsetting of recognized fair values for the right to reclaim cashcollateral or the obligation to return cash collateral against fair values ofderivatives under certain circumstances, such as under master nettingarrangements. Additional disclosure is also required regarding a Company’saccounting policy with respect to offsetting

 

8

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fair value amounts. The guidance in FSP No. FIN 39-1 iseffective for fiscal years beginning after November 15, 2007, with earlyapplication allowed. The effects of initial adoption should be recognized as achange in accounting principle through retrospective application for allperiods presented. The Company does not believe that the adoption of FSP No.FIN 39-1 will have a material impact on its results of operations orfinancial position.

 

In February 2007, the FASB issued SFAS No. 159, “*The Fair Value Option for Financial Assets and Financial Liabilities,including an amendment of FASB Statement No. 115*” (“SFAS 159”),which permits companies to choose, at specified dates, to measure certaineligible financial instruments at fair value. The objective of SFAS 159 isto reduce volatility in preparer reporting that may be caused as a result ofmeasuring related financial assets and liabilities differently and to expandthe use of fair value measurements. The provisions of SFAS 159 apply onlyto entities that elect to use the fair value option and to all entities withavailable-for-sale and trading securities. Additional disclosures are alsorequired for instruments for which the fair value option is elected. SFAS 159is effective for fiscal years beginning after November 15, 2007. Noretrospective application is allowed, except for companies that choose to adoptearly. At the effective date, companies may elect the fair value option foreligible items that exist at that date, and the effect of the firstremeasurement to fair value must be reported as a cumulative-effect adjustmentto the opening balance of retained earnings. The Company is currentlyevaluating what impact, if adopted, SFAS 159 may have on its results ofoperations or financial position.

 

In September 2006, the FASB issued SFAS No. 157, “*Fair Value Measurements*” (“SFAS 157”), which providesguidance for using fair value to measure assets and liabilities. SFAS 157applies whenever other standards require (or permit) assets or liabilities tobe measured 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 mark-to-market value. SFAS 157 also requires expandeddisclosure of the effect on earnings for items measured using unobservable data.The provisions of SFAS 157 are effective for financial statements issued forfiscal years beginning after November 15, 2007, and interim periods withinthose fiscal years. The Company is currently evaluating the effect that theimplementation of SFAS 157 will have on its results of operations and financialcondition.

 

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

 

On February 1, 2007,effective January 1, 2007, the Company completed the acquisition ofcertain oil and gas properties and related assets in the Texas Panhandle fromStallion Energy LLC, acting as general partner for Cavallo Energy, LP, for acontract price of $415.0 million (“Panhandle I”). The Panhandle Iacquisition was financed with a combination of a private placement of units(see Note 3) and borrowings under the Company’s credit facility (seeNote 6).

 

On June 12, 2007,effective April 1, 2007, the Company completed the acquisition of certainoil and gas properties in the Texas Panhandle for a contract price of $90.5million (“Panhandle II”). The acquisition was financed with borrowingsunder the Company’s credit facility.

 

On August 31, 2007,effective July 1, 2007, the Company completed the acquisition of certainoil and gas properties in the Mid-Continent, in Oklahoma, Kansas and the TexasPanhandle for a contract price of $2.05 billion from Dominion Resources,Inc. and certain affiliates (“Dominion”) (“Mid-Continent”). On August 31,2007, the Company completed the private placement of $1.5 billion of unitsand Class D units to a group of institutional investors (see Note 3).In addition, on August 31, 2007, the Company entered into a new $1.8billion credit facility (see Note 6). The Company funded the Mid-Continentacquisition with the net proceeds from the private placement, together withborrowings under its credit facility.

 

9

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The following tablepresents the preliminary purchase accounting for the Panhandle I,Panhandle II and Mid-Continent acquisitions, based on preliminaryestimates of fair value:

 
| ** **                             | ** ** | **Panhandle I**    | ** ** | **Panhandle II** | ** ** | **Mid-Continent** | ** ** |
|----------------------------------------|------------|-------------------------|------------|-----------------------|------------|-------------------|------------|
| ** **                             | ** ** | **(in thousands)** | ** ** |
|                                   |       |                    |       |                  |       |              |       |
| Cash                                   |       | $                       | 411,287    |                  | $          | 90,179            |       | $ | 2,022,606 |   |
| Estimated  transaction costs           |       | 2,996                   |       | 366                   |       | 6,790             |       |
| Estimated pending  closing adjustments |       | —                  |       | (1,440                | )          | (23,500           | )          |
|                                   |       | 414,283                 |       | 89,105                |       | 2,005,896         |       |
| Fair value of  liabilities assumed     |       | 1,706                   |       | 1,034                 |       | 24,569            |       |
| Total purchase  price                  |       | $                       | 415,989    |                  | $          | 90,139            |       | $ | 2,030,465 |   |

 

The following table presents the preliminary allocation of the purchaseprices based on preliminary estimates of fair value:

 
| ** **                             | ** ** | **Panhandle I**    | ** ** | **Panhandle II** | ** ** | **Mid-Continent** | ** ** |
|----------------------------------------|------------|-------------------------|------------|-----------------------|------------|-------------------|------------|
| ** **                             | ** ** | **(in thousands)** | ** ** |
|                                   |       |                    |       |                  |       |              |       |
| Accounts  receivable                   |       | $                       | —     |                  | $          | —            |       | $ | 27,915 |   |
| Other current  assets                  |       | —                  |       | 644                   |       | 6,326             |       |
| Oil and gas  properties                |       | 415,251                 |       | 89,495                |       | 2,017,189         |       |
| Property, plant  and equipment         |       | 738                     |       | —                |       | 3,604             |       |
| Accounts payable  and accrued expenses |       | —                  |       | —                |       | (24,569           | )          |
|                                   |       | $                       | 415,989    |                  | $          | 90,139            |       | $ | 2,030,465 |   |

 

The preliminary purchase prices and purchase price allocations above arebased on preliminary reserve reports, quoted market prices and estimates bymanagement. The most significant assumptions are related to the estimated fairvalues assigned to proved oil and gas properties. To estimate the fair valuesof these properties, the Company utilized preliminary estimates of oil, gas andNGL reserves prepared by an independent engineering firm. The Company estimatedfuture prices to apply to the estimated reserve quantities acquired, andestimated future operating and development costs, to arrive at estimates offuture net revenues. The Company also reviewed comparable purchases and salesof oil and gas properties within the same regions. As noted, the purchaseprices and the allocations of the purchase prices are preliminary. Items pendingcompletion include final closing adjustments for all three acquisitions and forthe Mid-Continent acquisition include completion of independent appraisals offixed assets, and additional analysis related to the fair value of proved andunproved oil and gas reserves, including discounted cash flows and market-baseddata, and the valuation of certain assumed liabilities. The purchase prices andpurchase price allocations will be finalized within one year of the acquisitiondates.

 

The following unaudited pro forma financial information presents a summaryof Linn’s consolidated results of operations for the three and nine monthsended September 30, 2007 and 2006, assuming the Panhandle I,Panhandle II and Mid-Continent acquisitions and the related privateplacement of units and Class D units (see Note 3) had been completedas of January 1, 2006, including adjustments to reflect the allocation ofthe purchase prices to the acquired net assets. The pro forma financialinformation also assumes that the acquisitions of California assets fromaffiliated entities of Blacksand Energy, LLC and Oklahoma assets fromKaiser-Francis Oil Company were completed as of January 1, 2006. TheCalifornia and Oklahoma acquisitions were completed in 2006 and the revenuesand expenses are included in the consolidated results of the Company effectiveAugust 1, 2006 and September 1, 2006, respectively. The revenues andexpenses of the Panhandle I and Panhandle II assets are included inthe consolidated results of the Company as of February 1, 2007 andJune 12, 2007, respectively. The revenues and expenses of theMid-Continent assets are

 

10

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included in the consolidated results of the Company effectiveSeptember 1, 2007. The pro forma financial information is not necessarilyindicative of the results of operations if the acquisitions had been effectiveas of these dates.

 
| ** **                         | ** ** | **Three Months Ended  September 30,**                 | ** ** | **Nine Months Ended  September 30,** | ** ** |
|------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                         | ** ** | **2007**                                                             | ** ** | **2006**                                            | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                         | ** ** | **(in thousands, except per unit amounts)** | ** ** |
|                               |       |                                                                 |       |                                                |       |   |   |   |   |
| Total revenues                     |       | $                                                                    | 75,479     |                                                | $          | 196,228 |   | $ | 261,791 |   | $ | 534,305 |   |
| Total operating  expenses          |       | $                                                                    | 92,487     |                                                | $          | 78,318 |   | $ | 274,741 |   | $ | 238,419 |   |
| Net income  (loss)                 |       | $                                                                    | (43,023    | )                                                   | $          | 91,086 |   | $ | (90,447 | ) | $ | 220,365 |   |
|                               |       |                                                                 |       |                                                |       |   |   |   |   |
| Net income  (loss) per unit:       |       |                                                                 |       |                                                |       |   |   |   |   |
| Units – basic                 |       | $                                                                    | (0.38      | )                                                   | $          | 1.21 |   | $ | (0.86 | ) | $ | 2.93 |   |
| Units – diluted               |       | $                                                                    | (0.38      | )                                                   | $          | 1.20 |   | $ | (0.86 | ) | $ | 2.93 |   |
|                               |       |                                                                 |       |                                                |       |   |   |   |   |
| Class D  units – basic   |       | $                                                                    | (0.38      | )                                                   | $          | 1.21 |   | $ | (0.86 | ) | $ | 2.93 |   |
| Class D  units – diluted |       | $                                                                    | (0.38      | )                                                   | $          | 1.20 |   | $ | (0.86 | ) | $ | 2.93 |   |

 

The unaudited pro forma condensed combined statements of operationspresent net income (loss) per unit allocated to the units and the Class Dunits on an equal basis. In November 2007, at a special meeting of Linn unitholders,unitholders approved the one-for-one conversion of each of the Class Dunits into units. Therefore, pro forma net income (loss) per unit assumes thatthe units and Class D units share equally in the pro forma net income(loss) of the Company.

 

In addition, during 2007,the Company completed the following other acquisitions:

 

•                  January2007 – gas properties located in the Appalachian Basin of West Virginia for acontract price of $39.0 million

 

•                  April2007 – net profits interest in oil and gas properties in California for acontract price of $10.0 million

 

•                  October2007 – working or royalty interests in oil and gas properties primarily in theMid-Continent in two separate transactions for contract prices totaling $74.5million

 

In March 2007, theCompany sold certain of its oil and gas properties located in New York for cashof approximately $2.5 million and recorded a gain of approximately $0.9million. The gain is included in “other revenues” on the condensed consolidatedstatements of operations.

 

**(3)****                                 Unitholders’ Capital**

 

***August 2007 Private Placement***

 

In August 2007, the Company closed its privateplacement of $1.5 billion of units to a group of institutional investors,consisting of 34,997,005 Class D units at a price of $30.97 per unit and12,999,989 units at a price of $32.00 per unit (“August 2007 Private Placement”).Proceeds, net of expenses, were $1.48 billion and were used to fund theMid-Continent acquisition (see Note 2).

 

11

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The Class D units represent a class of equitysecurities that is entitled to a special quarterly distribution equal to 115%of the distribution received by the holders of units, has no voting rightsother than as required by law and is subordinated to the units on dissolutionand liquidation. In November 2007, at a special meeting of Linn unitholders,unitholders approved the one-for-one conversion of the Class D units intounits. In connection with the August 2007 Private Placement, the Company agreedto file a Registration Statement with the SEC covering the units and the ClassD units. See “Liquidated Damages” below for details regarding potentialpenalties that could be incurred by the Company in the event the RegistrationStatement is not declared effective by the SEC on or prior to February 12,2008.

 

***June 2007 Private Placement***

 

In June 2007, the Company closed its private placement of $260.0 millionof units to a group of institutional investors, consisting of 7,761,194 unitsat a price of $33.50 per unit (the “June 2007 Private Placement”). Proceeds,net of expenses, were $255.2 million and were used to repay indebtedness underthe Company’s credit facility (see Note 6). In connection with the June2007 Private Placement, the Company agreed to file a Registration Statementwith the SEC covering the units. As discussed below under “February 2007Private Placement” and “October 2006 Private Placement,” the Company’sRegistration Statement on Form S-3, as amended, to register units issuedin the October 2006 and February 2007 offerings, has not yet been declaredeffective by the SEC. Under the terms of the registration rights agreement withthe purchasers in the June 2007 Private Placement, the Company cannot file aRegistration Statement to register the units issued in the June 2007 PrivatePlacement until the Registration Statement covering the units issued in theFebruary 2007 and October 2006 Private Placements is declared effective. See “LiquidatedDamages” below for details regarding potential penalties that could be incurredby the Company in the event the Registration Statement is not declaredeffective by the SEC on or prior to November 13, 2007.

 

***February 2007 Private Placement***

 

In February 2007, the Company closedits private placement of $360.0 million of units to a group of institutionalinvestors, consisting of 7,465,946 Class C units at a price of$25.06 per unit, and 6,650,144 units at a price of $26.00 per unit (the “February2007 Private Placement”). Proceeds, net of expenses, were $353.1 million andwere used to finance the Panhandle I acquisition and the acquisitions ofcertain gas properties in West Virginia (see Note 2).

 

The Class C units were converted into units on a one-for-one basis inApril 2007. The Company filed a Registration Statement on Form S-3 withthe SEC covering the units in September 2007 and Amendment No. 1 toForm S-3 in October 2007. Under the registration rights agreement, asamended, liquidated damages could become payable if the Registration Statementis not declared effective by the SEC on or prior to December 31, 2007. TheRegistration Statement, as amended, has not yet been declared effective by theSEC. See “Liquidated Damages” below.

 

***October 2006 Private Placement***

 

In connection with its October 2006 private placement of units and Class Bunits (Class B units were converted to units on a one-for-one basis inJanuary 2007), (the “October 2006 Private Placement”), the Company filed aRegistration Statement on Form S-3 with the SEC covering the units inSeptember 2007 and Amendment No. 1 to Form S-3 in October 2007. Underthe registration rights agreement, as amended, liquidated damages could becomepayable if the Registration Statement is not declared effective by the SEC onor prior to December 31, 2007. The Registration Statement, as amended, hasnot yet been declared effective by the SEC. See “Liquidated Damages” below.

 

12

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***Liquidated Damages***

 

The Company could be required to pay purchasers liquidated damagesspecified in agreements pursuant to the October 2006, February 2007, June 2007and August 2007 Private Placements in the event the registration effectivenessdeadlines noted above are not achieved. The potential payments under theagreements are 0.25% of the gross proceeds for each 30 day period that theregistration deadlines are not met, up through 90 days. Subsequent to 90 days,the potential payments would increase for each 30 day period, up to a maximumof 1.0% of the gross proceeds of each offering. As of the date of this report,based on the facts discussed in “June 2007 Private Placement” above, it isreasonably possible that the Company may be required to make some amount ofsuch payments; however, the Company does not expect payments under theseagreements to be material to the Company’s financial position or results ofoperations.

 

***Cancellation of Units***

 

In January 2007, theCompany purchased 226,561 restricted units from an employee for $7.4 million(market price on the day of purchase) in conjunction with the vesting ofrestricted unit awards. The proceeds were used to fund the employee’s payrolltaxes on the award, and the Company cancelled the units.

 

***Issuance of Units***

 

In October 2007, theCompany issued 77,381 units in connection with the acquisition of royaltyinterests in certain oil and gas properties.

 

***Initial Public Offering***

 

In the first quarter of2006, the Company completed its initial public offering (“IPO”) of 12,450,000units representing limited liability company interests in the Company at $21.00per unit, for net proceeds, after underwriting discounts of $18.3 million andoffering expenses of $4.3 million, of $238.8 million, of which $122.0 millionwas used to reduce indebtedness, $114.4 million was used to redeem a portion ofthe 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)****                                 Oil and GasCapitalized Costs**

 

Aggregate capitalizedcosts related to oil, gas and NGL production activities with applicableaccumulated depreciation, depletion and amortization are presented below:

 
| ** **                                                 | ** ** | **September 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                 | ** ** | **(in thousands)**      | ** ** |
|                                                       |       |                         |       |                        |       |
| Unproved  properties                                       |       | $                            | 9,117      |                        | $          | 8,624 |   |
| Proved properties:                                         |       |                         |       |                        |       |
| Leasehold,  equipment and drilling                         |       | 3,288,130                    |       | 737,202                     |       |
| Gas compression  plant and pipelines                       |       | 119,541                      |       | 20,812                      |       |
|                                                       |       | 3,416,788                    |       | 766,638                     |       |
| Less accumulated  depletion, depreciation and amortization |       | (79,702                      | )          | (33,349                     | )          |
| Net capitalized  costs                                     |       | $                            | 3,337,086  |                        | $          | 733,289 |   |

 

13

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**(5)****                                 Property and Equipment**

 

Property and equipment consists of the following:

 
| ** **                            | ** ** | **September 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|---------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                            | ** ** | **(in thousands)**      | ** ** |
|                                  |       |                         |       |                        |       |
| Land                                  |       | $                            | 326        |                        | $          | 308 |   |
| Buildings and  leasehold improvements |       | 8,178                        |       | 2,759                       |       |
| Vehicles                              |       | 7,203                        |       | 3,097                       |       |
| Aircraft                              |       | 5,890                        |       | 5,890                       |       |
| Drilling and  other equipment         |       | 12,909                       |       | 8,611                       |       |
| Furniture and  office equipment       |       | 4,748                        |       | 1,966                       |       |
|                                  |       | 39,254                       |       | 22,631                      |       |
| Less accumulated  depreciation        |       | (4,298                       | )          | (1,877                      | )          |
|                                  |       | $                            | 34,956     |                        | $          | 20,754 |   |

 

Depreciation expense for the three and nine months endedSeptember 30, 2007, was approximately $1.0 million and $2.5 million,respectively. Depreciation expense for the three and nine months endedSeptember 30, 2006, was approximately $0.2 million and $0.6 million,respectively.

 

**(6)****                                 Credit Facility**

 

On August 31, 2007, the Company entered into a $1.8 billion ThirdAmended and Restated Credit Agreement (“Credit Facility”), which amended andrestated the Company’s prior credit facility. The Credit Facility has anavailable borrowing base of $1.8 billion, of which $1.65 billion is conforming,and a maturity of August 2010. In connection with its new Credit Facility, theCompany paid approximately $9.3 million in financing fees, which were deferredand are being amortized over the life of the Credit Facility. In addition,during the three and nine months ended September 30, 2007, the Companywrote off deferred financing fees related to its prior credit facility of approximately$2.2 million and $2.8 million, respectively.

 

The borrowing base under the Credit Facility will be redeterminedsemi-annually by the lenders in their sole discretion, based on, among otherthings, reserve reports as prepared by reserve engineers taking into accountthe oil and gas prices at such time. The Company’s obligations under the CreditFacility are secured by mortgages on its oil and gas properties as well as apledge of all ownership interests in its operating subsidiaries. The Company isrequired to maintain the mortgages on properties representing at least 80% ofits oil and gas properties. Additionally, the obligations under the CreditFacility are guaranteed by all of the Company’s operating subsidiaries and maybe guaranteed by any future subsidiaries.

 

At the Company’s election, interest on borrowings under the CreditFacility is determined by reference to either LIBOR plus an applicable marginbetween 1.00% and 2.25% per annum or the alternate base rate (“ABR”) plus anapplicable margin between 0% and 0.75% per annum. Interest is generally payablequarterly for ABR loans and at the applicable maturity date for LIBOR loans.

 

The Credit Facility contains various covenants, substantially similar tothe prior credit facility, that limit the Company’s ability to incurindebtedness, enter into interest rate swaps, grant certain liens, make certainloans, acquisitions, capital expenditures and investments, make distributionsother than from available cash, merge or consolidate, or engage in certainasset dispositions, including a sale of all or substantially all of its assets.The Credit Facility also contains covenants, substantially similar to the priorcredit facility, that require the

 

14

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Company to maintain specified financial ratios. The other terms andconditions of the Credit Facility are substantially similar to the prior creditfacility.

 

As of September 30, 2007 and December 31, 2006, the CreditFacility consisted of the following:

 
| ** **               | ** ** | **September 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|--------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **               | ** ** | **(in thousands)**      | ** ** |
|                     |       |                         |       |                        |       |
| Total (1)                |       | $                            | 1,302,000  |                        | $          | 425,750 |   |
| Less current  maturities |       | —                       |       | —                      |       |
|                     |       | $                            | 1,302,000  |                        | $          | 425,750 |   |

 

----

(1)         Variable rate of 7.188%and 7.125% at September 30, 2007 and December 31, 2006, respectively.

 

At September 30, 2007, the Company also had $2.5 million outstandingletters of credit, which reduce its borrowing availability under the CreditFacility. At September 30, 2007, available borrowing under the CreditFacility was $495.5 million. See Note 8 for details about the Company’sinterest rate swaps.

 

**(7)****                                 Long-term NotesPayable**

 

The Company has the following long-term notes payable outstanding:

 
| ** **                                                                                                                                                                                                                                                                                                                                                                                           | ** ** | **September 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                                                                                                                                                                                                                                           | ** ** | **(in thousands)**      | ** ** |
| Note payable to  a bank with an interest rate of 6.14%, payable in monthly installments of  approximately $3, including interest, through September 2024. The note is  secured by an office building.                                                                                                                                                                                                |       | $                            | 363        |                        | $          | 372 |   |
| Various notes  for the purchase of vehicles and equipment, payable in monthly installments  totaling approximately $59 and $88, as of September 30, 2007 and  December 31, 2006, respectively, including interest. The interest rates  range from 3.90%-8.25%. The notes are secured by the vehicles and equipment  purchased and expire at various dates from 2007 through 2011. (1) |       | 1,259                        |       | 2,988                       |       |
|                                                                                                                                                                                                                                                                                                                                                                                                 |       | 1,622                        |       | 3,360                       |       |
| Less current  maturities                                                                                                                                                                                                                                                                                                                                                                             |       | (666                         | )          | (873                        | )          |
|                                                                                                                                                                                                                                                                                                                                                                                                 |       | $                            | 956        |                        | $          | 2,487 |   |

 

----

(1)         At September 30, 2007 andDecember 31, 2006, includes approximately $1.1 million and $1.0 million,respectively, of notes payable on which interest was imputed at 7.0%.

 

15

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As of September 30, 2007, maturities on the aforementioned long-termnotes payable were as follows:

 
| ** ** | ** ** | **(in thousands)** | ** ** |
|------------|------------|-------------------------|------------|
|       |       |                    |       |
| 2007       |       | $                       | 159        |   |
| 2008       |       | 601                     |       |
| 2009       |       | 406                     |       |
| 2010       |       | 126                     |       |
| 2011       |       | 28                      |       |
| Thereafter |       | 302                     |       |
|       |       | $                       | 1,622      |   |

 

**(8)****                                 Interest Rate Swaps**

 

The Company hasperiodically entered into interest rate swap agreements to minimize the effectof fluctuations in interest rates. The Company is required to pay thecounterparties the difference between the contract’s fixed rate and the actualrate if the actual rate is lower than the fixed rate and conversely, thecounterparties are required to pay the Company if the actual rate is higherthan the fixed rate in the contract. The Company did not designate the interestrate swap agreements as cash flow hedges under SFAS 133; therefore, thechanges in fair value of these instruments, which are non-cash gains or losses,are recorded in current earnings.

 

The following summarizesthe Company’s interest rate swaps outstanding:

 
| ** **         | ** ** | **September 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|--------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **         | ** ** | **(in thousands)**      | ** ** |
|               |       |                         |       |                        |       |
| Total  liabilities |       | $                            | 8,550      |                        | $          | 423 |   |
| Less total  assets |       | (5,127                       | )          | (44                         | )          |
|               |       | $                            | 3,423      |                        | $          | 379 |   |

 

Unrealized gains (losses)due to the change in the fair value of approximately $(3.8) million and $(3.7)million for the three and nine months ended September 30, 2007,respectively, and $(0.6) million and $0.1 million for the three and nine monthsended September 30, 2006, respectively, are recorded in gain (loss) oninterest rate swaps in the condensed consolidated statements of operations.

 

The following tablepresents the outstanding notional amounts and maximum number of monthsoutstanding of interest rate swaps:

 
| ** **                            | ** ** | **September 30,  2007**                     | ** ** | **December 31,  2006** | ** ** |
|---------------------------------------|------------|--------------------------------------------------|------------|-----------------------------|------------|
| ** **                            | ** ** | **(in thousands, except months)** | ** ** |
|                                  |       |                                             |       |                        |       |
| Notional amount                       |       | $                                                | 1,035,000  |                        | $          | 50,000 |   |
| Maximum number  of months outstanding |       | 39                                               |       | 12                          |       |
|                                       |            |                                                  |            |                             |            |  |  |

 

16

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The following tablepresents the settlement terms of the interest rate swaps:

 
| ** **                                            | ** ** | **Notional  Amount**    | ** ** | **Fixed  Rate** | ** ** |
|-------------------------------------------------------|------------|-------------------------|------------|-----------------|------------|
| ** **                                            | ** ** | **(in thousands)** | ** ** | ** **      | ** ** |
|                                                  |       |                    |       |            |       |
| Settles monthly,  October 2007 – January 2008    |       | $                       | 985,000    |            | 4.79       | % |
| Settles monthly,  January 2008 – January 2009    |       | $                       | 985,000    |            | 4.25       | % |
| Settles monthly,  January 2009 – January 2011    |       | $                       | 985,000    |            | 5.10       | % |
| Settles  quarterly, October 2007 – December 2007 |       | $                       | 50,000     |            | 5.30       | % |
| Settles  quarterly, January 2008 – December 2008 |       | $                       | 50,000     |            | 5.79       | % |

 

**(9)****                                 Business and CreditConcentrations**

 

***Cash***

*** ***

The Company maintains its cash in bank deposit accounts, which, at times,may exceed federally insured amounts. The Company has not experienced anylosses in such accounts. The Company believes it is not exposed to anysignificant credit risk on its cash.

 

***Revenue and Trade Receivables***

*** ***

The Company has a concentration of customers who are engaged in oil andgas purchasing, transportation and/or refining within the United States. Thisconcentration of customers may impact the Company’s overall exposure to creditrisk, either positively or negatively, in that the customers may be similarlyaffected by changes in economic or other conditions. The Company’s customersconsist primarily of major oil and gas purchasers and the Company generallydoes not require collateral.

 

A majority of the Company’s largest customers are oil and gas refiners,suppliers and operators. For the three and nine months ended September 30,2007, the Company’s three largest customers represented approximately 24%, 18%and 18%, and 21%, 18% and 26%, respectively, of the Company’s sales. For thethree and nine months ended September 30, 2006, the Company’s two largestcustomers represented approximately 48% and 26%, and 60% and 10%, respectively,of the Company’s sales.

 

At September 30, 2007, two customers’ trade accounts receivable fromoil, gas and NGL sales accounted for more than 10% of the Company’s total tradeaccounts receivable. At September 30, 2007, trade accounts receivable fromthese customers represented approximately 31% and 11% of the Company’s receivables.At December 31, 2006, three customers’ trade accounts receivable from oiland gas sales accounted for more than 10% of the Company’s total trade accountsreceivable. As of December 31, 2006, trade accounts receivable from thesecustomers represented approximately 41%, 22% and 16% of the Company’sreceivables.

 

**(10)****                          Commitments and Contingencies**

 

The Company would have increased exposure to oil, gas and NGL pricefluctuations on underlying sale contracts should the counterparties to theCompany’s derivative instruments or the counterparties to the Company’s oil,gas and NGL marketing contracts not perform. Such non-performance is notanticipated. There were no counterparty default losses during the three or ninemonths ended September 30, 2007 or 2006.

 

In June 2007, the Company entered into an agreement and paid $0.4 millionto cancel future lease obligations totaling $1.1 million related to an officefacility in Pennsylvania.

 

17

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From time to time the Company is a party to various legal proceedings oris subject to industry rulings that could bring rise to claims in the ordinarycourse of business. The Company is not currently a party to any litigation orpending claims that it believes would have a materially adverse effect on theCompany’s business, financial condition, results of operations or liquidity.

 

**(11)****                          Derivatives**

 

The Company sells oil,gas and NGL in the normal course of its business and utilizes derivativeinstruments to minimize the variability in forecasted cash flows due to pricemovements in oil, gas and NGL. The Company enters into derivative instrumentssuch as swap contracts and put options to hedge a portion of its forecastedoil, gas and NGL sales. Oil derivatives are used to hedge oil and NGL sales.

 

Settled derivatives ongas production for the three and nine months ended September 30, 2007,included a volume of 5,762 MMMBtu and 15,131 MMMBtu at an average contractprice of $8.51 and $8.46, respectively. Settled derivatives on oil and NGLproduction for the three and nine months ended September 30, 2007 includeda volume of 500 MBbls and 1,392 MBbls at an average contract price of $68.71and $69.00, respectively. The gas derivatives are settled based upon theclosing NYMEX future price of gas or on the published PEPL spot price of gas onthe settlement date, which occurs on the third day preceding the productionmonth. The oil transactions are settled based upon the average month’s dailyNYMEX price of light oil and settlement occurs on the final day of theproduction month.

 

The following tablessummarize open positions as of September 30, 2007 and represent, as ofsuch date, derivatives in place through December 31, 2012, on annualproduction volumes:

 
| ** **               | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** | **Year  2012** | ** ** |
|--------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas  Positions**       |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price  Swaps:      | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume  (MMMBtu)  |       | 9,689          |       | 49,410         |       | 49,271         |       | 42,086         |       | 38,741         |       | 34,066         |       |
| Average Price  ($/MMBtu) |       | $              | 7.84       |           | $          | 7.79           |       | $              | 7.65       |           | $          | 7.48           |       | $ | 7.43 |   | $ | 7.50 |   |
| Puts:                    |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)  |       | —         |       | 10,907         |       | 12,294         |       | 17,594         |       | 20,219         |       | 5,934          |       |
| Average Price  ($/MMBtu) |       | $              | —     |           | $          | 7.99           |       | $              | 7.65       |           | $          | 7.71           |       | $ | 7.73 |   | $ | 7.85 |   |
| Total:                   |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)  |       | 9,689          |       | 60,317         |       | 61,565         |       | 59,680         |       | 58,960         |       | 40,000         |       |
| Average Price  ($/MMBtu) |       | $              | 7.84       |           | $          | 7.82           |       | $              | 7.65       |           | $          | 7.55           |       | $ | 7.53 |   | $ | 7.55 |   |

 
| ** **             | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** | **Year  2012** | ** ** |
|------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Oil  Positions**     |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price  Swaps:    | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume  (MBbls) |       | 308            |       | 1,542          |       | 1,587          |       | 1,300          |       | 1,223          |       | 800            |       |
| Average Price  ($/Bbl) |       | $              | 74.15      |           | $          | 73.00          |       | $              | 72.89      |           | $          | 73.87          |       | $ | 68.23 |   | $ | 73.50 |   |
| Puts:                  |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls) |       | 349            |       | 1,368          |       | 1,343          |       | 1,750          |       | 1,852          |       | —         |       |
| Average Price  ($/Bbl) |       | $              | 66.17      |           | $          | 66.23          |       | $              | 66.06      |           | $          | 66.44          |       | $ | 65.57 |   | $ | — |   |
| Total:                 |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls) |       | 657            |       | 2,910          |       | 2,930          |       | 3,050          |       | 3,075          |       | 800            |       |
| Average Price  ($/Bbl) |       | $              | 69.92      |           | $          | 69.82          |       | $              | 69.76      |           | $          | 69.61          |       | $ | 66.63 |   | $ | 73.50 |   |

 

18

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Included in the table above are 39,016 of MMMBtu of gas that settle on thepublished PEPL spot price of gas, rather than NYMEX. The oil and gasderivatives are not designated as cash flow hedges under SFAS 133, and,accordingly, the changes in fair value are recorded in current period earnings.

 

The following table presents the outstanding notional amounts and maximumnumber of months outstanding of oil and gas derivatives:

 
| ** **                                           | ** ** | **September 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                           | ** ** | ** **                   | ** ** | ** **                  | ** ** |
| Outstanding  notional amounts of gas hedges (MMMBtu) |       | 290,211                      |       | 31,503                      |       |
| Maximum number  of months gas hedges outstanding     |       | 63                           |       | 35                          |       |
| Outstanding  notional amounts of oil hedges (MBbls)  |       | 13,422                       |       | 8,700                       |       |
| Maximum number  of months oil hedges outstanding     |       | 64                           |       | 60                          |       |

 

By using derivative instruments to hedge exposures to changes in commodityprices, the Company exposes itself to credit risk and market risk. Credit riskis the failure of the counterparty to perform under the terms of the derivativecontract. When the fair value of a derivative contract is positive, thecounterparty owes the Company, which creates credit risk. The Company minimizesthe credit risk in derivative instruments by entering into transactions withcredit-worthy counterparties.

 

**(12)****                          Earnings Per Unit**

 

Basic earnings per unit is computed by dividing net earnings attributableto unitholders by the weighted average number of units outstanding during eachperiod. Diluted earnings per unit is computed by adjusting the average numberof units outstanding for the dilutive effect, if any, of unit equivalents. TheCompany uses the treasury stock method to determine the dilutive effect inaccordance with SFAS No. 128, “*Earnings Per Share*”(“SFAS 128”). At September 30, 2007, the Company had two classes ofunits outstanding: (i) units representing limited liability company interests (“units”)listed on The NASDAQ Global Select Market under the symbol “LINE” and (ii)Class D units. See Note 3 for details regarding the Class Dunits.

 

In accordance with SFAS 128, dual presentation of basic and dilutedearnings per unit has been presented in the condensed consolidated statementsof operations for each class of units issued and outstanding atSeptember 30, 2007, units and Class D units. Net income per unit isallocated to the units and the Class D units on an equal basis. Since theClass D units were converted to units on November 1, 2007, they shareequally in the November 2007 distributions and all future distributions. TheCompany made no distributions to Class D unitholders during the period theClass D units were outstanding.

 

19

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The following reconciliation presents the impact on the unit amounts ofpotential unit equivalents and the earnings per unit amounts:

 
| ** **                                                      | ** ** | **Three Months Ended  September 30,**                 | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-----------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                      | ** ** | **2007**                                                             | ** ** | **2006**                                            | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                      | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| ** **                                                      | ** ** | ** **                                                           | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income  (loss)                                              |       | $                                                                    | (76,222    | )                                                   | $          | 53,057 |   | $ | (161,195 | ) | $ | 85,273 |   |
|                                                            |       |                                                                 |       |                                                |       |   |   |   |   |
| **Weighted  average units outstanding:**                        |       |                                                                 |       |                                                |       |   |   |   |   |
| Basic units  outstanding                                        |       | 69,207                                                               |       | 27,584                                              |       | 58,072 |   | 27,118 |   |
| Dilutive effect  of unit equivalents and Class D units (1) |       | —                                                               |       | 460                                                 |       | — |   | 223 |   |
| Diluted units  outstanding                                      |       | 69,207                                                               |       | 28,044                                              |       | 58,072 |   | 27,341 |   |
|                                                            |       |                                                                 |       |                                                |       |   |   |   |   |
| **Weighted  average Class D units outstanding:**           |       |                                                                 |       |                                                |       |   |   |   |   |
| Basic Class D  units outstanding                                |       | 11,792                                                               |       | —                                              |       | 3,974 |   | — |   |
| Dilutive effect  of unit equivalents                            |       | —                                                               |       | —                                              |       | — |   | — |   |
| Diluted Class D  units outstanding                              |       | 11,792                                                               |       | —                                              |       | 3,974 |   | — |   |
|                                                            |       |                                                                 |       |                                                |       |   |   |   |   |
| **Net  income (loss) per unit:**                                |       |                                                                 |       |                                                |       |   |   |   |   |
| Units – basic                                              |       | $                                                                    | (0.94      | )                                                   | $          | 1.92 |   | $ | (2.60 | ) | $ | 3.14 |   |
| Units – diluted                                            |       | $                                                                    | (0.94      | )                                                   | $          | 1.89 |   | $ | (2.60 | ) | $ | 3.12 |   |
| Class D – basic                                            |       | $                                                                    | (0.94      | )                                                   | $          | — |   | $ | (2.60 | ) | $ | — |   |
| Class D –  diluted                                         |       | $                                                                    | (0.94      | )                                                   | $          | — |   | $ | (2.60 | ) | $ | — |   |

 

----

(1)         Excludes the effect ofaverage anti-dilutive common stock equivalents related to unit options andwarrants, and unvested restricted units of 547,197 and 441,154 for the threeand nine months ended September 30, 2007, respectively. In addition,excludes the effect of average anti-dilutive Class D units for the threeand nine months ended September 30, 2007. Excludes the effect of averageanti-dilutive common stock equivalents related to unit options and unvestedrestricted units of 16,055 and 61,313 for the three and nine months endedSeptember 30, 2006, respectively. All equivalent units are anti-dilutivefor the three and nine months ended September 30, 2007 as the Companyreported a net loss from operations.

 

**(13)****                          Unit-Based Compensation**

 

***Employee Grants***

 

During the nine months ended September 30, 2007, the Company grantedan aggregate 400,500 restricted units to employees as part of its annual reviewof employee compensation and 152,000 restricted units to new employees of theCompany with an aggregate fair value of approximately $18.2 million. During thenine months ended September 30, 2007, the Company granted 123,000 unitoptions to new employees of the Company with a fair value of approximately $0.8million. The majority of these restricted units and options vest ratably overthree years. In addition, during the nine months ended September 30, 2007,the Company granted 12,000 phantom units to independent members of its Board ofDirectors with a fair value of approximately $0.4 million. The phantomunits vest over one year.

 

20

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For the three and nine months ended September 30, 2007, the Companyrecorded unit-based compensation expense of approximately $3.2 million and $9.5million, respectively, as a charge against income before income taxes and it isincluded in general and administrative expenses on the condensed consolidatedstatements of operations. For the three and nine months endedSeptember 30, 2006, the Company recorded unit-based compensation expenseof approximately $4.2 million and $14.1 million, respectively.

 

***Non-Employee Grants***

 

In February 2007, the Company granted an aggregate 150,000 unit warrantsto certain individuals in connection with a transition services agreemententered into with the Panhandle I acquisition (see Note 2). The unitwarrants have an exercise price of $25.50 per unit warrant, may be exercised inwhole or in-part on or after December 13, 2007, and expire ten years fromissuance. In accordance with SFAS 123R, the Company computed the fair value ofthe unit warrants using the Black-Scholes model. At September 30, 2007,the aggregate fair value of the unit warrants was approximately $1.4 millionand the expense was recognized over the five-month term of the agreementthrough June 30, 2007. For the nine months ended September 30, 2007,the Company recorded general and administrative expenses of approximately $1.4million as a charge against income before income taxes.

 

**(14)****                          Income Taxes**

 

The Company is a limited liability company treated as apartnership for federal and state income tax purposes with all income taxliabilities and/or benefits of the Company passed through to the Company’sunitholders. As such, no recognition of federal or state income taxes for theCompany or its subsidiaries that are organized as limited liability companieshave been provided for in the accompanying condensed consolidated financialstatements, except as described below.

 

Certain of the Company’s subsidiaries are Subchapter C-corporationssubject to corporate income taxes, which are accounted for under the provisionsof SFAS No. 109 *“Accounting for IncomeTaxes”* (“SFAS 109”), which uses the asset and liability method.Deferred tax assets and liabilities are recognized for the future taxconsequences attributable to differences between the financial statementcarrying amounts of existing assets and liabilities and their respective taxbasis and operating loss and tax credit carryforwards. Deferred tax assets andliabilities are measured using enacted tax rates expected to apply to taxableincome in the years in which those temporary differences are expected to berecovered or settled. The effect on deferred tax assets and liabilities of achange in tax rates is recognized in income in the period that includes theenactment date. At September 30, 2007, deferred tax liabilities ofapproximately $1.3 million are recorded on the condensed consolidated balancesheets and deferred tax assets of $5.5 million, net of a valuation allowance of$4.2 million, are also recorded. At December 31, 2006, deferred taxliabilities of approximately $0.7 million are recorded on the condensedconsolidated balance sheets and deferred tax assets of $6.3 million, net of avaluation allowance of $2.3 million, are also recorded.

 

The Company adopted Financial Interpretation No. 48, *“Accounting for Uncertainty in Income Taxes – an interpretation of FASBStatement No. 109”* (“FIN 48”) on January 1, 2007. FIN 48requires that the Company recognize only the impact of income tax positionsthat, based on their merits, are more likely than not to be sustained uponaudit by a taxing authority. It also requires expanded financial statementdisclosure of such positions.

 

In evaluating its current tax positions in order to identifyany material uncertain tax positions, the Company developed a policy inidentifying uncertain tax positions that considers support for each taxposition, industry standards, tax return disclosures and schedules and thesignificance of each position. As of September 30, 2007, the Company hadno material uncertain tax positions.

 

21

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**(15)****         RelatedParty Transactions**

 

In September 2007, Quantum Energy Partners (“Quantum”) sold 4,620,000 ofLinn units previously held. Subsequent to the sale, Quantum is no longerconsidered a related party to the Company as it owns less than 10% of totaloutstanding Linn units.

 

During the three and nine months ended September 30, 2006, theCompany made payments of approximately $0.2 million and $0.4 million,respectively, to a company owned by one of its senior executives. The paymentsreflect reimbursement for maintenance and hourly usage fees for business use ofan aircraft that was partially owned by the senior executive. These costs areincluded in general and administrative expenses on the condensed consolidatedstatements of operations. The fees and expenses associated with thereimbursements were consummated on terms equivalent to those that prevail inarm’s-length transactions. In the third quarter of 2006, the Company purchasedan ownership interest in an airplane for corporate travel from a third party;therefore, these reimbursements ended. Simultaneous with this transaction, thesenior executive was able to fully liquidate the investment in the aircraftowned by his company.

 

At September 30, 2007, on an aggregate basis, agroup of certain direct or indirect wholly-owned subsidiaries of LehmanBrothers Holding, Inc. (“Lehman”) owned over 10% of the Company’s outstanding units,acquired during 2006 and 2007 in the Company’s private placements of units (seeNote 3). As such, Lehman is considered a related party under the provisions ofSFAS No. 57 *“Related Party Disclosures.”*Lehmansubsidiaries provide certain services to the Company, including participationin the Company’s Credit Facility (see Note 6) and sale of commodityderivative instruments (see Note 11), which were all consummated on termsequivalent to those that prevail in arm’s-length transactions.

 

In conjunction with its private placement of units,the Company received proceeds from Lehman of approximately $260.0 million and$378.7 million during the three and nine months ended September 30, 2007,respectively. The Company received such proceeds from Lehman of approximately$46.0 million during the three and nine months ended September 30, 2006.

 

During the three and nine months endedSeptember 30, 2007, the Company paid Lehman underwriting fees ofapproximately $10.0 million and $13.5 million, respectively. In addition,during the three and nine months ended September 30, 2007, the Companypaid distributions on units to Lehman of approximately $3.6 million and $7.5million, respectively. During the three and nine months endedSeptember 30, 2007, the Company paid Lehman approximately $204.1 millionfor oil and gas put and swap contracts. No similar payments were made duringthe comparable periods of 2006.

 

During the three and nine months endedSeptember 30, 2007, the Company paid Lehman, through the administrator ofits Credit Facility, interest on borrowings under its Credit Facility ofapproximately $0.3 million and $0.6 million, respectively, and financing feesof approximately $0.1 million. During the three and nine months endedSeptember 30, 2006, the Company paid Lehman interest on borrowings underits Credit Facility of approximately $0.3 million and $0.4 million,respectively, and financing fees of approximately $30,000 and $42,000,respectively.

 

22

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The following table sets forth the amounts due to orfrom Lehman as of the respective balance sheet dates included in theaccompanying condensed consolidated financial statements:

 
| ** **                                               | ** ** | **September 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|----------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                               | ** ** | **(in thousands)**      | ** ** |
| **Assets:**                                              |       |                         |       |                        |       |
| Current portion  of oil and gas derivative assets        |       | $                            | 45,597     |                        | $          | 2,218 |   |
| Long-term  portion of oil and gas derivative assets      |       | $                            | 210,200    |                        | $          | 3,538 |   |
| **Liabilities:**                                         |       |                         |       |                        |       |
| Current portion  of oil and gas derivative liabilities   |       | $                            | 24,809     |                        | $          | — |   |
| Accrued interest  payable – Credit Facility         |       | $                            | 5,267      |                        | $          | 79 |   |
| Credit Facility                                          |       | $                            | 36,400     |                        | $          | 15,966 |   |
| Long-term  portion of oil and gas derivative liabilities |       | $                            | 101,405    |                        | $          | — |   |

 

23

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**Item 2.    Management’s Discussion and Analysis of Financial Condition andResults of Operations**

 

**Executive Summary**

Linn is anindependent oil and gas company focused on providing stability and growth indistributions to its unitholders through continued successful drilling, acquisitions, increasing production ofexisting wells and pursuing operational and administrativeefficiencies.  The Company’s oil, gas and NGL properties are currently located in threecore areas:

•                  Mid-Continent, which includes fields in Kansas,Oklahoma and Texas;

•                  Appalachian Basin, which includes West Virginia,Pennsylvania and Virginia; and

•                  Western, which includes the BreaOlinda Field of the Los Angeles Basin in California.

The following is asummary of the key elements of the Company’s 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; and

•                  mitigate commodity price and interest rate riskthrough hedging.

Certain keyelements included in our business strategy are further explained below.

***Acquire Properties and BuildRegional Scale***

The Company’sacquisition program targets oil and gas properties that offer high-quality,long-life production with predictable decline curves, as well as developmentdrilling opportunities.  The following table provides a summary ofsignificant acquisitions of working or royalty interests in oil and gasproperties 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     |       | 7                      |       | 4,929            |       | West Virginia and Mid-Continent                    |       | 2,668.9                        |
|     |       | 21                     |       | 8,273            |       |                                               |       | $                              | 3,323.0 |

 

Frominception through the date of this report, the Company has completed 21 significantacquisitions of working or royalty interests in oil and gas properties andrelated gathering and pipeline assets.  Totalproved reserves from working interests acquired were approximately 1.6 Tcfe, oran acquisition cost of approximately $2.07 per Mcfe.  On August 31, 2007, the Company completed itslargest acquisition to date, the Mid-Continent acquisition, acquiring oil andgas properties and other assets for approximately $2.0 billion and successfullyrecruited the 200 employees involved in operating the related acquiredassets.  See Note 2 in Notes to CondensedConsolidated Financial Statements for additional details about Companyacquisitions during 2007.

Acquisitions arefinanced with a combination of proceeds from private placements of units, bankborrowings and cash flow from operations. The Company is focused on evaluating and developing its asset base,increasing acreage positions and evaluating potential acquisitions.  Because of its rapid growth throughacquisitions and development of properties, historical results of operationsand period-to-period comparisons of these results and certain financial datamay not be meaningful or indicative of future results.

 

24

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***Growth Through DevelopmentActivities***

The Company seeks to be the operator of its properties so that it cancontrol the drilling programs that not only replace production, but add valuethrough the growth of reserves and future operational synergies.  Many of the Company’s wells are completed inmultiple producing zones with commingled production and long economiclives.  Recent acquisitions provide aninventory of lower-risk development opportunities, which the Company expectswill create post-acquisition value from our assets.

Drilling activity is concentrated on lower risk, developmentproperties.  The number, types, andlocation of wells the Company drills varies depending on its capital budget,the cost of each well, anticipated production and the estimated recoverablereserves attributable to each well.  Historically, until 2007, most of theCompany’s drilling has been in the Appalachian Basin.  With the February 2007 Panhandle I, June 2007Panhandle II and August 2007 Mid-Continent acquisitions, the drilling programhas been expanded to include the Texas Panhandle and the Oklahoma AnadarkoBasin as well as other areas in the Mid-Continent.

***Hedging Program***

As noted above, the Company’s revenues are highlysensitive to changes in oil, gas and NGL prices and levels of production.  The Company typically seeks to hedge asignificant portion of its anticipated future production volumes to reducecommodity price volatility risk. Managing this volatility, which is expected to continue in the future,provides a longer-term stability of cash flows. Currently, the Company uses fixedprice swaps and puts to reduce its exposure to the volatility in oil, gas andNGL prices.  As of the date ofthis report, the Company has hedged a significant portion of its expectedproduction through 2012 using derivatives, which allows it to mitigate, but noteliminate, commodity price risk.  See Note 11 in Notes to CondensedConsolidated Financial Statements for details about derivatives in placethrough December 31, 2012.

***Risks***

Revenues, cashflow from operations and future growth depend substantially on factors beyondthe Company’s control, such as economic, political and regulatory developmentsand competition from other producers. Oil, gas and NGL prices historically have been volatile and may fluctuatewidely in the future.  Sustained periodsof low prices for oil, gas or NGL could materially and adversely affect theCompany’s financial position, results of operations, the quantities ofproductive reserves that can be economically produced and access tocapital.  See “Cautionary Statement”below in this Item 2. for additional information about risks related toCompany.

 

25

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**Results of Operations - Three Months Ended September 30,2007 Compared to Three Months Ended September 30, 2006**

** **
| ** **                                   | ** ** | **Three Months Ended  September 30,** | ** ** | ** ** | ** ** |
|----------------------------------------------|------------|------------------------------------------------------|------------|------------|------------|
| ** **                                   | ** ** | **2007**                                             | ** ** | **2006**   | ** ** | **Variance** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                              | ** ** |
| **Revenues:**                                |       |                                                 |       |       |       |   |   |
| Gas sales                                    |       | $                                                    | 37,110     |       | $          | 15,553 |   | $ | 21,557 |   |
| Oil sales                                    |       | 24,046                                               |       | 7,953      |       | 16,093 |   |
| Natural gas  liquid sales                    |       | 13,906                                               |       | —     |       | 13,906 |   |
| Total oil, gas  and natural gas liquid sales |       | 75,062                                               |       | 23,506     |       | 51,556 |   |
| Gain (loss) on  oil and gas derivatives      |       | (65,440                                              | )          | 57,396     |       | (122,836 | ) |
| Natural gas  marketing revenues              |       | 8,434                                                |       | 1,090      |       | 7,344 |   |
| Other revenues                               |       | 423                                                  |       | 265        |       | 158 |   |
| Total revenues                               |       | $                                                    | 18,479     |       | $          | 82,257 |   | $ | (63,778 | ) |
| **Expenses:**                                |       |                                                 |       |       |       |   |   |
| Operating  expenses                          |       | $                                                    | 27,465     |       | $          | 4,845 |   | $ | 22,620 |   |
| Natural gas  marketing expenses              |       | 7,207                                                |       | 954        |       | 6,253 |   |
| General and  administrative expenses         |       | 13,202                                               |       | 6,536      |       | 6,666 |   |
| Depreciation,  depletion and amortization    |       | 24,320                                               |       | 5,654      |       | 18,666 |   |
| Total expenses                               |       | $                                                    | 72,194     |       | $          | 17,989 |   | $ | 54,205 |   |
| **Other  income and (expenses)**             |       | $                                                    | (22,186    | )          | $          | (11,211 | ) | $ | (10,975 | ) |

 

26

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| ** **                                      | ** ** | **Three Months Ended  September 30,** | ** ** | **Increase** | ** ** |
|-------------------------------------------------|------------|------------------------------------------------------|------------|--------------|------------|
| ** **                                      | ** ** | **2007**                                             | ** ** | **2006**     | ** ** | **(Decrease)** | ** ** |
| **Production:**                                 |       |                                                 |       |         |       |   |   |
| Gas production  (MMcf)                          |       | 6,770                                                |       | 2,265        |       | 198.9 | % |
| Oil production  (MBbls)                         |       | 345                                                  |       | 153          |       | 125.5 | % |
| Natural gas  liquid production (MBbls)          |       | 274                                                  |       | —       |       | — |   |
| Total production  (MMcfe)                       |       | 10,488                                               |       | 3,181        |       | 229.7 | % |
| Average daily  production (MMcfe/d)             |       | 114.0                                                |       | 34.6         |       | 229.5 | % |
|                                            |       |                                                 |       |         |       |   |   |
| **Weighted  average prices (hedged):****(1)**   |       |                                                 |       |         |       |   |   |
| Gas (Mcf)                                       |       | $                                                    | 7.57       |         | $          | 10.27 |   | (26.3 | )% |
| Oil (Bbl) (2)                                   |       | $                                                    | 70.03      |         | $          | 55.24 |   | 26.8 | % |
| Natural gas  liquid (Bbl)                       |       | $                                                    | 50.75      |         | $          | — |   | — |   |
| Total (Mcfe)                                    |       | $                                                    | 8.51       |         | $          | 9.97 |   | (14.6 | )% |
|                                            |       |                                                 |       |         |       |   |   |
| **Weighted average prices  (unhedged):****(3)** |       |                                                 |       |         |       |   |   |
| Gas (Mcf)                                       |       | $                                                    | 5.48       |         | $          | 6.87 |   | (20.2 | )% |
| Oil (Bbl) (2)                                   |       | $                                                    | 69.70      |         | $          | 51.99 |   | 34.1 | % |
| Natural gas  liquid (Bbl)                       |       | $                                                    | 50.75      |         | $          | — |   | — |   |
| Total (Mcfe)                                    |       | $                                                    | 7.16       |         | $          | 7.39 |   | (3.1 | )% |
|                                            |       |                                                 |       |         |       |   |   |
| **Average unit costs per Mcfe of production:**  |       |                                                 |       |         |       |   |   |
| Operating  expenses                             |       | $                                                    | 2.62       |         | $          | 1.52 |   | 72.4 | % |
| General and  administrative expenses (4)        |       | $                                                    | 1.26       |         | $          | 2.05 |   | (38.5 | )% |
| Depreciation,  depletion and amortization       |       | $                                                    | 2.32       |         | $          | 1.78 |   | 30.3 | % |

 

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(1)          Includes the effect of realized gains of $14.2 millionand $8.2 million on derivatives for the three months ended September 30,2007 and 2006, respectively.

(2)          Oil production in California issold pursuant to a long-term contract at 79% of NYMEX, and with gravityincrease due to NGL being mixed into the oil stream, prices realized averageapproximately 82% of NYMEX.

(3)          Does not include the effect ofrealized gains on derivatives.

(4)          The measure for the three monthsended September 30, 2007 and 2006 includes approximately $3.2 million and$4.2 million, respectively, of unit-based compensation expense.  Excluding these amounts, general andadministrative expenses for the three months ended September 30, 2007 and2006 were $0.95 per Mcfe and $0.74 per Mcfe, respectively.  This is a non-GAAP measure used by Companymanagement to analyze its performance.

 

27

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***Revenues***

** **

Gas,oil and NGL sales increased 220%, to approximately $75.1million for the three months ended September 30, 2007, from $23.5 millionfor the three months ended September 30, 2006.

 

The increase in revenue from gas, oil and NGLsales was primarily attributable to increased production.  Total production increased to 10,488 MMcfeduring the three months ended September 30, 2007, from 3,181 MMcfe duringthe three months ended September 30, 2006. The increase in production was due primarily to production from oil andgas properties acquired during 2007 and 2006 and by the drilling of newwells.  The Company drilled 47 wellsduring the three months ended September 30, 2007, compared to 42 wellsduring the three months ended September 30, 2006.

 

Gas production increased to 6,770 MMcf during thethree months ended September 30, 2007, from 2,265 MMcf during the threemonths ended September 30, 2006, with the 2007 acquisitions in theMid-Continent core area contributing approximately 4,642 MMcf to current periodgas production.  The increase in productionwas slightly offset by a reduction in the weighted average gas price, from$6.87 per Mcf during the three months ended September 30, 2006, to $5.48per Mcf during the comparable period of 2007, which caused gas revenues todecrease approximately $3.1 million.

 

Oil production increased to 345 MBbls during thethree months ended September 30, 2007, from 153 MBbls during the duringthe three months ended September 30, 2006, due to the acquisitions in theWestern and Mid-Continent core areas. The acquisitions in the Mid-Continent also increased NGL production to274 MBbls during the three months ended September 30, 2007, from zeroduring the comparative period of the prior year.  The increase in the weighted average price ofoil for the period, from $51.99 per Bbl, to $69.70 per Bbl, also contributedslightly to the increase in oil revenues.

 

***HedgingActivities***

 

During the three months ended September 30,2007, the Company had commodity pricing derivative contracts for approximately69% of its third quarter gas production and 81% of its third quarter oil andNGL production, which resulted in realized gains of $14.2 million (revenuesgreater than would have been achieved at unhedged prices).  During the three months endedSeptember 30, 2006, the Company entered into commodity pricing derivativecontracts for approximately 90% of its gas production and 26% of its oilproduction, which resulted in realized gains of $8.2 million.  Unrealized losses on derivatives in theamount of $80.0 million for the three months ended September 30, 2007, andunrealized gains of $49.2 million for the three months ended September 30,2006, were also recorded.  Unrealizedgains and losses result from changes in market valuations of derivatives asfuture commodity price expectations change compared to the contract price on thederivative.  During the quarter, short-term oil and gas pricesincreased, which reduced the market value of the derivatives.  Such market value adjustment, if realized inthe future, would be offset by higher actual prices for production.  Since the Company has hedged a significantportion of its oil and gas production at fixed prices, it may not realize thebenefit of future increases in commodity prices.  See Note 11 in Notes to CondensedConsolidated Financial Statements for details regarding derivatives in placethrough December 31, 2012.

 

***Expenses***

 

Operatingexpenses include lease operating expenses, labor, field office expenses,vehicle expenses, supervision, transportation, minor maintenance, tools andsupplies, and severance and ad valorem taxes.  Severance taxes are a function of volumes andrevenues generated from production.  Advalorem taxes vary by state/county and are based on the value of reserves.  The Company assesses its operating expensesby monitoring the expenses in relation to the amount of production and thenumber of wells operated.  Operatingexpenses increased to $27.5 million for the three months endedSeptember 30, 2007, from $4.8 million for the three months endedSeptember 30, 2006, due primarily to expenses associated with the 2007acquisitions in the Mid-Continent core area, including expenses associated withthe addition of approximately 150 field and direct field supportemployees.  In addition, the number ofproducing wells, which increased by over 4,000 gross wells as a result of theacquisitions completed in 2007 and the drilling of 47 wells

 

28

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inthe three months ended September 30, 2007, and 519 wells from inceptionthrough September 30, 2007 also contributed to the increased operatingexpenses.

 

Inaddition, average operating expenses per equivalent unit of productionincreased to $2.62 for the three months ended September 30, 2007, comparedto $1.52 for the three months ended September 30, 2006, due to increasedmaterial and labor costs and the changing mix of production beginning in thethird quarter of 2006 to include oil and NGL, which have higher operating coststhan gas wells.  Operating expenses perMcfe for the three months ended September 30, 2007 also increased due toturnover of purchased inventory valued at acquisition cost instead of cost toproduce and increased ad valorem taxes due to higher property valueassessments.  Finally, the Company hasincurred costs in 2007 for workover and maintenance of its wells to enhancefuture production and/or offset decline.

 

General and administrative expenses include thecosts of employees and executive officers, related benefits, office leases,professional fees and other costs not directly associated with field operations.  General and administrative expenses increasedto approximately $13.2 million for the three months ended September 30,2007, from $6.5 million for the three months ended September 30, 2006.  The increase in general and administrative expenseswas primarily due to costs incurred to support the Company’s rapid growththrough acquisitions and position the Company for future growth.  In conjunction with expansion and developmentof the organization, to date during 2007, the Company has hired approximately150 employees (including approximately 100 corporate, administrative andsupport employees with the Mid-Continent acquisition) and as a result, salariesand benefits expense increased approximately $4.1 million over the comparablequarter of 2006.  Costs to perform thenecessary functions associated with being a growing public company were $3.2million during the third quarter of 2007, compared to $1.6 million during thethird quarter of 2006.  These costsinclude expenses for recruitment of key management team members, acquisitionrelated data conversion and integration, public partnership tax reporting,audit fees, legal fees, proxy and printing costs and other professional fees,including costs related to compliance with Section 404 of the Sarbanes-Oxley Actof 2002 (“Sarbanes-Oxley Act”).  TheCompany is currently in the process of implementing and testing procedures andcontrols in order to comply with the Sarbanes-Oxley Act at December 31,2007, and as such, expects these costs to continue throughout the remainder ofthe year.  In addition, acquisition coststhat are not eligible for capitalization, including internal and indirect costsfor completed acquisitions, as well as direct costs associated with acquisitionefforts that have not reached fruition, contributed to the increase.  The increase in general and administrativeexpenses was partially offset by lower employee unit-based compensationexpense, which decreased to $2.3 million(exclusive of amounts associated with certain of the new employees) during thethree months ended September 30, 2007, from $4.2 million during the comparative quarter of 2006.  Unit-based compensation expense incurredduring the three months ended September 30, 2006 was higher compared tothat incurred in the comparative period of 2007, primarily due to expenseassociated with unit awards granted in conjunction with the Company’s IPO inJanuary 2006.  General and administrativeexpenses are presented net of approximately $0.1million and $0.2 million during the threemonths ended September 30, 2007 and 2006, respectively, whichrepresent expense reimbursements from other working interest owners.

 

Depreciation, depletionand amortization increased to approximately$24.3 million for the three months ended September 30, 2007, from $5.7million for the three months ended September 30, 2006.  Of this increase, approximately $3.8 million was as a result of depletionrelated to the Texas acquisitions in 2007. The properties acquired in the Mid-Continent acquisition contributedapproximately $9.3 million to the increase.  Although total depreciation, depletion andamortization increased in the third quarter of 2007 due to higher totalproduction levels, the reserves in the acquired Texas, Oklahoma and Californiaproperties have lower depletion rates than the reserves in the AppalachianBasin.  In addition, the depletion ratefor oil and gas properties in the Appalachian Basin increased in the fourthquarter of 2006 due to a downward revision of estimated reserves from the prioryear, primarily attributable to decreases in gas prices.  During the threemonths ended September 30, 2007 and 2006, the Company capitalizedapproximately $3.0 million and $2.1 million, respectively, of costs forspecific activities related to drilling its wells, which include sitepreparation, drilling labor, meter installation, pipeline connection and sitereclamation.  Capitalized drilling costsincreased in the three months ended September 30, 2007 due to the Company’spurchase and placement of two drilling rigs into service during the thirdquarter of 2006.  Company personnel alsoperform activities using leased equipment, and did so prior to the purchase ofits own rigs.

 

29

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Other income and(expenses) increased to a net expense of $22.2million for the three months endedSeptember 30, 2007, compared to a net expense of $11.2 million for the three months ended September 30, 2006,primarily due to increased interest expense from increased debt levelsassociated with borrowings to fund the Mid-Continent acquisition anddrilling.  Cash payments for interestincreased to $9.7 million for the three months ended September 30, 2007,compared to $8.5 million for the three months ended September 30, 2006.  The Company’s interest rate swaps (seeNote 8 in Notes to Condensed Consolidated Financial Statements) were notdesignated as hedges under SFAS 133, even though they reduce exposure tochanges in interest rates.  Therefore, thechanges in fair values of these instruments were recorded as losses ofapproximately $3.8 million and $0.6million for the three months endedSeptember 30, 2007 and 2006, respectively.  These amounts are non-cash items.

 

Income tax was anexpense of approximately $0.3 million forthe three months ended September 30,2007.  There was no income tax impactrecorded for the three months endedSeptember 30, 2006.  The Company’s taxable subsidiaries generated netoperating losses for the year ended December 31, 2006.  Management has subsequently recovered expensesthrough an intercompany charge for services from Linn Operating, Inc. to LinnEnergy, LLC, which resulted in a corresponding tax expense in the three monthsended September 30, 2007.  Inaddition, the three months ended September 30, 2007 includes Texas margintax expense of $0.3 million.

 

30

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**Results of Operations - NineMonths Ended September 30, 2007 Compared to Nine Months EndedSeptember 30, 2006**

** **
| ** **                                   | ** ** | **Nine Months Ended** | ** ** | ** ** | ** ** |
|----------------------------------------------|------------|---------------------------------|------------|------------|------------|
| ** **                                   | ** ** | **September 30,**          | ** ** | ** ** | ** ** |
| ** **                                   | ** ** | **2007**                        | ** ** | **2006**   | ** ** | **Variance** | ** ** |
| ** **                                   | ** ** | **(in thousands)**         | ** ** |
| **Revenues:**                                |       |                            |       |       |       |   |   |
| Gas sales                                    |       | $                               | 85,932     |       | $          | 44,727 |   | $ | 41,205 |   |
| Oil sales                                    |       | 47,120                          |       | 8,683      |       | 38,437 |   |
| Natural gas  liquid sales                    |       | 30,431                          |       | —     |       | 30,431 |   |
| Total oil, gas  and natural gas liquid sales |       | 163,483                         |       | 53,410     |       | 110,073 |   |
| Gain (loss) on  oil and gas derivatives      |       | (143,588                        | )          | 94,537     |       | (238,125 | ) |
| Natural gas  marketing revenues              |       | 11,351                          |       | 3,654      |       | 7,697 |   |
| Other revenues                               |       | 3,652                           |       | 758        |       | 2,894 |   |
| Total revenues                               |       | $                               | 34,898     |       | $          | 152,359 |   | $ | (117,461 | ) |
| **Expenses:**                                |       |                            |       |       |       |   |   |
| Operating  expenses                          |       | $                               | 54,635     |       | $          | 10,772 |   | $ | 43,863 |   |
| Natural gas  marketing expenses              |       | 9,433                           |       | 3,126      |       | 6,307 |   |
| General and  administrative expenses         |       | 36,360                          |       | 22,934     |       | 13,426 |   |
| Depreciation,  depletion and amortization    |       | 49,109                          |       | 13,470     |       | 35,639 |   |
| Total expenses                               |       | $                               | 149,537    |       | $          | 50,302 |   | $ | 99,235 |   |
| **Other  income and (expenses)**             |       | $                               | (42,573    | )          | $          | (16,858 | ) | $ | (25,715 | ) |

 

31

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| ** **                                            | ** ** | **Nine Months Ended  September 30,** | ** ** | **Increase** | ** ** |
|-------------------------------------------------------|------------|-----------------------------------------------------|------------|--------------|------------|
| ** **                                            | ** ** | **2007**                                            | ** ** | **2006**     | ** ** | **(Decrease)** | ** ** |
| **Production:**                                       |       |                                                |       |         |       |   |   |
| Gas production  (MMcf)                                |       | 13,662                                              |       | 5,977        |       | 128.6 | % |
| Oil production  (MBbls)                               |       | 811                                                 |       | 166          |       | 388.6 | % |
| Natural gas  liquid production (MBbls)                |       | 604                                                 |       | —       |       | — |   |
| Total production  (MMcfe)                             |       | 22,157                                              |       | 6,973        |       | 217.8 | % |
| Average daily  production (MMcfe/d)                   |       | 81.2                                                |       | 25.5         |       | 218.4 | % |
|                                                  |       |                                                |       |         |       |   |   |
| **Weighted  average prices (hedged):****(1)**         |       |                                                |       |         |       |   |   |
| Gas (Mcf)                                             |       | $                                                   | 8.06       |         | $          | 10.30 |   | (21.8 | )% |
| Oil (Bbl) (2)                                         |       | $                                                   | 64.39      |         | $          | 55.31 |   | 16.4 | % |
| Natural gas  liquid (Bbl)                             |       | $                                                   | 52.42      |         | $          | — |   | — |   |
| Total (Mcfe)                                          |       | $                                                   | 8.75       |         | $          | 10.15 |   | (13.8 | )% |
|                                                  |       |                                                |       |         |       |   |   |
| **Weighted average prices  (unhedged):**** (3)** |       |                                                |       |         |       |   |   |
| Gas (Mcf)                                             |       | $                                                   | 6.29       |         | $          | 7.48 |   | (15.9 | )% |
| Oil (Bbl) (2)                                         |       | $                                                   | 58.10      |         | $          | 52.31 |   | 11.1 | % |
| Natural gas  liquid (Bbl)                             |       | $                                                   | 50.38      |         | $          | — |   | — |   |
| Total (Mcfe)                                          |       | $                                                   | 7.38       |         | $          | 7.66 |   | (3.7 | )% |
|                                                  |       |                                                |       |         |       |   |   |
| **Average unit costs per Mcfe of production:**        |       |                                                |       |         |       |   |   |
| Operating  expenses                                   |       | $                                                   | 2.47       |         | $          | 1.54 |   | 60.4 | % |
| General and  administrative expenses (4)              |       | $                                                   | 1.64       |         | $          | 3.29 |   | (50.2 | )% |
| Depreciation,  depletion and amortization             |       | $                                                   | 2.22       |         | $          | 1.93 |   | 15.0 | % |

 

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(1)          Includes the effect of realized gains of $30.5 millionand $17.4 million on derivatives for the nine months ended September 30,2007 and 2006, respectively.

(2)          Oil production in California issold pursuant to a long-term contract at 79% of NYMEX, and with gravityincrease due to NGL being mixed into the oil stream, prices realized averageapproximately 82% of NYMEX.

(3)          Does not include the effect ofrealized gains on derivatives.

(4)          The measure for the nine monthsended September 30, 2007 and 2006 includes approximately $10.9 million and$14.1 million, respectively, of unit-based compensation expense and unitwarrant expense.  The measure for thenine months ended September 30, 2006 includes approximately $2.0 millionof bonuses paid to certain executive officers in connection with the IPO.  Excluding these amounts, general andadministrative expenses for the nine months ended September 30, 2007 and2006 were $1.15 per Mcfe and $0.98 per Mcfe, respectively.  This is a non-GAAP measure used by Companymanagement to analyze its performance.

 

32

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***Revenues***

 

Gas,oil and NGL sales increased 206%, to approximately $163.5million for the nine months ended September 30, 2007, from $53.4 millionfor the nine months ended September 30, 2006.

 

Theincrease in revenue from gas, oil and NGL sales was primarily attributable toincreased production.  Total productionincreased to 22,157 MMcfe during the nine months ended September 30, 2007,from 6,973 MMcfe during the nine months ended September 30, 2006.  The increase in production was due primarilyto production from oil and gas properties acquired during 2007 and 2006 and bythe drilling of new wells.  The Companydrilled 160 wells during the nine months ended September 30, 2007,compared to 127 wells during the nine months ended September 30, 2006.

 

Gasproduction increased to 13,662 MMcf during the nine months endedSeptember 30, 2007, from 5,977 MMcf during the nine months endedSeptember 30, 2006, with the 2007 acquisitions in the Mid-Continent corearea contributing approximately 7,372 MMcf to current period gasproduction.  The increase in productionwas slightly offset by a reduction in the weighted average gas price, from$7.48 per Mcf during the nine months ended September 30, 2006, to $6.29per Mcf during the comparable period of 2007, which caused gas revenues todecrease approximately $7.1 million.

 

Oilproduction increased to 811 MBbls during the nine months endedSeptember 30, 2007, from 166 MBbls during the during the nine months endedSeptember 30, 2006, due to the acquisitions in the Western andMid-Continent core areas.  Theacquisitions in the Mid-Continent also increased NGL production to 604 MBblsduring the nine months ended September 30, 2007, from zero during thecomparative period of the prior year. The increase in the weighted average price of oil for the period, from$52.31 per Bbl, to $58.10 per Bbl, also contributed slightly to the increase inoil revenues.

 

***HedgingActivities***

 

During the nine months ended September 30,2007, the Company had commodity pricing derivative contracts for approximately97% of its nine month gas production and 97% of its nine month oil and NGLproduction, which resulted in realized gains of $30.5 million (revenues greaterthan would have been achieved at unhedged prices).  The calculation of the percentage hedged forthe nine months ended September 30, 2007 includes an adjustment to reflectPanhandle I production, which was hedged, but was notincluded in the Company’s reported production. It was instead recorded as a purchase price adjustment (see Note 2in Notes to Condensed Consolidated Financial Statements).  During the nine months endedSeptember 30, 2006, the Company entered into commodity pricing derivativecontracts for approximately 102% of its gas production and 24% of its oilproduction, which resulted in realized gains of $17.4 million.  Unrealized losses on derivatives in theamount of $174.1 million for the nine months ended September 30, 2007, andunrealized gains of $77.2 million for the nine months ended September 30,2006, were also recorded.  Unrealizedgains and losses result from changes in market valuations of derivatives asfuture commodity price expectations change compared to the contract price onthe derivative.  During the ninemonths ended September 30, 2007, short-term oil and gas prices increased,which reduced the market value of the derivatives.  Such market value adjustment, if realized inthe future, would be offset by higher actual prices for production.  Since the Company has hedged a significantportion of its oil and gas production at fixed prices, it may not realize thebenefit of future increases in commodity prices.  See Note 11 in Notes to CondensedConsolidated Financial Statements for details regarding derivatives in placethrough December 31, 2012.

 

***Expenses***

 

Operatingexpenses include lease operating expenses, labor, field office expenses,vehicle expenses, supervision, transportation, minor maintenance, tools andsupplies, and severance and ad valorem taxes. Severance taxes are a function of volumes and revenues generated fromproduction.  Ad valorem taxes vary bystate/county and are based on the value of reserves.  The Company assesses its operating expensesby monitoring the expenses in relation to the amount of production and thenumber of wells operated.  Operatingexpenses increased to $54.6 million for the nine months endedSeptember 30, 2007, from $10.8 million for the nine months endedSeptember 30, 2006, due to the increase in the number of producing wellsby over 4,000 gross wells as a result of the acquisitions completed in 2007 andthe drilling of 160 wells in the nine months ended September 30, 2007, and519 wells from inception through September 30, 2007.  Expenses associated with the 2007acquisitions in the Mid-Continent core area, including

 

33

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expensesassociated with the addition of approximately 150 field and direct fieldsupport employees during the nine months ended September 30, 2007, alsocontributed to the increase in operating expenses.

 

Inaddition, average operating expenses per equivalent unit of productionincreased to $2.47 for the nine months ended September 30, 2007, comparedto $1.54 for the nine months ended September 30, 2006, due to increasedmaterial and labor costs and the changing mix of production beginning in thethird quarter of 2006 to include oil and NGL, which have higher operating coststhan gas wells.  Operating expenses perMcfe for the nine months ended September 30, 2007 also increased due toturnover of purchased inventory valued at acquisition cost instead of cost toproduce and increased ad valorem taxes due to higher property valueassessments.  Finally, the Company hasincurred costs in 2007 for workover and maintenance of its wells to enhancefuture production and/or offset decline.

 

Generaland administrative expenses include the costs of employees and executiveofficers, related benefits, office leases, professional fees and other costsnot directly associated with field operations. General and administrative expenses increased to approximately $36.4million for the nine months ended September 30, 2007, from $22.9 millionfor the nine months ended September 30, 2006.  The increase in general and administrative expenseswas primarily due to costs incurred to support the Company’s rapid growththrough acquisitions and position the Company for future growth.  In conjunction with expansion and developmentof the organization, to date during 2007, the Company has hired approximately 150employees (including approximately 100 corporate, administrative and supportemployees with the Mid-Continent acquisition) and as a result, salaries andbenefits expense increased approximately $7.0 million as compared to the ninemonths ended September 30, 2006. The Company also incurred approximately $1.8 million in expenses forservices performed by third-parties pursuant to a transition services agreementassociated with the Panhandle I properties (see Note 2 in Notes toCondensed Consolidated Financial Statements). This services agreement terminated effective June 30, 2007.  Costs to perform the necessary functionsassociated with being a growing public company were $9.3 million during thenine months ended September 30, 2007, compared to $3.7 million during thenine months ended September 30, 2006. These costs include expenses for relocation of the Company headquartersfrom Pittsburgh, Pennsylvania to Houston, Texas, recruitment of key managementteam members, acquisition related data conversion and integration, publicpartnership tax reporting, audit fees, legal fees, proxy and printing costs andother professional fees, including costs related to compliance with theSarbanes-Oxley Act.  The Company is currentlyin the process of implementing and testing procedures and controls in order tocomply with the Sarbanes-Oxley Act at December 31, 2007, and as such,expects these costs to continue throughout the remainder of the year.  In addition, acquisition costs that are noteligible for capitalization, including internal and indirect costs forcompleted acquisitions, as well as direct costs associated with acquisitionefforts that have not reached fruition, contributed to the increase.  The increase in general and administrativeexpenses was partially offset by lower employee unit-based compensationexpense, which decreased to $7.3 million(exclusive of amounts associated with certain of the new employees) during thenine months ended September 30, 2007, from $14.1 million during the comparative period of 2006.  Unit-based compensation expense incurredduring the nine months ended September 30, 2006 was higher compared tothat incurred in the comparative period of 2007, primarily due to expenseassociated with unit awards granted in conjunction with the Company’s IPO inJanuary 2006.  In addition, IPO bonusesof $2.0 million were paid to certainexecutive officers during the nine months ended September 30, 2006.  General and administrative expenses arepresented net of approximately $0.4 millionand $0.9 million during the nine monthsended September 30, 2007 and 2006, respectively, which representexpense reimbursements from other working interest owners.

 

Depreciation, depletionand amortization increased to approximately$49.1 million for the nine months ended September 30, 2007, from $13.5million for the nine months ended September 30, 2006.  Of this increase, approximately $10.6 million was as a result of depletionrelated to the California and Oklahoma acquisitions in the third quarter of2006 and the Texas acquisitions during 2007. The properties acquired in the Mid-Continent acquisition contributedapproximately $9.3 million to the increase. Although total depreciation, depletion and amortization increased in thenine months ended September 30, 2007 due to higher total productionlevels, the reserves in the acquired Texas, Oklahoma and California propertieshave lower depletion rates than the reserves in the Appalachian Basin.  During the nine months ended September 30, 2007 and 2006, the Company capitalizedapproximately $7.7 million and $4.0 million, respectively, of costs forspecific activities related to drilling its wells, which include sitepreparation, drilling labor, meter installation, pipeline connection and sitereclamation.  Capitalized drilling costsincreased in the nine months ended September 30, 2007 due to the Company’spurchase and placement of two drilling rigs into service during the thirdquarter of 2006.  Company personnel alsoperform activities using leased equipment, and did so prior to the purchase ofits own rigs.

 

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Other income and(expenses) increased to a net expense of $42.6million for the nine months endedSeptember 30, 2007, compared to a net expense of $16.9 million for the nine months ended September 30, 2006,primarily due to increased interest expense from increased debt levelsassociated with borrowings to fund acquisitions and drilling.  Cash payments for interest increased to $29.3 million for the nine months ended September 30, 2007,compared to $13.6 million for the nine months ended September 30, 2006.  The Company’s interest rate swaps (seeNote 8 in Notes to Condensed Consolidated Financial Statements) were notdesignated as hedges under SFAS 133, even though they reduce exposure tochanges in interest rates.  Therefore,the changes in fair values of these instruments were recorded as a loss ofapproximately $3.7 million and a gain of$0.1 million for the nine monthsended September 30, 2007 and 2006, respectively.  These amounts are non-cash items.

 

Income tax was an expenseof approximately $4.0 million for the nine months ended September 30,2007, compared to a benefit of $74,000 for the nine months endedSeptember 30, 2006.  The Company’staxable subsidiaries generated net operating losses for the year endedDecember 31, 2006.  Management hassubsequently recovered expenses through an intercompany charge for servicesfrom Linn Operating, Inc. to Linn Energy, LLC, which resulted in acorresponding tax expense in the nine months ended September 30,2007.  In addition, the nine months endedSeptember 30, 2007 includes Texas margin tax expense of $0.4 million.

 

**Critical Accounting Policies andEstimates**

 

The preparation offinancial statements in accordance with GAAP requires management to select andapply accounting policies that best provide the framework to report its resultsof operations and financial position. The selection and application of those policies requires management tomake difficult subjective or complex judgments concerning reported amounts ofrevenue and expenses during the reporting period and the reported amounts ofassets and liabilities at the date of the financial statements.  As a result, there exists the likelihood thatmaterially different amounts would be reported under different conditions orusing different assumptions.

 

As of September 30, 2007, there have been no significant changeswith regard to the critical accounting policies disclosed in the Company’sAnnual Report on Form 10-K for the year ended December 31,2006.  The policies disclosed includedthe accounting for oil and gas properties, reserve quantities, revenuerecognition, purchase accounting and derivative instruments.

 

**Liquidity and Capital Resources**

 

The Company has utilized public and privateequity, proceeds from bank borrowings and cash flow from operations for capitalresources and liquidity.  To date, theprimary use of capital has been for the acquisition and development of oil andgas properties.  As the Company pursuesgrowth, it continually monitors the capital resources available to meet futurefinancial obligations and planned capital expenditures.  The Company’s future success in growingreserves and production will be highly dependent on the capital resourcesavailable and its success in drilling for or acquiring additionalreserves.  The Company actively reviewsacquisition opportunities on an ongoing basis. If the Company were to make significant additional acquisitions forcash, it would need to borrow additional amounts under the Credit Facility, ifavailable, or obtain additional debt or equity financing.  The Credit Facility imposes certainrestrictions on the Company’s ability to obtain additional debt financing.  Based upon current expectations, the Companybelieves liquidity and capital resources will be sufficient for the conduct ofits business and operations.

 

***Statements ofCash Flows – Operating Activities***

 

At September 30, 2007, the Company had cashand cash equivalents of approximately $33.6 million compared to $6.6 million atDecember 31, 2006.

 

Cash used by operating activities for the ninemonths ended September 30, 2007 was approximately $188.0 million, comparedto cash provided by operating activities of $8.0 million for the nine months endedSeptember 30, 2006.  The decrease incash provided by operating activities was primarily due to premiums paid forderivatives of approximately $257.1 million. These premiums relate to oil and gas put and swap contracts to hedgeprojected production through December 31, 2012.

 

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Cash flow from operations is subject to manyvariables, the most significant of which is the volatility of oil, gas and NGLprices.  Oil, gas and NGL prices aredetermined primarily by prevailing market conditions, which are dependent onregional and worldwide economic activity, weather and other factors beyond theCompany’s control.  Future cash flow fromoperations will depend on the Company’s ability to maintain and increase productionthrough its drilling program and acquisitions, as well as the prices receivedfor production.  The Company enters intoderivative arrangements to reduce the impact of commodity price volatility onoperations.  Currently, the Company usesfixed price swaps and puts to reduce its exposure to the volatility in oil, gasand NGL prices.  See Note 11 inNotes to Condensed Consolidated Financial Statements for details aboutderivatives in place through December 31, 2012.

 

***Statements of Cash Flows –Investing Activities***

 

Cash used in investing activities wasapproximately $2.64 billion for the nine months ended September 30, 2007,compared to $509.1 million for the nine months ended September 30,2006.  The increase in cash used ininvesting activities was primarily due to an increase in acquisition activityduring the nine months ended September 30, 2007, compared to the sameperiod of the prior year.

 

The total cash used in investing activities forthe nine months ended September 30, 2007 includes $2.03 billion for theMid-Continent acquisition, $484.5 million for the Panhandle I and Panhandle II acquisitionsand $38.6 million for the acquisitions of certain gas properties in WestVirginia. See Note 2 in Notes to Condensed Consolidated Financial Statementsfor additional details.  Otheracquisitions, including acquisitions of additional working interests in currentwells, were approximately $21.6 million and property, plant and equipmentpurchases were $12.5 million.  The totalfor the nine months ended September 30, 2007 also includes $54.2 millionfor the drilling and development of oil and gas properties.

 

***Statements of Cash Flows – Financing Activities***

 

Cash provided by financing activities wasapproximately $2.85 billion for the nine months ended September 30, 2007,compared to $491.8 million for the nine months ended September 30, 2006.

 

The Company recorded gross proceeds of $2.12 billion from three privateplacements of its units during the nine months ended September 30, 2007(see below).  The proceeds, net ofexpenses of approximately $34.3 million, were used to finance the Mid-Continent and Panhandle Iacquisitions, the acquisitions of certain gas properties in West Virginia, andto repay indebtedness under the Company’s Credit Facility.  During the ninemonths ended September 30, 2007, total proceeds from borrowingsunder the Credit Facility were $1.14 billion and total payments on the CreditFacility were $263.8 million.

 

***Distributions***

 

Under the limitedliability company agreement, Company unitholders are entitled to receive aquarterly distribution of available cash to the extent there is sufficient cashfrom operations after establishment of cash reserves and payment of fees andexpenses.  In January 2007, the Company’sBoard of Directors declared a distribution of $0.52 per unit with respect tothe fourth quarter of 2006.  Thedistribution totaled approximately $22.7 million and was paid in February2007.  In April 2007, the Company’s Board of Directorsdeclared a distribution of $0.52 per unit with respect to the first quarter of2007.  The distribution totaledapproximately $30.0 million and was paid in May 2007.  In July 2007, the Company’s Board ofDirectors declared a distribution of $0.57 per unit with respect to the secondquarter of 2007.  The distributiontotaled approximately $37.4 million and was paid in August 2007.

 

In October 2007, the Company’s Board of Directors declared adistribution of $0.57 per unit with respect to the third quarter of 2007.  The distribution will be paid in November2007 to unitholders of record as of the close of business on November 2,2007.  As previously announced,management currently intends to recommend to the Board of Directors a furtherincrease in the quarterly cash distribution to $0.63 per unit, or $2.52 perunit on an annualized basis, beginning with the distribution with respect tothe fourth quarter of 2007.

 

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***August 2007 PrivatePlacement***

 

In August 2007, theCompany closed its private placement of $1.5 billion of units to a groupof institutional investors, consisting of 34,997,005 Class D units at aprice of $30.97 per unit and 12,999,989 units at a price of $32.00 per unit. Proceeds,net of expenses, were $1.48 billion and wereused to fund the Mid-Continent acquisition (seeNote 2 in Notes to Condensed Consolidated Financial Statements).

 

The Class D unitsrepresent a class of equity securities that is entitled to a special quarterlydistribution equal to 115% of the distribution received by the holders ofunits, has no voting rights other than as required by law and is subordinatedto the units on dissolution and liquidation. In November 2007, at a special meetingof Linn unitholders, unitholders approved the one-for-one conversion of theClass D units into units. In connection with the August 2007 PrivatePlacement, the Company agreed to file a Registration Statement with the SECcovering the units and the Class D units. See “Liquidated Damages” below fordetails regarding potential penalties that could be incurred by the Company inthe event the Registration Statement is not declared effective by the SEC on orprior to February 12, 2008.

 

***June 2007 Private Placement***

 

In June 2007, the Companyclosed its private placement of $260.0 million of units to a group ofinstitutional investors, consisting of 7,761,194 units at a price of $33.50 perunit. Proceeds, net of expenses, were $255.2 million and were used torepay indebtedness under the Company’s Credit Facility. In connection with theJune 2007 Private Placement, the Company agreed to file a RegistrationStatement with the SEC covering the units. As discussed below under “February2007 Private Placement” and “October 2006 Private Placement,” the Company’sRegistration Statement on Form S-3, as amended, to register units issued in theOctober 2006 and February 2007 offerings, has not yet been declared effectiveby the SEC. Under the terms of the registration rights agreement with thepurchasers in the June 2007 Private Placement,the Company cannot file a Registration Statement toregister the units issued in the June 2007 Private Placement until theRegistration Statement covering the units issued in the February 2007 andOctober 2006 Private Placements is declared effective. See “Liquidated Damages”below for details regarding potential penalties that could be incurred by theCompany in the event the Registration Statement is not declared effective bythe SEC on or prior to November 13, 2007.

 

***February 2007Private Placement***

 

In February 2007, theCompany closed its private placement of$360.0 million of units to a group of institutional investors,consisting of 7,465,946 Class C units at a price of $25.06 per unit, and6,650,144 units at a price of $26.00 per unit. Proceeds, net of expenses, were$353.1 million and were used to finance the Panhandle I acquisitionand the acquisitions of certain gas properties in West Virginia (seeNote 2 in Notes to Condensed Consolidated Financial Statements).

 

The Class C unitswere converted into units on a one-for-one basis in April 2007. The Companyfiled a Registration Statement on Form S-3 with the SEC covering the unitsin September 2007 and Amendment No. 1 to Form S-3 in October 2007. Underthe registration rights agreement, as amended, liquidated damages could becomepayable if the Registration Statement is not declared effective by the SEC onor prior to December 31, 2007. The Registration Statement, as amended, hasnot yet been declared effective by the SEC. See “Liquidated Damages” below.

 

***October 2006Private Placement***

 

In connection with itsOctober 2006 private placement of units and Class B units (Class Bunits were converted to units on a one-for-one basis in January 2007), theCompany filed a Registration Statement on Form S-3 with the SEC coveringthe units in September 2007 and Amendment No. 1 to Form S-3 inOctober 2007. Under the registration rights agreement, as amended, liquidateddamages could become payable if the Registration Statement is not declaredeffective by the SEC on or prior to December 31, 2007. The RegistrationStatement, as amended, has not yet been declared effective by the SEC. See “LiquidatedDamages” below.

 

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***Liquidated Damages***

 

The Company could berequired to pay purchasers liquidated damages specified in the agreementspursuant to the October 2006, February 2007, June 2007 and August 2007 PrivatePlacements in the event the registration effectiveness deadlines noted aboveare not achieved. The potential payments under the agreements are 0.25% of thegross proceeds for each 30 day period that the registration deadlines are notmet, up through 90 days. Subsequent to 90 days, the potential payments wouldincrease for each 30 day period, up to a maximum of 1.0% of the gross proceedsof each offering. As of the date of this report, based on the facts discussedin “June 2007 Private Placement” above, it is reasonably possible that theCompany may be required to make some amount of such payments; however, theCompany does not expect payments under these agreements to be material to theCompany’s financial position or results of operations.

 

***Initial PublicOffering***

 

In the first quarter of2006, the Company completed its initial public offering of 12,450,000 unitsrepresenting limited liability company interests in the Company at $21.00 perunit, for net proceeds, after underwriting discounts of $18.3 million andoffering expenses of $4.3 million, of $238.8 million, of which $122.0 millionwas used to reduce indebtedness, $114.4 million was used to redeem a portion ofthe 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.

 

***Credit Facility***

 

On August 31, 2007 the Company entered into a new$1.8 billion Credit Facility with an available borrowing base of $1.8billion, of which $1.65 billion is conforming, and a maturity of August2010. In connection with its new Credit Facility, the Company paidapproximately $9.3 million in financing fees, which were deferred and are beingamortized over the life of the Credit Facility. In addition, during the threeand nine months ended September 30, 2007, the Company wrote off deferredfinancing fees related to its prior credit facility of approximately $2.2million and $2.8 million, respectively. At October 31, 2007, the Companyhad $450.5 million available for borrowing under its Credit Facility.

 

The borrowing base under the Credit Facility will be redeterminedsemi-annually by the lenders in their sole discretion, based on, among otherthings, reserve reports as prepared by reserve engineers taking into accountthe oil and gas prices at such time. The Company’s obligations under the CreditFacility are secured by mortgages on its oil and gas properties as well as apledge of all ownership interests in its operating subsidiaries. The Company isrequired to maintain the mortgages on properties representing at least 80% ofits oil and gas properties. Additionally, the obligations under the CreditFacility are guaranteed by all of the Company’s operating subsidiaries and maybe guaranteed by any future subsidiaries.

 

At the Company’s election, interest on borrowings under the CreditFacility is determined by reference to either LIBOR plus an applicable marginbetween 1.00% and 2.25% per annum or the ABR plus an applicable margin between0% and 0.75% per annum. Interest is generally payable quarterly for ABR loansand at the applicable maturity date for LIBOR loans.

 

The Credit Facility contains various covenants, substantially similarto the prior credit facility, that limit the Company’s ability to incurindebtedness, enter into interest rate swaps, grant certain liens, make certainloans, acquisitions, capital expenditures and investments, make distributionsother than from available cash, merge or consolidate, or engage in certainasset dispositions, including a sale of all or substantially all of its assets.The Credit Facility also contains covenants, substantially similar to the priorcredit facility, that require the Company to maintain specified financialratios. The other terms and conditions of the Credit Facility are substantiallysimilar to the prior credit facility.

 

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***Off-BalanceSheet Arrangements***

 

At September 30,2007, the Company did not have any off-balance sheet arrangements that have, orare reasonably likely to have, a material effect on its financial position orresults of operations.

 

***Contingencies***

 

The Company regularlyanalyzes current information and accrues for probable liabilities on thedisposition of certain matters, as necessary. Liabilities for losscontingencies arising from claims, assessments, litigation or other sources arerecorded when it is probable that a liability has been incurred and the amountcan be reasonably estimated.

 

***Commitmentsand Contractual Obligations***

 

The following table summarizes,as of September 30, 2007, certain contractual obligations that arereflected in the condensed consolidated balance sheet and/or disclosed in theaccompanying notes thereto:

 
| ** **                                      | ** ** | **Payments Due**   | ** ** |
|-------------------------------------------------|------------|--------------------|------------|
| **Contractual Obligations**                     | ** ** | **Total**          | ** ** | **October 1– December 31,  2007** | ** ** | **2008 – 2009** | ** ** | **2010 – 2011** | ** ** | **Thereafter** | ** ** |
| ** **                                      | ** ** | **(in thousands)** | ** ** |
| **Long-term  Debt Obligations:**                | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Long-term notes  payable                        |       | $                  | 1,622      |   | $ | 159 |   | $ | 1,007 |   | $ | 154 |   | $ | 302 |   |
| Credit Facility                                 |       | 1,302,000          |       | — |   | — |   | 1,302,000 |   | — |   |
| Interest on  Credit Facility computed at 7.188% |       | 265,166            |       | 23,397 |   | 187,176 |   | 54,593 |   | — |   |
| **Operating  Lease Obligations:**               | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Office and  office equipment leases             |       | 13,783             |       | 552 |   | 4,166 |   | 4,321 |   | 4,744 |   |
| **Other  Long-term Liabilities:**               | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Asset retirement  obligation                    |       | 27,124             |       | — |   | — |   | 103 |   | 27,021 |   |
| **Other:**                                      | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Derivative  instruments (1)                     |       | 167,664            |       | 5,324 |   | 79,540 |   | 66,215 |   | 16,585 |   |
| Drilling and  other contracts                   |       | 33,045             |       | 12,453 |   | 20,144 |   | 448 |   | — |   |
| Total                                           |       | $                  | 1,810,404  |   | $ | 41,885 |   | $ | 292,033 |   | $ | 1,427,834 |   | $ | 48,652 |   |

 

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(1)         Derivative instrumentsare presented on the condensed consolidated balance sheet on a gross basis. Amountspresented in the table above do not include offsetting derivative assets.

 

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**Non-GAAPFinancial Measure**

 

***Adjusted EBITDA***

 

The Company definesAdjusted EBITDA as net income (loss) plus:

 

•                  Net operating cash flow from acquisitions, effectivedate through closing date;

•                  Interest expense, net of amounts capitalized;

•                  Depreciation, depletion and amortization;

•                  Write-off of deferred financing fees and other;

•                  (Gain) loss on sale of assets;

•                  Accretion of asset retirement obligation;

•                  Unrealized (gain) loss on derivatives;

•                  Unit-based compensation and unit warrant expense;

•                  IPO cash bonuses; and

•                  Income tax provision.

 

Adjusted EBITDA is asignificant performance metric used by Company management to indicate (prior tothe establishment of any reserves by its Board of Directors) the cashdistributions the Company expects to pay unitholders. Specifically, thisfinancial measure indicates to investors whether or not the Company isgenerating cash flow at a level that can sustain or support an increase in itsquarterly distribution rates. Adjusted EBITDA is also a quantitative standardused throughout the investment community with respect to publicly-tradedpartnerships and limited liability companies.

 

For the third quarter of2007 as compared to the third quarter of 2006, Adjusted EBITDA increased 303%,from $25.1 million to $101.2 million. For the nine months endedSeptember 30, 2007 as compared to the comparable period of the prior year,Adjusted EBITDA increased 208%, from $55.7 million to $171.4 million.

 

The following tablepresents a reconciliation of consolidated net income (loss) to Adjusted EBITDA:

 
| ** **                                                                      | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|---------------------------------------------------------------------------------|------------|---------------------------------------|------------|--------------------------------------|------------|
| ** **                                                                      | ** ** | **2007**                              | ** ** | **2006**                             | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                                      | ** ** | **(in thousands)**                    | ** ** |
| Net income  (loss)                                                              |       | $                                     | (76,222    | )                                    | $          | 53,057 |   | $ | (161,195 | ) | $ | 85,273 |   |
| Plus:                                                                           |       |                                  |       |                                 |       |   |   |   |   |
| Net operating  cash flow from acquisitions, effective date through closing date |       | 46,957                                |       | —                               |       | 51,650 |   | 712 |   |
| Interest  expense, net of amounts capitalized                                   |       | 16,810                                |       | 11,204                               |       | 36,675 |   | 16,539 |   |
| Depreciation,  depletion and amortization                                       |       | 24,320                                |       | 5,654                                |       | 49,109 |   | 13,470 |   |
| Write-off of  deferred financing fees and other                                 |       | 2,235                                 |       | 161                                  |       | 2,784 |   | 664 |   |
| (Gain) loss on  sale of assets                                                  |       | 18                                    |       | (47                                  | )          | (867 | ) | — |   |
| Accretion of  asset retirement obligation                                       |       | 243                                   |       | 61                                   |       | 577 |   | 180 |   |
| Unrealized  (gain) loss on derivatives                                          |       | 83,364                                |       | (49,198                              | )          | 177,765 |   | (77,176 | ) |
| Unit-based  compensation and unit warrant expense                               |       | 3,199                                 |       | 4,191                                |       | 10,890 |   | 14,067 |   |
| IPO cash bonuses                                                                |       | —                                |       | —                               |       | — |   | 2,039 |   |
| Income tax  (benefit) provision (1)                                             |       | 321                                   |       | —                               |       | 3,983 |   | (74 | ) |
| Adjusted EBITDA                                                                 |       | $                                     | 101,245    |                                 | $          | 25,083 |   | $ | 171,371 |   | $ | 55,694 |   |

 

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(1)         The Company’staxable subsidiaries generated net operating losses for the year endedDecember 31, 2006. Management has subsequently recovered expenses throughan intercompany charge for services from Linn Operating, Inc. to Linn Energy,LLC, which resulted in a corresponding tax expense for the nine months endedSeptember 30, 2007.

 

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As noted above, AdjustedEBITDA is non-GAAP performance measure used by Company management to indicatethe cash distributions the Company expects to pay unitholders. On the condensedconsolidated statements of cash flows, net cash used by operating activitiesfor the nine months ended September 30, 2007, was approximately $188.0million and includes approximately $257.1 million invested in derivatives. Netcash provided by operating activities for the nine months endedSeptember 30, 2006, was approximately $8.0 million and includes $14.2million invested in derivatives.

 

**New Accounting Standards**

 

There have been no accountingstandards that materially affected the Company this period; however, seeNote 14 in Notes to Condensed Consolidated Financial Statements for detailregarding FIN 48.

 

**Cautionary Statement**

 

This Quarterly Report on Form 10-Q contains forward-lookingstatements that are subject to a number of risks and uncertainties, many ofwhich are beyond the Company’s control. These statements may include statementsabout the Company’s:

 

•                  businessstrategy;

•                  acquisitionstrategy;

•                  financialstrategy;

•                  drillinglocations;

•                  oil,gas and NGL reserves;

•                  realizedoil, gas and NGL prices;

•                  productionvolumes;

•                  leaseoperating expenses, general and administrative expenses and finding anddevelopment costs;

•                  futureoperating results; and

•                  plans,objectives, expectations and intentions.

 

All of these types of statements, other than statements of historicalfact included in this Quarterly Report on Form 10-Q, are forward lookingstatements. These forward-looking statements may be found in Item 2. Insome cases, forward-looking statements can be 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 comparable terminology.

 

The forward-looking statements contained in this Quarterly Report onForm 10-Q are largely based on Company expectations, which reflectestimates and assumptions made by Company management. These estimates andassumptions reflect management’s best judgment based on currently known marketconditions and other factors. Although the Company believes such estimates andassumptions to be reasonable, they are inherently uncertain and involve anumber of risks and uncertainties beyond its control. In addition, management’sassumptions may prove to be inaccurate. The Company cautions that theforward-looking statements contained in this Quarterly Report on Form 10-Qare not guarantees of future performance, and it cannot assure any reader thatsuch statements will be realized or the forward-looking statements or eventswill occur. Actual results may differ materially from those anticipated orimplied in forward-looking statements due to factors listed in “Item 1A.Risk Factors” in the Company’s Annual Report on Form 10-K for the yearended December 31, 2006, and elsewhere in the Annual Report and also inthe Company’s Quarterly Reports on Form 10-Q. The forward-lookingstatements speak only as of the date made, and other than as required by law,the Company undertakes no obligation to publicly update or revise anyforward-looking statement, whether as a result of new information, futureevents or otherwise.

 

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**Item 3.   Quantitative and Qualitative Disclosures About Market Risk**

** **

The primary objective of the following information is to provideforward-looking quantitative and qualitative information about potentialexposure to market risks. The term “market risk” refers to the risk of lossarising from adverse changes in oil, gas and NGL 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-lookinginformation provides indicators of how the Company views and manages itsongoing market risk exposures. All of the Company’s market risk sensitiveinstruments were entered into for purposes other than speculative trading.

 

**Commodity Price Risk**

 

The Company’s major market risk exposure is in the pricing applicableto oil, gas and NGL production. Realized pricing is primarily driven by thespot market prices applicable to production and the prevailing price for oil,gas and NGL. Pricing for oil, gas and NGL production has been historicallyvolatile and unpredictable, and this volatility is expected to continue in thefuture. The prices the Company receives for production depend on many factorsoutside of its control.

 

The Company enters intohedging arrangements with respect to a portion of its projected productionthrough various transactions that hedge the future prices received. SeeNote 11 in Notes to Condensed Consolidated Financial Statements foradditional details. These transactions may include price swaps whereby theCompany will receive a fixed price for production and pay a variable marketprice to the contract counterparty. At the settlement date, the Companyreceives the excess, if any, of the fixed NYMEX or PEPL price floor over thefloating rate. Additionally, the Company has put options for which it pays thecounterparty the fair value at the purchase date. These hedging activities areintended to support commodity prices at targeted levels and to manage exposureto oil, gas and NGL price fluctuations. The Company does not hold or issuederivative instruments for speculative trading purposes.

 

At September 30, 2007, the fair value of hedges that settle duringthe next twelve months was an asset of approximately $73.5 million and aliability of approximately $30.8 million for a net asset of approximately $42.7million, which the Company is owed by the counterparty. A 10% increase in theindex oil and gas prices above the September 30, 2007 prices for the nexttwelve months would result in a reduction in the value of the hedges ofapproximately $90.1 million; conversely, a 10% decrease in the index oil andgas prices would result in an increase of approximately $82.7 million.

 

**Interest Rate Risk**

 

At September 30,2007, the Company had long-term debt outstanding of $1.3 billion under itsCredit Facility, which incurred interest at floating rates in accordance theCredit Facility agreement. See Note 6 in Notes to Condensed ConsolidatedFinancial Statements for additional details about the Credit Facility. As ofSeptember 30, 2007, the interest rate based on LIBOR was approximately7.188%. A 1% increase in LIBOR would result in an estimated $8.2 millionincrease in annual interest expense associated with the Credit Facility.

 

The Company hasperiodically entered into interest rate swap agreements to minimize the effectof fluctuations in interest rates. The Company is required to paycounterparties the difference between the contract’s fixed rate and the actualrate if the actual rate is lower than the fixed rate and conversely,counterparties are required to pay the Company if the actual rate is higherthan the fixed rate in the contract. See Note 8 in Notes to CondensedConsolidated Financial Statements for additional details.

 

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The following tablepresents the settlement terms of the interest rate swaps:

 

| ** **                                            | ** ** | **Notional  Amount** | ** ** | **Fixed  Rate** | ** ** |
|-------------------------------------------------------|------------|----------------------|------------|-----------------|------------|
| ** **                                            | ** ** | **(in thousands)**   | ** ** | ** **      | ** ** |
|                                                  |       |                 |       |            |       |
| Settles monthly,  October 2007 – January 2008    |       | $                    | 985,000    |            | 4.79       | % |
| Settles monthly,  January 2008 – January 2009    |       | $                    | 985,000    |            | 4.25       | % |
| Settles monthly,  January 2009 – January 2011    |       | $                    | 985,000    |            | 5.10       | % |
| Settles  quarterly, October 2007 – December 2007 |       | $                    | 50,000     |            | 5.30       | % |
| Settles  quarterly, January 2008 – December 2008 |       | $                    | 50,000     |            | 5.79       | % |

 

Under the terms of theswap agreements, interest is based on LIBOR. A 1% change in LIBOR as ofSeptember 30, 2007 would result in an estimated $9.1 million change inannual expense associated with the interest swap agreements.

 

The Company didnot designate the interest rate swap agreements as cash flow hedges underSFAS 133; therefore, the changes in fair value of these instruments, whichare non-cash gains or losses, are recorded in current earnings.

 

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**Item 4.   Controls and Procedures**

** **

***(a) *Evaluation of disclosure controls and procedures**

 

The Company maintains disclosure controls and procedures that aredesigned to ensure that information required to be disclosed in the Company’sreports under the Securities Exchange Act of 1934 is recorded, processed,summarized and reported within the time periods specified in the SEC’s rulesand forms, and that such information is accumulated and communicated tomanagement, including the Company’s Chief Executive Officer and Chief FinancialOfficer, and the Company’s Audit Committee of the Board of Directors, asappropriate, to allow timely decisions regarding required disclosure. Indesigning and evaluating the disclosure controls and procedures, managementrecognizes that any controls and procedures, no matter how well designed andoperated, can provide only reasonable assurance of achieving the desiredcontrol objectives, and management is required to apply its judgment inevaluating the cost-benefit relationship of possible controls and procedures.

 

The Company carried out an evaluation under the supervision and withthe participation of its management, including its Chief Executive Officer andChief Financial Officer, of the effectiveness of its disclosure controls andprocedures as of the end of the period covered by this report.

 

Due to the remediation status of our material weaknesses describedbelow, our Chief Executive Officer and Chief Financial Officer continue toconclude that our disclosure controls and procedures were not effective as ofSeptember 30, 2007. We believe we have taken the necessary steps toaddress the matters related to the material weaknesses described below and weconclude that material weaknesses (i), (iii) and (iv) have been remediated. Regardingmaterial weakness (ii), review controls, including controls over significantcomputations involving estimates and judgment, we believe that these internalcontrols have not been implemented and operational for a sufficient period oftime to demonstrate they are effective and have thus not been remediated. Webelieve our condensed consolidated financial statements included in thisQuarterly Report on Form 10-Q fairly present in all material respects ourfinancial position, results of operations and cash flows for the periodspresented in accordance with United States generally accepted accountingprinciples.

 

*Material weaknesses in internalcontrol*. Specifically, the Company lacked:  (i) personnel with sufficient technicalaccounting and financial reporting expertise, (ii) adequate reviewcontrols over account reconciliations and account analyses, (iii) policiesand procedures to determine and document the appropriate application ofaccounting principles, and (iv) policies and procedures requiring adetailed and comprehensive review of the underlying information supporting theamounts included in the annual and interim consolidated financial statementsand disclosures. As noted above, we conclude that material weaknesses (i),(iii) and (iv) have been remediated and that material weakness (ii) has notbeen remediated.

 

*Remediation activities.*During2006 and the first six months of 2007, Company management took the followingsteps to strengthen internal control over financial reporting:

 

1.              Recruited anexperienced accounting team with over 130 combined years of experience in oiland gas accounting and financial reporting.

 

2.              Utilized outsideconsultants with extensive oil and gas financial reporting experience andaugmented accounting resources to assist with required filings and documentationof reconciliations and procedures.

 

3.              Developed accountingand reporting position papers for critical accounting policies involvingjudgment or application of complex accounting standards.

 

4.              Performed additionalanalysis and other post-closing procedures to enable the preparation ofaccurate consolidated financial statements, including all required disclosures.In addition, implemented certain review and monitoring controls over accountreconciliations, and analysis and post-closing procedures.

 

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5.              Developed andimplemented a process for determining the effective accounting date for an oiland gas property acquisition and formalized procedures necessary toappropriately account for future acquisitions.

 

6.              Implemented the useof disclosure checklists addressing the disclosure requirements under GAAP aswell as the incremental financial and non-financial information required by SECregulations.

 

7.              Provided extensivetraining on the accounting software system to both new and establishedaccounting personnel.

 

8.              Strengthenedcontrols over financially significant spreadsheets, including change, version,access, input/output and data controls.

 

9.              Enhanced informationtechnology (“IT”) controls, in areas including the general IT environment,access to programs and data and change management.

 

In addition, to further enhance controls, during the three months endedSeptember 30, 2007, the following improvements were implemented:

 

1.              Implemented aDisclosure Committee to ensure that information required to be disclosed inperiodic reports filed with the SEC is recorded, processed, summarized andreported correctly and within the required time periods.

 

2.              Expandedidentification of key financial reporting controls and implemented the use ofrisk control matrices to monitor the effectiveness of key controls.

 

As noted above, we believe we have taken the necessary steps to addressthe matters related to the material weaknesses described above and we concludethat material weaknesses (i), (iii) and (iv) have been remediated. Regardingmaterial weakness (ii), review controls, including controls over significantcomputations involving estimates and judgment, we believe that these internalcontrols have not been implemented and operational for a sufficient period oftime to demonstrate they are effective and have thus not been remediated.

 

***(b)***  **Changesand remediation in the Company’s internal control over financial reporting**

 

The items noted above constitute the changes in the Company’s internalcontrol over financial reporting, as defined in Rule 13(a)-15(f) under theExchange Act, during the three months ended September 30, 2007, that havematerially affected, or are reasonably likely to materially affect, the Company’sinternal control over financial reporting.

 

As previously reported, the Company expects to continue to make changesin internal control over financial reporting during the periods prior toDecember 31, 2007 in connection with its compliance efforts underSection 404 of the Sarbanes-Oxley Act of 2002. As such, the Company willcontinue to assess the adequacy of 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.

 

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** **

**PART II – OTHER INFORMATION**

** **

**Item 1.      Legal Proceedings**

 

Not applicable.

 

**Item 1A.   Risk Factors**

 

Our business has manyrisks. As of the date of this report, the factors that have materially changedfrom those reported in “Item 1A. Risk Factors” in our Annual Report onForm 10-K for the year ended December 31, 2006 are presented below. Theserisk factors primarily relate to the new $1.8 billion Credit Facility weentered into in August 2007 and the addition of NGL to our revenue stream inthe first quarter of 2007, in conjunction with our acquisition of properties inthe Texas Panhandle. This information should be considered carefully, togetherwith other information in this report and other reports and materials we filewith the SEC.

 

**RisksRelated 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 havesufficient cash flow from operations each quarter to pay the quarterlydistribution at the current distribution level. Under the terms of our limitedliability company agreement, the amount of cash otherwise available fordistribution will be reduced by our operating expenses and the amount of anycash reserve amounts that our Board of Directors establishes to provide forfuture operations, future capital expenditures, future debt servicerequirements and future cash distributions to our unitholders. The amount ofcash we can distribute on our units principally depends upon the amount of cashwe generate from our operations, which will fluctuate from quarter to quarterbased on, among other things:

 

•                  theamount of oil, gas and NGL we produce;

•                  theprice at which we are able to sell our oil, gas and NGL production;

•                  thelevel of our operating costs;

•                  thelevel of our interest expense, which depends on the amount of our indebtednessand the interest payable thereon; and

•                  thelevel of our capital expenditures.

 

In addition, the actualamount of cash we will have available for distribution will depend on otherfactors, some of which are beyond our control, including:

 

•                  ourability to make working capital borrowings under our Credit Facility to paydistributions;

•                  thecosts of acquisitions, if any;

•                  fluctuationsin our working capital needs;

•                  timingand collectibility of receivables;

•                  restrictionson distributions contained in our Credit Facility;

•                  prevailingeconomic conditions; and

•                  theamount of cash reserves established by our Board of Directors for the properconduct of our business.

 

As a result of thesefactors, the amount of cash we distribute to our unitholders in any quarter mayfluctuate significantly from quarter to quarter and may be significantly lessthan the current distribution level.

 

***Weactively seek to acquire oil and gas properties. Acquisitions involve potentialrisks that could adversely impact our future growth and our ability to increasedistributions.***

 

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

 

•                  therisk that reserves expected to support the acquired assets may not be of theanticipated magnitude or may not be developed as anticipated;

 

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•                  inaccurateassumptions about revenues and costs, including synergies;

•                  significantincreases in our indebtedness and working capital requirements;

•                  aninability to transition and integrate successfully or timely the businesses weacquire;

•                  aninability to integrate data systems successfully or timely;

•                  theassumption of unknown liabilities;

•                  limitationson rights to indemnity from the seller;

•                  thediversion of management’s attention from other business concerns;

•                  increaseddemands on existing personnel and on our corporate structure;

•                  customeror key employee losses at the acquired businesses; and

•                  thefailure to realize expected growth or profitability.

 

The scope and cost of these risks may ultimately bematerially greater than estimated at the time of the acquisition. Further, ourfuture acquisition costs may be higher than those we have achieved historically.Any of these factors could adversely impact our future growth and our abilityto increase distributions.

 

***We havesignificant indebtedness under our Credit Facility. Our Credit Facility hassubstantial restrictions and financial covenants and we may have difficultyobtaining additional credit, which could adversely affect our operations andour ability to pay distributions to our unitholders.***

 

We have significant indebtedness under our CreditFacility. As of October 31, 2007, we had approximately $1.35 billionoutstanding under our Credit Facility (with additional borrowing capacity ofapproximately $450.5 million). As a result of our indebtedness, we will use aportion of our cash flow to pay interest when due, which will reduce the cashavailable to finance our operations and other business activities and couldlimit our flexibility in planning for or reacting to changes in our businessand the industry 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 raise capital onfavorable terms will be affected by our debt level and by adverse marketconditions resulting from, among other things, general economic conditions,contingencies and uncertainties that are difficult to predict and impossible tocontrol. Such a development could adversely affect our ability to obtainfinancing for working capital, capital expenditures or acquisitions or torefinance existing indebtedness.

 

We depend on our Credit Facility for future capitalneeds and to fund distributions. The Credit Facility restricts our ability toobtain additional financing, enter into interest rate swaps, make investments,lease equipment, sell assets and engage in business combinations. We also arerequired to comply with certain financial covenants and ratios. Our ability tocomply with these restrictions and covenants in the future is uncertain andwill be affected by the levels of cash flow from our operations and events orcircumstances beyond our control. Our failure to comply with any of therestrictions and covenants under our Credit Facility could result in a defaultunder our Credit Facility, which could cause all of our existing indebtednessto be immediately due and payable.

 

Availability under our Credit Facility is determinedsemi-annually at the discretion of the lenders and is based in part on oil, gasand NGL prices. The lenders can unilaterally adjust the borrowing base and theborrowings permitted to be outstanding under the Credit Facility. Any increasein the borrowing base requires the consent of all the lenders. Outstandingborrowings in excess of the borrowing base must be repaid immediately, or wemust pledge other properties as additional collateral. We do not currently haveany substantial unpledged properties, and we may not have the financialresources in the future to make any mandatory principal prepayments requiredunder the Credit Facility. Significant declines in our production orsignificant declines in realized oil, gas or NGL prices for prolonged periodsand resulting decreases in our borrowing base may force us to reduce or suspenddistributions to our unitholders.

 

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***If commodityprices decline significantly for a prolonged period, our cash flow fromoperations will decline, and we may have to lower our distribution rate or maynot be able to pay distributions at all.***

 

Our revenue,profitability and cash flow depend upon the prices of and demand for oil, gasand NGL. The oil, gas and NGL market is very volatile and a drop in prices cansignificantly affect our financial results and impede our growth. Changes inoil, gas and NGL prices have a significant impact on the value of our reservesand on our cash flow. Prices for these commodities may fluctuate widely inresponse to relatively minor changes in the supply of and demand for them,market uncertainty and a variety of additional factors that are beyond ourcontrol, such as:

 

•                  thedomestic and foreign supply of and demand for oil, gas and NGL;

•                  theprice and level of foreign imports;

•                  regionalprice differentials;

•                  thelevel of consumer product demand;

•                  weatherconditions;

•                  overalldomestic and global economic conditions;

•                  politicaland economic conditions in oil and gas producing countries, including those inthe Middle East and South America;

•                  theability of members of the Organization of Petroleum Exporting Countries toagree to and maintain price and production controls;

•                  theimpact of the U.S. dollar exchange rates on oil, gas and NGL prices;

•                  technologicaladvances affecting energy consumption;

•                  domesticand foreign governmental regulations and taxation;

•                  theimpact of energy conservation efforts;

•                  theproximity and capacity of pipelines and other transportation facilities; and

•                  theprice and availability of alternative fuels.

 

In the past, the pricesof oil, gas and NGL have been extremely volatile, and we expect this volatilityto continue. If commodity prices decline significantly for a prolonged period,our cash flow from operations will decline, and we may have to lower ourdistribution or may not be able to pay distributions at all.

 

***Future price declines or downwardreserve revisions may result in a write-down of our asset carrying values.***

 

Declines in oil, gas and NGL prices may result in ourhaving to make substantial downward adjustments to our estimated provedreserves. 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 properties for impairments. We are required to performimpairment tests on our assets periodically and whenever events or changes incircumstances warrant a review of our assets. To the extent such tests indicatea reduction of the estimated useful life or estimated future cash flows of ourassets, the carrying value may not be recoverable and therefore require awrite-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 wereplace our reserves, our reserves and production will decline, which wouldadversely affect our cash flow from operations and our ability to makedistributions to our unitholders.***

 

Producing oil and gas reservoirs are characterized bydeclining production rates that vary depending upon reservoir characteristicsand other factors. The overall rate of decline for our production will changeif production from our existing wells declines in a different manner than wehave estimated and can change when we drill additional wells, make acquisitionsand under other circumstances. Thus, our future oil, gas and NGL reserves andproduction and, therefore, our cash flow and income, are highly dependent onour success in efficiently developing and exploiting our current reserves andfinding or acquiring additional economically recoverable reserves. We may notbe able to develop, find or acquire additional reserves to replace our currentand future production at acceptable costs, which would adversely affect ourcash flow from operations and our ability to make distributions to ourunitholders.

 

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***Our estimatedreserves are based on many assumptions that may prove to be inaccurate. Anymaterial inaccuracies in these reserve estimates or underlying assumptions willmaterially affect the quantities and present value of our reserves.***

 

No one can measure underground accumulations of oil,gas and NGL in an exact way. Reserve engineering requires subjective estimatesof underground accumulations of oil, gas and NGL and assumptions concerningfuture oil, gas and NGL prices, production levels, and operating anddevelopment costs. As a result, estimated quantities of proved reserves andprojections of future production rates and the timing of developmentexpenditures may prove to be inaccurate. An independent petroleum engineeringfirm prepares estimates of our proved reserves. Over time, our internal engineersmay make material changes to reserve estimates taking into account the resultsof actual drilling and production. Some of our reserve estimates are madewithout the benefit of a lengthy production history, which are less reliablethan estimates based on a lengthy production history. Also, we make certainassumptions regarding future oil, gas and NGL prices, production levels, andoperating and development costs that may prove incorrect. Any significantvariance from these assumptions by actual figures could greatly affect ourestimates of reserves, the economically recoverable quantities of oil, gas andNGL attributable to any particular group of properties, the classifications ofreserves based on risk of recovery and estimates of the future net cash flows. Numerouschanges over time to the assumptions on which our reserve estimates are based,as described above, often result in the actual quantities of oil, gas and NGLwe ultimately recover being different from our reserve estimates.

 

The present value of future net cash flows from ourproved reserves is not necessarily the same as the current market value of ourestimated oil, gas and NGL reserves. We base the estimated discounted futurenet cash flows from our proved reserves on prices and costs in effect on theday of estimate. Actual future net cash flows from our properties also will beaffected by factors such as:

 

•                  actualprices we receive for oil, gas and NGL;

•                  theamount and timing of actual production;

•                  supplyof and demand for oil, gas and NGL; and

•                  changesin governmental regulations or taxation.

 

The timing of both our production and our incurrenceof expenses in connection with the development and production of our propertieswill affect the timing of actual future net cash flows from proved reserves,and thus their actual present value. In addition, the 10% discount factor,required to be used pursuant to SFAS No. 69, “*Disclosuresabout Oil and Gas Producing Activities*” when calculating discountedfuture net cash flows, may not be the most appropriate discount factor based oninterest rates in effect from time to time and risks associated with us or theoil and gas industry in general.

 

***Our developmentoperations require substantial capital expenditures, which will reduce our cashavailable for distribution. We may be unable to obtain needed capital orfinancing on satisfactory terms, which could lead to a decline in our reserves.***

 

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

 

•                  ourproved reserves;

•                  thelevel of oil, gas and NGL we are able to produce from existing wells;

•                  theprices at which we are able to sell our oil, gas and NGL; and

•                  ourability to acquire, locate and produce new reserves.

 

If our revenues or the borrowing base under our CreditFacility decrease as a result of lower oil, gas and NGL prices, operatingdifficulties, declines in reserves or for any other reason, we may have limitedability to obtain the capital necessary to sustain our operations at currentlevels. Our Credit Facility restricts our ability to obtain new financing.

 

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If additional capital is needed, we may not be able toobtain debt or equity financing on terms favorable to us, or at all. If cashgenerated by operations or available under our Credit Facility is notsufficient to meet our capital requirements, the failure to obtain additionalfinancing could result in a curtailment of our development operations, which inturn could lead to a possible decline in our reserves, cash flow, and futuredistributions.

 

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

 

The marketability of our oil, gas and NGL productiondepends in part on the availability, proximity and capacity of gathering andpipeline systems. The amount of oil, gas and NGL that can be produced and soldis subject to limitation in certain circumstances, such as pipelineinterruptions due to scheduled and unscheduled maintenance, excessive pressure,physical damage to the gathering or transportation system, or lack ofcontracted capacity on such systems. The curtailments arising from these andsimilar circumstances may last from a few days to several months. In manycases, we are provided only with limited, if any, notice as to when thesecircumstances will arise and their duration. In addition, some of our wells aredrilled 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 the oil, gas and NGL production from these wellsuntil the necessary gathering and transportation systems are constructed. Anysignificant 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, gas and NGL weproduce, and could reduce our cash available for distribution and adverselyimpact expected increases in production from our drilling program.

 

***We depend oncertain key customers for sales of our oil, gas and NGL. To the extent theseand other customers reduce the volumes of oil, gas and NGL they purchase fromus, our revenues and cash available for distribution could decline.***

 

For the nine months ended September 30, 2007,Dominion Resources, Inc., Duke Energy Corporation and ConocoPhillips accountedfor approximately 26%, 22% and 16%, respectively, of our total volumes, or 64%in the aggregate. For the year ended December 31, 2006, DominionResources, Inc. and ConocoPhillips accounted for approximately 53%, and 14%,respectively, of our total volumes, or 67% in the aggregate. To the extentthese and other customers reduce the volumes of oil, gas or NGL that theypurchase from us, our revenues and cash available for distribution coulddecline.

 

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

 

Higher oil, gas and NGLprices increase the demand for drilling rigs, pipe, equipment and crews and canlead to shortages of, and increasing costs for, drilling equipment, servicesand personnel. Shortages of, or increasing costs for, experienced drillingcrews and oil field equipment and services could restrict our ability to drillthe wells and conduct the operations which we currently have planned. Any delayin the drilling of new wells or significant increase in drilling costs couldimpact our ability to generate sufficient cash flow from operations to payquarterly distributions to our unitholders at the current distribution level.

 

***As a result of contractuallyrequired registrations of our units, a substantial amount of our units may besold in the future, which could reduce the market price of our outstandingunits.***

 

We have agreed toregister for sale approximately 94.6 million units held by certain investorsand certain members of our management.

 

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Our RegistrationStatement on Form S-3 filed in September 2007, as amended in October 2007(the “Form S-3”), includes a total of 38,350,470 units comprising:

 

•                  theunits and the units underlying the Class B units issued in October 2006that were requested by the holders to be registered;

•                  theunits and the units underlying the Class C units issued in February 2007that were requested by the holders to be registered; and

•                  unitsheld by certain members of our management.

 

The RegistrationStatement, as amended, has not yet been declared effective by the SEC.

 

In addition to the unitsavailable for resale under the Form S-3, in June 2007, we completed a privateoffering to institutional investors of 7,761,194 units. We agreed to file aRegistration Statement with the SEC covering the units. In accordance with theagreement, if the Registration Statement is not declared effective by the SECby November 13, 2007, we could be required to pay purchasers liquidateddamages as defined in the agreement. As noted above, the Form S-3 has notyet been declared effective by the SEC. We cannot file a Registration Statementto register the units issued in the June 2007 or August 2007 offerings untilthe Form S-3 is declared effective.

 

In August 2007, wecompleted a private offering to a group of institutional investors of12,999,989 units and 34,997,005 newly created Class D units. We agreed tofile a Registration Statement with the SEC covering the units and the unitsunderlying the Class D units, which were converted into units on aone-for-one basis in November 2007. In accordance with the agreement, if theRegistration Statement is not declared effective by the SEC byFebruary 12, 2008, we could be required to pay purchasers liquidateddamages as defined in the agreement.

 

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.

 

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**Item 2.   Unregistered Sales of Equity Securities and Use of Proceeds**

 

None not previously reported.

 

**Item 3.   Defaults Upon Senior Securities**

 

None.

 

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

 

None.

 

**Item 5.   Other Information**

 

None.

 

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**Item 6.   Exhibits - Continued**

 
| **Exhibit Number** | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                            |
|-------------------------|------------|------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.1                     |       | —     |       | Amended and Restated  Mid-Continent Onshore Package Purchase Agreement, dated August 30, 2007,  between Dominion Exploration & Production, Inc., Dominion Oklahoma Texas  Exploration & Production, Inc., LDNG Texas Holdings, LLC, and DEPI Texas  Holdings, LLC, as Sellers, and Linn Energy, LLC, as Purchaser (incorporated  herein by reference to Exhibit 2.1 to Current Report on Form 8-K  filed on September 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 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  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 (incorporated herein by reference to Exhibit 3.3  to Annual Report on Form 10-K filed on March 30, 2007)                                                                                                                                                                                                                  |
| 3.4                     |       | —     |       | Amendment No. 1 to  Second Amended and Restated Limited Liability Company Agreement of Linn  Energy, LLC dated October 24, 2006 (incorporated herein by reference to  Exhibit 3.3 to Annual Report on Form 10-K filed on March 30,  2007)                                                                                                                                                                                         |
| 3.5                     |       | —     |       | Amendment No. 2 to  Second Amended and Restated Limited Liability Company Agreement of Linn  Energy, LLC dated February 1, 2007 (incorporated herein by reference to  Exhibit 3.3 to Annual Report on Form 10-K filed on March 30,  2007)                                                                                                                                                                                         |
| 3.6                     |       | —     |       | Amendment No. 3 to  Second Amended and Restated Limited Liability Company Agreement of Linn  Energy, LLC dated August 31, 2007 (incorporated herein by reference to  Exhibit 4.1 to Current Report on Form 8-K filed on  September 5, 2007)                                                                                                                                                                                       |
| 4.1                     |       | —     |       | Form of specimen unit  certificate for the units of Linn Energy, LLC (incorporated herein by reference  to Exhibit 4.1 to Annual Report on Form 10-K filed on May 31,  2006)                                                                                                                                                                                                                                                                |
| 10.1                    |       | —     |       | Third Amended and  Restated Credit Agreement dated August 31, 2007, among Linn Energy, LLC,  as borrower, BNP Paribas, as administrative agent, and the agents and lenders  party thereto (incorporated herein by reference to Exhibit 10.1 to Form  8-K filed on September 5, 2007)                                                                                                                                                        |
| 10.2                    |       | —     |       | Third Amended and  Restated Guaranty and Pledge Agreement, dated August 31, 2007, among  Linn Energy, LLC, the other obligors named therein and BNP Paribas, as  administrative agent (incorporated herein by reference to Exhibit 10.2  to Form 8-K filed on September 5, 2007)                                                                                                                                                       |
| 10.3                    |       | —     |       | Registration Rights  Agreement, dated August 31, 2007 by and among Linn Energy, LLC and the  Purchasers named therein (incorporated herein by reference to  Exhibit 10.3 to Current Report on Form 8-K filed on  September 5, 2007)                                                                                                                                                                                                    |
| 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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†  Filed herewith.

 

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** **

**SIGNATURE**

 

Pursuant to the requirements of the Securities Exchange Act of 1934,the registrant has duly caused this report to be signed on its behalf by theundersigned, thereunto duly authorized.

 

 
|                        | **LINN  ENERGY, LLC**                                      |
|-----------------------------|------------------------------------------------------------|
|                        | (Registrant)                                               |
|                        |                                                       |
|                        |                                                       |
| Date: November 9, 2007 | /s/ Lisa D. Anderson                                       |
|                        | Lisa D. Anderson                                           |
|                        | Senior Vice President  and Chief Accounting Officer        |
|                        | (As Duly Authorized  Officer and Chief Accounting Officer) |

 

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