** **

**UNITED STATES SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C.20549**

**Form 10-Q**

**x**                              QUARTERLYREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

** **

**For the QuarterlyPeriod Ended September 30, 2006**

**OR**

** **

**o**                                 TRANSITION REPORTPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

**for the transitionperiod from                                 to                                 **

**Commission FileNumber: 000-51719**

**LINN ENERGY, LLC**

(Exact name ofregistrant as specified in its charter)

 

| **Delaware**                     |   | **65-1177591**          |
|----------------------------------|--------|-------------------------|
| (State or other  jurisdiction of |   | (I.R.S. Employer        |
| incorporation or  organization)  |   | Identification  Number) |

 

**650Washington Road8****th FloorPittsburgh, PA  15228**(Address of principal executive offices)

**(412)440-1400**

(Registrant’s telephone number, including area code) 

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

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

Large acceleratedfiler  o        Acceleratedfiler    o      Non-acceleratedfiler  x

Indicate by checkmark whether registrant is a shell company (as defined in Rule 12b-2 of theExchange Act).  Yes  o    No  x

As of November 1, 2006, there were 33,417,187units outstanding.

As of November 1, 2006, there were 9,185,965 class B units outstanding.

 

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**TABLE OF CONTENTS**

** **

 
|          | ** ** | ** **                                                                                                                  | ** ** | **Page** |
|----------|------------|-----------------------------------------------------------------------------------------------------------------------------|------------|----------|
|     | ** ** | **Glossary of Terms**                                                                                                       | ** ** | 3        |
|     | ** ** | ** **                                                                                                                  | ** ** |     |
|          | ** ** | **Part  I - Financial Information**                                                                                         | ** ** |     |
| Item 1.  |       | Financial Statements                                                                                                        |       |     |
|     |       | Condensed Consolidated Balance Sheets as of September  30, 2006 (Unaudited) and December 31, 2005                 |       | 5        |
|     |       | Condensed Consolidated Statements of Operations for  the three and nine months ended September 30, 2006 and2005 (Unaudited) |       | 7        |
|     |       | Condensed Consolidated Statements of Unitholders’  Capital for the nine months ended September 30, 2006 (Unaudited)    |       | 8        |
|     |       | Condensed Consolidated Statements of Cash Flows for  the nine months ended September 30, 2006 and 2005 (Unaudited)          |       | 9        |
|     |       | Notes to Condensed Consolidated Financial Statements  (Unaudited)                                                           |       | 11       |
| Item 2.  |       | Management’s Discussion  and Analysis of Financial Condition and Results of Operations                                 |       | 26       |
| Item 3.  |       | Quantitative and Qualitative Disclosures About Market  Risk                                                                 |       | 39       |
| Item 4.  |       | Controls and Procedures                                                                                                     |       | 41       |
|     | ** ** | **Part II - Other  Information**                                                                                            | ** ** |     |
| Item 1.  |       | Legal Proceedings                                                                                                           |       | 43       |
| Item 1A. |       | Risk  Factors                                                                                                               |       | 43       |
| Item 2.  |       | Unregistered  Sales of Equity Securities and Use of Proceeds                                                                |       | 45       |
| Item 3.  |       | Defaults Upon Senior  Securities                                                                                            |       | 45       |
| Item 4.  |       | Submission of  Matters to a Vote of Security Holders                                                                        |       | 45       |
| Item 5.  |       | Other Information                                                                                                           |       | 45       |
| Item 6.  |       | Exhibits                                                                                                                    |       | 46       |
|     | ** ** | **Signature**                                                                                                               |       | 48       |

2

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**GLOSSARY OF TERMS**

As commonly used in theoil and gas industry and as used in this Quarterly Report on Form10-Q, thefollowing terms have the following meanings:

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

*Bcf.* One billion cubic feet.

*Bcfe.* One billion cubic feetequivalent, determined using a ratio of six Mcf of natural gas to one Bbl ofcrude oil, condensate or natural gas liquids.

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

*Development well.* A well drilledwithin the proved area of an oil or gas reservoir to the depth of astratigraphic horizon known to be productive.

*Dth.* One decatherm, equivalent toone million British thermal units.

*Developed acres.* Acres spaced orassigned 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 area consisting of asingle reservoir or multiple reservoirs all grouped on or related to the sameindividual geological structural feature and/or stratigraphic condition.

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

*MBbls.* One thousand barrels ofcrude oil or other liquid hydrocarbons.

*Mcf.* One thousand cubic feet.

*Mcfe.* One thousand cubic feetequivalent, determined using the ratio of six Mcf of natural gas to one Bbl ofcrude oil, condensate or natural gas liquids.

*MMBbls.* One million barrels ofcrude oil or other liquid hydrocarbons.

*MMBtu.* One million British thermalunits.

*MMcf.* One million cubic feet.

*MMcfe.* One million cubic feetequivalent, determined using a ratio of six Mcf of natural gas to one Bbl ofcrude oil, condensate or natural gas liquids.

*MMcfe/d.* One MMcfe per day.

*MMMBtu.* One billion British thermalunits.

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

*NYMEX.* The New York MercantileExchange.

*Oil.* Crude oil, condensate andnatural gas liquids.

*Productive well.* A well that isfound to be capable of producing hydrocarbons in sufficient quantities suchthat proceeds from the sale of such production exceeds production expenses andtaxes.

*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 obtained through the applicationof fluid injection or other improved recovery techniques for supplementing thenatural forces and mechanisms of primary recovery are included in “proveddeveloped reserves” only after testing by a pilot project or after theoperation of an installed program has confirmed through production responsethat increased recovery will be achieved.

*Proved reserves.* Proved oil and gasreserves are the estimated quantities of natural gas, natural gas liquids andcrude 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.Prices include consideration of changes in existing prices provided only bycontractual arrangements, but not on escalations based on future conditions.

*Proved undeveloped drilling location.*A site on which a development well can be drilled consistent with spacing rulesfor 

3

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purposes of recovering proved undeveloped reserves.

*Proved undeveloped reserves* or*PUDs.* Reserves that are expected to berecovered from new wells on undrilled acreage or from existing wells where arelatively major expenditure is required for recompletion.  Reserves on undrilled acreage are limited to thosedrilling units offsetting productive units that are reasonably certain ofproduction when drilled. Proved reserves for other undrilled units are claimedonly where it can be demonstrated with certainty that there is continuity ofproduction from the existing productive formation.  Estimates for proved undeveloped reserves arenot attributed to any acreage for which an application of fluid injection orother improved recovery technique is contemplated, unless such techniques havebeen proved effective by actual tests in the area and in the same reservoir.

*Recompletion.* The completion forproduction of an existing wellbore in another formation from that which thewell has been previously completed.

*Reservoir.* A porous and permeableunderground formation containing a natural accumulation of produceable oiland/or gas that is confined by impermeable rock or water barriers and isindividual and separate from other reserves.

*Standardized Measure.* StandardizedMeasure is the present value of estimated future net revenues to be generatedfrom the production of proved reserves, determined in accordance with the rulesand regulations of the Securities and Exchange Commission (using prices andcosts in effect as of the date of estimation) without giving effect tonon-property related expenses such as general and administrative expenses, debtservice and future income tax expenses or to depreciation, depletion andamortization and discounted using an annual discount rate of 10%.  Our Standardized Measure does not includefuture income tax expenses because our reserves are owned by our subsidiaryLinn Energy Holdings, LLC, which is not subject to income taxes.

*Successful well.* A well capable ofproducing oil and/or gas in commercial quantities.

*Undeveloped acreage.* Lease acreageon which wells have not been drilled or completed to a point that would permitthe production of commercial quantities of oil and gas regardless of whethersuch acreage contains proved reserves.

*Unproved reserves.* Lease acreage onwhich wells have not been drilled and where it is either probable or possiblethat the acreage contains reserves.

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

*Workover.* Operations on a producingwell to restore or increase production.

4

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**Part I –FINANCIAL INFORMATION**

**Item 1.        FinancialStatements**

**LINN ENERGY, LLC**

**CONDENSED CONSOLIDATED BALANCE SHEETS**
| ** **                                                                                                   | ** ** | **September 30,**  | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                                                   | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                                                                                   | ** ** | **(Unaudited)**         | ** ** | ** **            | ** ** |
| ** **                                                                                                   | ** ** | **(in thousands)** | ** ** |
| **Assets**                                                                                                   |       |                    |       |                  |       |
| **Current assets:**                                                                                          |       |                    |       |                  |       |
| Cash and cash  equivalents                                                                                   |       | $                       | 1,762      |                  | $          | 11,041 |   |
| Receivables:                                                                                                 |       |                    |       |                  |       |
| Oil and gas, net  of allowance for doubtful accounts of $100 as of September 30, 2006 and  December 31, 2005 |       | 20,609                  |       | 17,103                |       |
| Other                                                                                                        |       | 233                     |       | 650                   |       |
| Fair value of  interest rate swaps                                                                           |       | 132                     |       | 202                   |       |
| Inventory                                                                                                    |       | 560                     |       | 68                    |       |
| Current portion  of oil and gas derivatives                                                                  |       | 30,404                  |       | 1,601                 |       |
| Other current  assets                                                                                        |       | 1,161                   |       | 4,068                 |       |
| Total current  assets                                                                                        |       | 54,861                  |       | 34,733                |       |
|                                                                                                         |       |                    |       |                  |       |
| Oil and gas  properties and related equipment (successful efforts method)                                    |       | 754,935                 |       | 250,000               |       |
| Less accumulated  depreciation, depletion, and amortization                                                  |       | 23,589                  |       | 10,707                |       |
|                                                                                                         |       | 731,346                 |       | 239,293               |       |
|                                                                                                         |       |                    |       |                  |       |
| Property and  equipment, net                                                                                 |       | 11,297                  |       | 2,525                 |       |
|                                                                                                         |       |                    |       |                  |       |
| **Other assets:**                                                                                            |       |                    |       |                  |       |
| Long-term  portion of oil and gas derivatives                                                                |       | 43,398                  |       | 2,795                 |       |
| Deferred tax  assets, net                                                                                    |       | 307                     |       | —                |       |
| Operating bonds                                                                                              |       | 198                     |       | 198                   |       |
| Intangible  assets                                                                                           |       | 2,208                   |       | —                |       |
|                                                                                                         |       | 46,111                  |       | 2,993                 |       |
| Total assets                                                                                                 |       | $                       | 843,615    |                  | $          | 279,544 |   |

 

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

5

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| ** **                                                     | ** ** | **September 30,**  | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                     | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                                     | ** ** | **(Unaudited)**         | ** ** | ** **            | ** ** |
| ** **                                                     | ** ** | **(in thousands)** | ** ** |
| **Liabilities and Unitholders’ Capital (Deficit)**        |       |                    |       |                  |       |
| **Current  liabilities:**                                      |       |                    |       |                  |       |
| Current portion of long-term notes payable                     |       | $                       | 675        |                  | $          | 113 |   |
| Subordinated term loan                                         |       | —                  |       | 59,501                |       |
| Accounts payable and accrued expenses                          |       | 6,325                   |       | 5,572                 |       |
| Current portion of oil and gas derivatives                     |       | 573                     |       | 12,094                |       |
| Revenue distribution                                           |       | 981                     |       | 6,082                 |       |
| Accrued interest payable                                       |       | 3,732                   |       | 1,448                 |       |
| Gas purchases payable                                          |       | 923                     |       | 1,208                 |       |
| Other current liabilities                                      |       | 40                      |       | 40                    |       |
| Total current liabilities                                      |       | 13,249                  |       | 86,058                |       |
|                                                           |       |                    |       |                  |       |
| **Long-term  liabilities:**                                    |       |                    |       |                  |       |
| Long-term portion of notes payable                             |       | 2,353                   |       | 695                   |       |
| Credit facility                                                |       | 404,257                 |       | 206,119               |       |
| Subordinated bridge loan                                       |       | 247,275                 |       | —                |       |
| Long-term portion of interest rate swaps                       |       | 492                     |       | 663                   |       |
| Asset retirement obligation                                    |       | 8,434                   |       | 5,443                 |       |
| Long-term portion of oil and gas derivatives                   |       | 10,273                  |       | 27,139                |       |
| Other long-term liabilities                                    |       | 474                     |       | 258                   |       |
| Total long-term liabilities                                    |       | 673,558                 |       | 240,317               |       |
| Total liabilities                                              |       | 686,807                 |       | 326,375               |       |
|                                                           |       |                    |       |                  |       |
| **Unitholders’  capital (deficit):**                      |       |                    |       |                  |       |
| 27,882,500 units issued and outstanding at September  30, 2006 |       | 134,390                 |       | 16,024                |       |
| Accumulated income (loss)                                      |       | 22,418                  |       | (62,855               | )          |
|                                                           |       | 156,808                 |       | (46,831               | )          |
| Total  liabilities and unitholders’ capital (deficit)     |       | $                       | 843,615    |                  | $          | 279,544 |   |

 

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

6

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF OPERATIONS**

**(Unaudited)**
| ** **                                             | ** ** | **Three months ended  September 30,**                 | ** ** | **Nine months ended  September 30,** | ** ** |
|--------------------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                             | ** ** | **2006**                                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                             | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                          |       |                                                                 |       |                                                |       |   |   |   |   |
| Oil and gas sales                                      |       | $                                                                    | 23,506     |                                                | $          | 10,407 |   | $ | 53,410 |   | $ | 24,408 |   |
| Realized gain (loss) on oil and gas derivatives        |       | 8,198                                                                |       | (29,058                                             | )          | 17,361 |   | (45,822 | ) |
| Unrealized gain (loss) on oil and gas derivatives      |       | 49,198                                                               |       | (21,405                                             | )          | 77,176 |   | (26,788 | ) |
| Natural gas marketing income                           |       | 1,090                                                                |       | 1,618                                               |       | 3,654 |   | 3,087 |   |
| Other income                                           |       | 265                                                                  |       | 20                                                  |       | 758 |   | 158 |   |
|                                                   |       | 82,257                                                               |       | (38,418                                             | )          | 152,359 |   | (44,957 | ) |
| **Expenses:**                                          |       |                                                                 |       |                                                |       |   |   |   |   |
| Operating expenses                                     |       | 4,845                                                                |       | 1,386                                               |       | 10,772 |   | 4,691 |   |
| Natural gas marketing expense                          |       | 954                                                                  |       | 1,768                                               |       | 3,126 |   | 3,162 |   |
| General and administrative expenses                    |       | 6,536                                                                |       | 1,197                                               |       | 22,934 |   | 2,345 |   |
| Depreciation, depletion and amortization               |       | 5,654                                                                |       | 1,448                                               |       | 13,470 |   | 4,035 |   |
|                                                   |       | 17,989                                                               |       | 5,799                                               |       | 50,302 |   | 14,233 |   |
|                                                   |       | 64,268                                                               |       | (44,217                                             | )          | 102,057 |   | (59,190 | ) |
| **Other  income and (expenses):**                      |       |                                                                 |       |                                                |       |   |   |   |   |
| Interest income                                        |       | 107                                                                  |       | 13                                                  |       | 345 |   | 16 |   |
| Interest and financing expenses                        |       | (11,204                                                              | )          | (998                                                | )          | (16,539 | ) | (3,282 | ) |
| Write-off of deferred financing fees and other  losses |       | (114                                                                 | )          | (3                                                  | )          | (664 | ) | (424 | ) |
|                                                   |       | (11,211                                                              | )          | (988                                                | )          | (16,858 | ) | (3,690 | ) |
| Income (loss) before  income taxes                     |       | 53,057                                                               |       | (45,205                                             | )          | 85,199 |   | (62,880 | ) |
| Income tax benefit (provision)                         |       | —                                                               |       | (385                                                | )          | 74 |   | (385 | ) |
| Net income (loss)                                      |       | $                                                                    | 53,057     |                                                | $          | (45,590 | ) | $ | 85,273 |   | $ | (63,265 | ) |
|                                                   |       |                                                                 |       |                                                |       |   |   |   |   |
| Net income  (loss) per unit - basic                    |       | $                                                                    | 1.92       |                                                | $          | (2.22 | ) | $ | 3.14 |   | $ | (3.08 | ) |
| Net income  (loss) per unit - diluted                  |       | $                                                                    | 1.89       |                                                | $          | (2.22 | ) | $ | 3.12 |   | $ | (3.08 | ) |
| Weighted average  units outstanding - basic            |       | 27,584                                                               |       | 20,518                                              |       | 27,118 |   | 20,518 |   |
| Weighted average  units outstanding - diluted          |       | 28,044                                                               |       | 20,518                                              |       | 27,341 |   | 20,518 |   |
|                                                   |       |                                                                 |       |                                                |       |   |   |   |   |
| Distributions declared  per unit                       |       | $                                                                    | 0.40       |                                                | $          | — |   | $ | 0.72 |   | $ | — |   |

 

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

7

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**LINN ENERGY, LLC**

**CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’CAPITAL (DEFICIT)**

**(Unaudited)**
| ** **                                        | ** ** | **Unitholders’  Capital** | ** ** | **Accumulated  Income (Loss)** | ** ** | **Treasury  Units  (at Cost)** | ** ** | **Total  Unitholders’  Capital  (Deficit)** | ** ** |
|---------------------------------------------------|------------|--------------------------------|------------|-------------------------------------|------------|-------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                        | ** ** | **(in thousands)**        | ** ** |
| ** **                                        | ** ** | ** **                     | ** ** | ** **                          | ** ** | ** **                          | ** ** | ** **                                       | ** ** |
| **Balance  as of December 31, 2005**         |       | $                              | 16,024     |                                | $          | (62,855                             | )          | $                                                | —     |   | $ | (46,831 | ) |
| Sale of units,  net of offering expense of $4,339 |       | 225,139                        |       | —                              |       | 13,671                              |       | 238,810                                          |       |
| Redemption of  member units                       |       | —                         |       | —                              |       | (114,449                            | )          | (114,449                                         | )          |
| Cancellation of  member units                     |       | (100,778                       | )          | —                              |       | 100,778                             |       | —                                           |       |
| Distribution to  members                          |       | (19,859                        | )          | —                              |       | —                              |       | (19,859                                          | )          |
| Unit-based  compensation expense                  |       | 13,864                         |       | —                              |       | —                              |       | 13,864                                           |       |
| Net income                                        |       | —                         |       | 85,273                              |       | —                              |       | 85,273                                           |       |
| **Balance as of September 30,  2006**             |       | $                              | 134,390    |                                | $          | 22,418                              |       | $                                                | —     |   | $ | 156,808 |   |

 

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

8

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**LINNENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS**

**(Unaudited)**
| ** **                                                                                              | ** ** | **Nine months ended  September 30,** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                                              | ** ** | **2006**                                            | ** ** | **2005** | ** ** |
| ** **                                                                                              | ** ** | **(in thousands)**                             | ** ** |
| **Cash  flow from operating activities:**                                                               |       |                                                |       |   |   |
| Net income (loss)                                                                                       |       | $                                                   | 85,273     |   | $ | (63,265 | ) |
| **Adjustments to reconcile net income (loss) to  net cash provided by (used in) operating activities:** |       |                                                |       |   |   |
| Depreciation, depletion and amortization                                                                |       | 13,470                                              |       | 4,035 |   |
| Amortization and write-off of deferred financing  fees and other losses                                 |       | 1,650                                               |       | 573 |   |
| Accretion of asset retirement obligation                                                                |       | 180                                                 |       | 124 |   |
| Unrealized (gain) loss on oil and gas and interest  rate derivatives                                    |       | (77,276                                             | )          | 26,013 |   |
| Unit-based compensation                                                                                 |       | 13,864                                              |       | — |   |
| Deferred income tax                                                                                     |       | (307                                                | )          | — |   |
| **Changes in assets and liabilities, net of  effects of acquisitions:**                                 | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| Increase in accounts receivable                                                                         |       | (3,089                                              | )          | (3,110 | ) |
| (Increase) decrease in inventory and other assets                                                       |       | 3,542                                               |       | (71 | ) |
| Increase (decrease) in accounts payable and accrued  expenses                                           |       | (5,821                                              | )          | 127 |   |
| Increase (decrease) in oil and gas and interest rate  derivatives                                       |       | (20,616                                             | )          | 402 |   |
| (Decrease) in revenue distribution                                                                      |       | (5,101                                              | )          | (692 | ) |
| Increase in accrued interest payable                                                                    |       | 2,284                                               |       | 288 |   |
| Increase (decrease) in gas purchases payable                                                            |       | (285                                                | )          | 623 |   |
| Increase in other liabilities                                                                           |       | 216                                                 |       | 572 |   |
| Net cash provided by (used in) operating activities                                                     |       | 7,984                                               |       | (34,381 | ) |
| ** **                                                                                              | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| **Cash  flow from investing activities:**                                                               |       |                                                |       |   |   |
| Acquisition and development of oil and gas  properties                                                  |       | (502,847                                            | )          | (27,540 | ) |
| Purchases of property and equipment                                                                     |       | (6,259                                              | )          | (874 | ) |
| Other investing activities                                                                              |       | 21                                                  |       | (30 | ) |
| Net cash (used in) investing activities                                                                 |       | (509,085                                            | )          | (28,444 | ) |
| ** **                                                                                              | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| **Cash  flow from financing activities:**                                                               |       |                                                |       |   |   |
| Proceeds from sale of units                                                                             |       | 243,149                                             |       | — |   |
| Redemption of member units                                                                              |       | (114,449                                            | )          | — |   |
| Proceeds from notes payable                                                                             |       | —                                              |       | 5,262 |   |
| Principal payments on notes payable                                                                     |       | (597                                                | )          | (5,058 | ) |
| Proceeds from credit facility                                                                           |       | 261,303                                             |       | 142,000 |   |
| Principal payments on credit facility                                                                   |       | (62,000                                             | )          | (75,605 | ) |
| Proceeds from subordinated bridge loan                                                                  |       | 250,000                                             |       | — |   |
| Principal payments on subordinated term loan                                                            |       | (60,000                                             | )          | — |   |
| Distribution to members                                                                                 |       | (19,859                                             | )          | — |   |
| Deferred offering costs                                                                                 |       | (844                                                | )          | (2,145 | ) |
| Deferred financing fees                                                                                 |       | (4,881                                              | )          | (840 | ) |
| Net cash provided by financing activities                                                               |       | 491,822                                             |       | 63,614 |   |
| Net increase (decrease) in cash                                                                         |       | (9,279                                              | )          | 789 |   |
| ** **                                                                                              | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| **Cash  and cash equivalents:**                                                                         |       |                                                |       |   |   |
| Beginning                                                                                               |       | 11,041                                              |       | 2,188 |   |
| Ending                                                                                                  |       | $                                                   | 1,762      |   | $ | 2,977 |   |

 

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

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###### **LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS - Continued**

**(Unaudited)**
| ** **                                                                                                        | ** ** | **Nine months ended  September 30,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                                                        | ** ** | **2006**                                            | ** ** | **2005** | ** ** |
| ** **                                                                                                        | ** ** | **(in thousands)**                             | ** ** |
| **Supplemental  disclosure of cash flow information:**                                                            |       |                                                |       |   |   |
| Cash payments for interest                                                                                        |       | $                                                   | 13,603     |   | $ | 3,596 |   |
| ** **                                                                                                        | ** ** | ** **                                          | ** ** | ** ** | ** ** |
| **Supplemental  disclosure of non cash investing and financing activities:**                                      |       |                                                |       |   |   |
| Increase in oil and gas properties and related asset  retirement obligation due to acquisitions and new drilling  |       | $                                                   | 2,652      |   | $ | 417 |   |
| Acquisition of vehicles and equipment through  issuance of notes payable                                          |       | $                                                   | 2,648      |   | $ | 294 |   |
|                                                                                                              |       |                                                |       |   |   |
| In connection with the purchase of Blacksand and the  Kaiser-Francis Assets, liabilities were assumed as follows: |       |                                                |       |   |   |
| Fair value of assets acquired                                                                                     |       | $                                                   | 426,957    |   |   |   |
| Cash paid                                                                                                         |       | (424,236                                            | )          |   |   |
| Liabilities  assumed                                                                                              |       | $                                                   | 2,721      |   |   |   |

 

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

10

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**LINN ENERGY, LLCNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Unaudited)**

**(1) Basis of Presentation**

The condensedconsolidated financial statements at September 30, 2006, and for the three andnine months ended September 30, 2006 and 2005, are unaudited, but in theopinion of management include all adjustments (consisting only of normalrecurring adjustments) necessary for a fair presentation of the results for theinterim periods.  Certain information andnote disclosures normally included in annual financial statements prepared inaccordance with U.S. generally accepted accounting principles (“GAAP”) havebeen condensed or omitted under Securities 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 our Annual Report on Form 10-K for the year ended December 31,2005.  Certain amounts in theconsolidated financial statements and notes thereto have been reclassified toconform to the 2006 financial statement presentation.

**(2) Summary of Significant Accounting Policies**

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

Linn Energy, LLC (“Linn”or “the Company”) was reorganized as a limited liability company in April 2005under the laws of the State of Delaware. The Company is an independent oil and gas company focused on thedevelopment and acquisition of long-lived properties in the United States.  As of September 30, 2006, Linn’s wholly ownedsubsidiaries included Linn Energy Holdings, LLC, Linn Energy Mid-ContinentHoldings, LLC, Linn Energy Western Holdings, LLC, Linn Operating, Inc., LinnWestern Processing, LLC, Penn West Pipeline, LLC, Mid Atlantic Well Service,Inc., Linn Western Operating, Inc., and Linn Mid-Continent Operating, Inc.

***(b)******                                 Principlesof Consolidation***

The consolidatedfinancial statements include the accounts of the Company and its wholly ownedsubsidiaries.  The Company presents itsfinancial statements in accordance with GAAP. All material inter-company transactions and balances have beeneliminated upon consolidation.

***(c)******                                  Cash Equivalents***

Forpurposes of the statement of cash flows, the Company considers all highlyliquid debt instruments with original maturities of three months or less to becash equivalents.

***(d)******                                 Oil and gas Properties***

TheCompany accounts for oil and gas properties by the successful effortsmethod.  Leasehold acquisition costs arecapitalized.  If proved reserves arefound on an undeveloped property, leasehold costs are transferred to proved properties.  Under this method of accounting, costsrelating to the development of proved areas are capitalized when incurred.

Depreciationand depletion of producing oil and gas properties is recorded based on units ofproduction.  Unit rates are computed forunamortized drilling and development costs using proved developed reserves andfor unamortized leasehold costs using all proved reserves.  Statement of Financial Accounting Standards (“SFAS”)No. 19, as amended, *“Financial Accounting andReporting by Oil and Gas Producing Companies,”* requires thatacquisition costs of proved properties be amortized on the basis of all provedreserves, developed and undeveloped, and that capitalized development costs(wells and related equipment and facilities) be amortized on the basis ofproved developed reserves.

TheCompany accounts for asset retirement obligations in accordance with SFAS No.143, “*Accounting for Asset Retirement Obligations”*(“SFAS143”)*.* In accordance with SFAS 143, estimated asset retirement costs arerecognized when the obligation is incurred, and are amortized over proved developedreserves using the units of production method. Asset retirement costs are estimated by the Company’s engineers usingexisting regulatory requirements and anticipated future inflation rates.

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

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Uponsale or retirement of complete fields of depreciable or depleted property, thebook value thereof, less proceeds or salvage value, is charged or credited toincome.  On sale or retirement of anindividual well the proceeds are credited to accumulated depreciation anddepletion.

Oiland gas properties are reviewed for impairment when facts and circumstancesindicate that their carrying value may not be recoverable.  The Company assesses impairment ofcapitalized costs of proved oil and gas properties by comparing net capitalizedcosts to estimated undiscounted future net cash flows using expected prices.  If net capitalized costs exceed estimated undiscountedfuture net cash flows, the measurement of impairment is based on estimated fairvalue, which would consider estimated future discounted cash flows.  No impairments were recorded during the threeor nine months ended September 30, 2006 or 2005.

Unprovedproperties that are individually insignificant are amortized.  Unproved properties that are individuallysignificant are assessed for impairment on a property-by-property basis.  If considered impaired, costs are charged toexpense when such impairment is deemed to have occurred.  No impairments were recorded during the threeor nine months ended September 30, 2006 or 2005.

***(e)******                                  Oil and Gas Reserve Quantities***

TheCompany’s estimates of proved reserves are based on the quantities of oil andgas that engineering and geological analyses demonstrate, with reasonablecertainty, to be recoverable from established reservoirs in the future undercurrent operating and economic parameters. An independent engineering firm prepares a reserve and economic evaluationof all the Company’s properties on a well-by-well basis.

Reservesand their relation to estimated future net cash flows impact the Company’sdepletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrentlywith changes to reserve estimates.  TheCompany prepares its reserve estimates, and the projected cash flows derivedfrom these reserve estimates, in accordance with SEC guidelines.  The independent engineering firm noted aboveadheres to the same guidelines when preparing its reserve reports.  The accuracy of the Company’s reserveestimates is a function of many factors including the following: the qualityand quantity of available data, the interpretation of that data, the accuracyof various mandated economic assumptions, and the judgments of the individualspreparing the estimates.

TheCompany’s proved reserve estimates are a function of many assumptions, all ofwhich could deviate significantly from actual results.  As such, reserve estimates may materiallyvary from the ultimate quantities of natural gas, natural gas liquids and crudeoil eventually recovered.

***(f)******                                    Income Taxes***

TheCompany is a limited liability company treated as a partnership for federal andstate income tax purposes with all income tax liabilities and/or benefits ofthe Company being passed through to the unitholders.  As such, no recognition of federal or stateincome taxes for the Company or its subsidiaries that are organized as limitedliability companies have been provided for in the accompanying financialstatements except as described below.

Certainof the Company’s subsidiaries are Subchapter C-corporations subject tocorporate income taxes, which are accounted for under the asset andliability method.  Deferred tax assets andliabilities are recognized for the future tax consequences attributable todifferences between the financial statement carrying amounts of existing assetsand liabilities and their respective tax basis and operating loss and taxcredit carryforwards.  Deferred taxassets and liabilities are measured using enacted tax rates expected to applyto taxable income in the years in which those temporary differences areexpected to be recovered or settled.  Theeffect on deferred tax assets and liabilities of a change in tax rates isrecognized in income in the period that includes the enactment date.  Deferredtax liabilities of approximately $0.3 million and $74,000 are recorded in otherlong-term liabilities on the consolidated balance sheets at September 30, 2006and December 31, 2005, respectively.  AtSeptember 30, 2006, deferred tax assets of approximately $0.3 million,net of a valuation allowance of $1.8 million, are recorded to the extent ofexisting deferred tax liabilities.

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

TheCompany periodically uses derivative financial instruments to achieve a morepredictable cash flow from its crude oil and natural gas production by reducingits exposure to price fluctuations.  Asof September 30, 2006, these transactions were in the form of swaps andputs.  Additionally, the Company usesderivative financial instruments in 

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theform of interest rate swaps to mitigate its interest rate exposure.  The Company accounts for its derivatives atfair value as an asset or liability and the change in the fair value ofderivatives is included in income.

***(h)******                                 Intangible Assets***

Underthe provisions of SFAS No. 142, *“Goodwilland Other Intangible Assets”* (“SFAS 142”), the Company amortizes theintangible asset acquired as part of the purchase of Blacksand (see Note 3)over the period in which the asset is expected to contribute to future cashflows, which is consistent with the life of the underlying oil and gasreserves.  The amortized intangible assetis evaluated for impairment in accordance with SFAS No. 144 “*Accounting for the Impairment or Disposal ofLong-Lived Assets*” when events and circumstances indicate that theasset might be impaired.

***(i)******                                    EarningsPer Unit***

Basic earnings per unitis computed by dividing net earnings attributable to unitholders by theweighted average number of units outstanding during each period.  During 2006, for the period prior to itsinitial public offering (“IPO”), equivalent units were calculated by adjustingpre-IPO members’ membership interests by the exchange ratio to reflect theexchange of pre-IPO membership interests for post-IPO units and cashimmediately prior to completion of the IPO (see Note 4).  Diluted earnings per unit is computed byadjusting the average number of units outstanding for the dilutive effect, ifany, of unit equivalents.  The Companyuses the treasury stock method to determine the dilutive effect.

In accordance with SFASNo. 128, “*Earnings per Share,”*dual presentation of basic and diluted earnings per share has been presented inthe Condensed Consolidated Statements of Earnings.  The following reconciliation illustrates theimpact on the share amounts of potential common shares and the earnings pershare amounts:
|                                         | ** ** | **Three months ended  September 30,**                 | ** ** | **Nine months ended  September 30,** | ** ** |
|-----------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                              | ** ** | **2006**                                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                              | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **Basic:**                              |       |                                                                 |       |                                                |       |   |   |   |   |
| Net income (loss)                       |       | $                                                                    | 53,057     |                                                | $          | (45,590 | ) | $ | 85,273 |   | $ | (63,265 | ) |
|                                    |       |                                                                 |       |                                                |       |   |   |   |   |
| Average number of units outstanding     |       | 27,584                                                               |       | 20,518                                              |       | 27,118 |   | 20,518 |   |
|                                    |       |                                                                 |       |                                                |       |   |   |   |   |
| Net income (loss) per unit (basic)      |       | $                                                                    | 1.92       |                                                | $          | (2.22 | ) | $ | 3.14 |   | $ | (3.08 | ) |
|                                    |       |                                                                 |       |                                                |       |   |   |   |   |
| **Diluted:**                            |       |                                                                 |       |                                                |       |   |   |   |   |
| Net income (loss)                       |       | $                                                                    | 53,057     |                                                | $          | (45,590 | ) | $ | 85,273 |   | $ | (63,265 | ) |
|                                    |       |                                                                 |       |                                                |       |   |   |   |   |
| Average number of units outstanding     |       | 27,584                                                               |       | 20,518                                              |       | 27,118 |   | 20,518 |   |
| Dilutive effect of unit equivalents (a) |       | 460                                                                  |       | —                                              |       | 223 |   | — |   |
| Equivalent units outstanding            |       | 28,044                                                               |       | 20,518                                              |       | 27,341 |   | 20,518 |   |
|                                    |       |                                                                 |       |                                                |       |   |   |   |   |
| Net income  (loss) per unit (diluted)   |       | $                                                                    | 1.89       |                                                | $          | (2.22 | ) | $ | 3.12 |   | $ | (3.08 | ) |

 

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(a)          Excludes the effect of averageanti-dilutive common stock equivalents related to out-of-the-money options of16,055 and 61,313 for the three and nine months ended September 30, 2006,respectively. 

 

***(j)******                                    Use of Estimates***

Managementof the Company has made a number of estimates and assumptions relating to thereporting of assets and liabilities and revenues and expenses and thedisclosure of contingent assets and liabilities to prepare these condensedconsolidated financial statements in conformity with GAAP.  Actual results could differ from thoseestimates.  The estimates that areparticularly significant to the financial statements include estimates of oiland gas reserves, future cash flows from oil and gas properties, depreciation,depletion and amortization, asset retirement obligations, the fair value ofderivatives and unit awards.

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***(k)******                                 Revenue Recognition***

Salesof oil and gas are recognized when oil or gas has been delivered to a custodytransfer point, persuasive evidence of a sales arrangement exists, the rightsand responsibility of ownership pass to the purchaser upon delivery, collectionof revenue from the sale is reasonably assured, and the sales price is fixed ordeterminable.  Oil and gas is sold by theCompany on a monthly basis.  Virtuallyall of the Company’s contracts’ pricing provisions are tied to a market index,with certain adjustments based on, among other factors, whether a well deliversto a gathering or transmission line, quality of crude oil and natural gas, andprevailing supply and demand conditions, so that the price of the crude oil andnatural gas fluctuate to remain competitive with other available oil and gassupplies.  As a result, the Company’srevenues from the sale of oil and gas will suffer if market prices decline andbenefit if they increase.  The Companybelieves that the pricing provisions of its oil and gas contracts are customaryin the industry.

Gasimbalances occur when the Company sells more or less than its entitledownership percentage of total gas production. Any amount received in excess of the Company’s share is treated as aliability.  If the Company receives lessthan its entitled share, the underproduction is recorded as a receivable.  The Company did not have any significant gasimbalance positions at September 30, 2006 or December 31, 2005.

Naturalgas marketing is recorded on the gross accounting method because PennWest Pipeline, LLC, the Company’s marketingsubsidiary, takes title to the natural gas it purchases from the variousproducers and bears the risks and enjoys the benefits of that ownership.  Natural gas marketing revenues and naturalgas marketing expense, titled as such, are reported on the consolidatedstatement of operations for the three and nine months ended September 30, 2006and 2005.

TheCompany currently uses the “Net-Back” method of accounting for transportationarrangements of its natural gas sales. The Company sells natural gas at the wellhead and collects a price andrecognizes revenues based on the wellhead sales price since transportationcosts downstream of the wellhead are incurred by its customers and reflected inthe wellhead price.

TheCompany generates electricity with excess gas, which it uses to serve certainof its operating facilities in California. Any excess electricity is sold to the wholesale power market and therevenue is recorded on the accrual basis. This revenue is included in “other income” on the condensed consolidatedstatement of operations.

TheCompany is paid a monthly operating fee for each well it operates for outsideowners.  The fee covers monthly operatingand accounting costs, insurance, and other recurring costs.  As the operating fee is a reimbursement forcosts incurred on behalf of third parties, the portion of the fee that exceedsthe reimbursement of operating costs has been netted against general andadministrative expense.  For the threeand nine months ended September 30, 2006, the operating fees netted againstgeneral and administrative expense were approximately $0.2 million and $0.9million, respectively.  For the three andnine months ended September 30, 2005, the operating fees netted against generaland administrative expense were approximately $0.3 million and $0.8 million,respectively.

***(l)******                                    Unit-Based Compensation***

See Note 9 for adiscussion of the accounting for unit-based compensation expense.

***(m)******                              Recently Issued Accounting Standards***

As of January 1, 2006,the Company adopted SFAS No. 154, “*Accounting Changes andError Corrections, a replacement of APB Opinion No. 20 and SFAS No. 3*”(“SFAS 154”).  SFAS 154 requiresretrospective application of voluntary changes in accounting principles, unlessit is impracticable.  The implementationof this standard did not have a material impact on the Company’s results ofoperations and financial condition.

In February 2006, theFinancial Accounting Standards Board (“FASB”) issued SFAS No. 155, *“Accounting for Certain Hybrid Instruments, (an Amendment of FASBStatements No. 133 and140)”* (“SFAS 155”).  The standard allows financial instrumentsthat have embedded derivatives to be accounted for as a whole, eliminating theneed to bifurcate the derivative from its host, if the holder elects to accountfor the whole instrument on a fair value basis. SFAS 155 also establishes a requirement to evaluate interests insecuritized financial assets to identify interests that are freestandingderivatives or that are hybrid financial instruments that contain an embeddedderivative requiring bifurcation.  Thestandard is effective for all financial instruments acquired or issued afterthe beginning of an entity’s first fiscal year that begins after September 15,2006.  The Company is currentlyevaluating the effect that 

14

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the implementation ofSFAS 155 will have on its results of operations and financial condition, butdoes not expect it will have a material impact.

In June 2006, the FASBissued Financial Interpretation No. 48, *“Accounting forUncertainty in Income Taxes - an interpretation of FASB Statement No. 109”*(“FIN 48”).  The interpretation setsforth a consistent recognition threshold and measurement attribute, andcriteria for subsequently recognizing, derecognizing and measuring uncertaintax positions for financial statement purposes. FIN 48 also requires expanded disclosure with respect to the uncertaintyin income taxes.  The interpretation iseffective for fiscal years beginning after December 31, 2006.  The Company is currently evaluating theeffect that the adoption of FIN 48 will have on its results of operations andfinancial condition, but does not expect it will have a material impact.

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

In September 2006, theFASB issued Staff Position No. AUG AIR-1, *“Accountingfor Planned Major Maintenance Activities,”*which prohibits companiesfrom accruing as a liability in annual and interim periods the future costs ofperiodic major overhauls and maintenance of plant and equipment (the “accrue-in-advancemethod”).  Other previously acceptablemethods of accounting for planned major overhauls and maintenance (the directexpense, built-in overhaul and deferral methods) will continue to bepermitted.  The new requirements apply toentities in all industries for fiscal years beginning after December 15, 2006,and must be retrospectively applied.  Wedo not expect that adoption of this FASB Staff Position will have a materialimpact on our results of operations or financial position.

In September 2006, theSEC issued Staff Accounting Bulletin No. 108 (“SAB 108”).  SAB 108 expresses the SEC staff’s viewsregarding the process of quantifying financial statement misstatements.  The SEC staff believes registrants shouldquantify errors using both a balance sheet and an income statement approach andevaluate whether either approach results in quantifying a misstatement that,when all relevant quantitative and qualitative factors are considered, ismaterial.  The SEC staff will not objectif a registrant records a one-time cumulative effect adjustment to correcterrors existing in prior years that previously had been considered immaterial,quantitatively and qualitatively, based on appropriate use of the registrant’sapproach.  SAB 108 describes thecircumstances where this would be appropriate as well as required disclosuresto investors.  SAB 108 is effective forfiscal years ending on or after November 15, 2006.  We are currently assessing the impact ofadoption of SAB 108 on our financial statements but do not expect that adoptionwill have a material effect on our results of operations or financial position.

**(3) Acquisitions**

Inthe second quarter of 2006, the Company purchased from the owners of propertyoperated by Devonian Gas Production, Inc., Excel Energy, Inc. and T&FExploration LP, a total of 200 producing wells and tangible wellhead equipmentin West Virginia, for an aggregate purchase price of approximately $27.5million.  Also in the second quarter of2006, the Company purchased a natural gas gathering pipeline system inwestern Pennsylvania for approximately $0.8 million.

In the third quarter of2006, the Company acquired certain affiliated entities of Blacksand Energy, LLC(“Blacksand”), located in the Los Angeles Basin, for an aggregate purchaseprice, including estimated transaction costs and assumed liabilities, ofapproximately $300.7 million and certain Mid-Continent assets of Kaiser-FrancisOil Company (“Kaiser-Francis Assets”) located in Oklahoma for an aggregatepurchase price, including estimated transaction costs and assumed liabilities,of approximately $126.3 million, in both cases subject to customarypost-closing adjustments.

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

Theacquisitions of the Kaiser-Francis Assets and Blacksand were financed with acombination of borrowings under our secured revolving credit facility and a$250.0 million subordinated bridge loan. In connection with the acquisitions, we entered into a new agreementthat increased the credit facility from $400.0 million to $800.0 million andincreased the borrowing base from $265.0 million to $480.0 million (see Note6).

The following table presentsthe preliminary purchase prices as of the respective acquisition dates:
|                                        | ** ** | **Blacksand**           | ** ** | **Kaiser Francis  Assets** | ** ** | **Total** | ** ** |
|----------------------------------------|------------|-------------------------|------------|---------------------------------|------------|-----------|------------|
| ** **                             | ** ** | **(in thousands)** | ** ** |
| Cash                                   |       | $                       | 298,113    |                            | $          | 125,000   |       | $ | 423,113 |   |
| Estimated  transaction costs           |       | 221                     |       | 902                             |       | 1,123     |       |
| Total  preliminary purchase price      |       | 298,334                 |       | 125,902                         |       | 424,236   |       |
| Liabilities  assumed                   |       | 2,373                   |       | 348                             |       | 2,721     |       |
| Total purchase price  plus liabilities |       | $                       | 300,707    |                            | $          | 126,250   |       | $ | 426,957 |   |

 

The assumed liabilitiesinclude asset retirement obligations of approximately $2.3 million forBlacksand and $0.3 million for the Kaiser-Francis Assets.

The following tablepresents, as of the respective acquisition dates, preliminary allocations ofthe purchase prices based on preliminary estimates of fair value:
|                         | ** ** | **Blacksand**           | ** ** | **Kaiser-Francis  Assets** | ** ** | **Total** | ** ** |
|-------------------------|------------|-------------------------|------------|----------------------------|------------|-----------|------------|
| ** **              | ** ** | **(in thousands)** | ** ** |
| Field inventory         |       | $                       | 284        |                       | $          | —    |       | $ | 284 |   |
| Oil and gas  properties |       | 297,659                 |       | 126,250                    |       | 423,909   |       |
| Vehicles and  buildings |       | 556                     |       | —                     |       | 556       |       |
| Intangible asset        |       | 2,208                   |       | —                     |       | 2,208     |       |
|                    |       | $                       | 300,707    |                       | $          | 126,250   |       | $ | 426,957 |   |

 

The preliminary purchaseprice allocations are based on preliminary independent appraisals, discountedcash flows, quoted market prices and estimates by management.  The purchase price allocations will becompleted within one year of the acquisition dates.

As part of the overallvaluation of Blacksand, Linn has preliminarily determined that it acquired anintangible asset associated with a contract purchased as part of theacquisition.  The contract is with a realestate developer under which the developer is obligated to make certainimprovements in the acquired property. The intangible asset acquired is anticipated to have a life consistentwith the underlying oil and gas reserves, and therefore, will be amortized on astraight-line basis over the life of the oil and gas reserves, in accordancewith the provisions of SFAS No. 142*.*

The following unaudited pro formafinancial information presents a summary of Linn’s consolidated results ofoperations for the three and nine months ended September 30, 2006 and 2005,assuming the acquisitions of Blacksand and the Kaiser-Francis Assets had beencompleted as of January 1, 2005, including adjustments, which are based uponpreliminary estimates, to reflect the allocation of the purchase prices to theacquired net assets.  The pro formafinancial information is not necessarily indicative of the results ofoperations if the acquisitions had been effective as of these dates.

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|                              | ** ** | **For the Three Months Ended  September 30,** | ** ** | **For the Nine Months Ended  September 30,** | ** ** |
|------------------------------|------------|------------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                   | ** ** | **2006**                                                               | ** ** | **2005**                                                              | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                   | ** ** | **(in thousands)**                                                | ** ** |
| Oil and gas  sales           |       | $                                                                      | 29,405     |                                                                  | $          | 26,428 |   | $ | 84,231 |   | $ | 55,317 |   |
| Total revenues               |       | 88,319                                                                 |       | (21,845                                                               | )          | 216,987 |   | (12,166 | ) |
| Total operating  expenses    |       | 22,079                                                                 |       | 13,111                                                                |       | 69,189 |   | 34,002 |   |
| Net income (loss)            |       | 52,063                                                                 |       | (46,099                                                               | )          | 110,252 |   | (79,553 | ) |
| Net income  (loss) per unit: |       |                                                                   |       |                                                                  |       |   |   |   |   |
| Basic                        |       | $                                                                      | 1.89       |                                                                  | $          | (2.25 | ) | $ | 4.07 |   | $ | (3.88 | ) |
| Diluted                      |       | $                                                                      | 1.86       |                                                                  | $          | (2.25 | ) | $ | 4.03 |   | $ | (3.88 | ) |

 

The pro forma results ofoperations for the nine months ended September 30, 2006 includes a Blacksandhistorical gain on property sale of $32.7 million.  Under SEC Regulation S-X, this gain may notbe excluded from the condensed combined pro forma financial statements.  Had this gain been excluded, pro forma netincome for the nine months ended September 30, 2006 would have been reduced bythe gain recorded.

**(4) Initial Public Offering**

Inthe first quarter of 2006, the Company completed its IPO of 12,450,000 unitsrepresenting limited liability interest in the Company at $21.00 per unit, fornet proceeds, after underwriting discounts of $18.3 million and offeringexpenses of $4.3 million, of $238.8 million, of which $122.0 million was usedto reduce indebtedness under the Company’s revolving credit facility and repay,in full, the subordinated term loan, $114.4 million was used to redeem aportion of the membership interests in the Company and units held by certainaffiliated and non-affiliated holders and approximately $2.0 million was usedto pay bonuses to certain executive officers of the Company.

**(5)  Oil and Gas Properties**
|                                                            | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                 | ** ** | **(in thousands)**      | ** ** |
| Unproved  properties                                       |       | $                            | 1,932      |                        | $          | — |   |
| Proved  properties:                                        |       |                         |       |                        |       |
| Leasehold, equipment and drilling                          |       | 733,161                      |       | 244,420                     |       |
| Gas and compression plant                                  |       | 12,511                       |       | —                      |       |
| Pipelines                                                  |       | 7,331                        |       | 5,580                       |       |
|                                                       |       | 754,935                      |       | 250,000                     |       |
|                                                       |       |                         |       |                        |       |
| Less accumulated  depletion, depreciation and amortization |       | (23,589                      | )          | (10,707                     | )          |
|                                                       |       |                         |       |                        |       |
|                                                       |       | $                            | 731,346    |                        | $          | 239,293 |   |

 

**(6) Debt**

***Credit Facility***

InAugust 2006, in connection with the acquisitions of Blacksand and theKaiser-Francis Assets (see Note 3), the Company entered into an $800.0 millionamended and restated senior secured revolving credit facility with a maturityof August 2010, and a borrowing base of $480.0 million (“Credit Facility”).  We also entered into a subordinated bridgeloan (see “Subordinated Bridge Loan” below).

Theterms under the incremental Credit Facility remain substantially the same asthe previous terms.  The borrowing baseunder the Credit Facility will be redetermined semi-annually by the lenders intheir sole discretion, based on, among other things, reserve reports asprepared by reserve engineers taking into account the oil and gas prices atsuch time.  Our obligations under theCredit Facility are secured by mortgages on our oil and gas properties as wellas a pledge of all ownership interests in our 

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operatingsubsidiaries.  We are required tomaintain the mortgages on properties representing at least 80% of our oil andgas properties.  Additionally, theobligations under the Credit Facility are guaranteed by all of our operatingsubsidiaries and may be guaranteed by any future subsidiaries.

Atour election, interest on the Credit Facility is determined by reference toLIBOR plus an applicable margin between 1.00% and 1.75% per annum; or adomestic bank rate plus an applicable margin between 0.00% and 0.25% perannum.  LIBOR margins increased by 0.25%during the term of the Subordinated Bridge Loan, which was repaid in October2006 (see Note 14).  Interest isgenerally payable quarterly for domestic bank rate loans and at the applicablematurity date for LIBOR loans.

The Credit Facilitycontains various covenants that limit the Company’s ability to incur additionalindebtedness, make acquisitions or certain capital expenditures; makedistributions other than from available cash; merge or consolidate; and engagein certain asset dispositions.  TheCredit Facility also contains covenants that, among other things, require us tomaintain specified financial ratios.  TheCompany is in compliance with all financial and other covenants of its CreditFacility.

As of September 30, 2006 and December 31, 2005, theCredit Facility consisted of the following:
|                                                                     | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|---------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                          | ** ** | **(in thousands)**      | ** ** |
| Outstanding  balance                                                |       | $                            | 406,000    |                        | $          | 207,000 |   |
| Less deferred  financing fees, net of amortization of $710 and $160 |       | (1,743                       | )          | (881                        | )          |
|                                                                |       |                         |       |                        |       |
|                                                                |       | $                            | 404,257    |                        | $          | 206,119 |   |

 

AtSeptember 30, 2006, the Company also had $4.0 million outstanding letters ofcredit, which reduce its borrowing availability under the Credit Facility.

Totalaccrued interest on the Credit Facility was approximately $2.0 million atSeptember 30, 2006.  Total accruedinterest on the prior credit facility was approximately $1.1 million atDecember 31, 2005.  The Company repaid $53.3 million of borrowings under its CreditFacility in October 2006 (see Note 14).

***Subordinated Bridge Loan***

InAugust 2006, in order to fund a portion of the acquisitions of Blacksand and theKaiser-Francis Assets, we entered into a $250.0 million subordinated bridgeloan (“Subordinated Bridge Loan”) with a termination of August 1, 2007.  Financial covenants under the SubordinatedBridge Loan are substantially similar to those under the Credit Facility.  At our election, interest is determined byreference to LIBOR plus an applicable margin of 4.00% per annum; or a domesticbank rate plus an applicable margin of 2.50% per annum.  Interest is generally payable quarterly fordomestic bank rate loans and at the applicable maturity date for LIBOR loans.

As of September 30, 2006, the Subordinated Bridge Loanconsisted of the following:
|                                                            | ** ** | **September 30,  2006** | ** ** |
|------------------------------------------------------------|------------|------------------------------|------------|
| ** **                                                 | ** ** | **(in thousands)**      | ** ** |
| Outstanding  balance                                       |       | $                            | 250,000    |   |
| Less deferred financing  fees, net of amortization of $545 |       | (2,725                       | )          |
|                                                       |       |                         |       |
|                                                       |       | $                            | 247,275    |   |

 

Totalaccrued interest on the Subordinated Bridge Loan was approximately $1.7 millionat September 30, 2006.

TheSubordinated Bridge Loan is classified as long-term debt at September 30, 2006,as the proceeds from the private placement of class B units in October 2006(see Note 14) were used to repay the entire amount outstanding.

18

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***SubordinatedTerm Loan***

During 2005, the Companyhad a $60.0 million second lien senior subordinated term loan.  The borrowings under the subordinated termloan were used to fund a portion of the purchase price for the acquisition ofoil and gas properties from Exploration Partners.  The outstanding balance was paid in full inJanuary 2006 with proceeds from our IPO. Total accrued interest on this loan was approximately $0.4 million atDecember 31, 2005.

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

TheCompany has the following long-term notes payable outstanding:
|                                                                                                                                                                                                                                                                                                                                                                                  | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                                                                                                                                                                                                                       | ** ** | **(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                                                                                                                                                                             |       | $                            | 378        |                        | $          | 387 |   |
| Various notes  for the purchase of vehicles and equipment, payable in monthly installments  totaling approximately $72 and $11, as of September 30, 2006 and December 31,  2005, respectively, including interest. The interest rates range from  3.9%-8.87%. The notes are secured by the vehicles and equipment purchased and  expire at various dates from 2008 through 2011. |       | 2,650                        |       | 421                         |       |
|                                                                                                                                                                                                                                                                                                                                                                             |       | 3,028                        |       | 808                         |       |
|                                                                                                                                                                                                                                                                                                                                                                             |       |                         |       |                        |       |
| Less current  portion                                                                                                                                                                                                                                                                                                                                                            |       | (675                         | )          | (113                        | )          |
|                                                                                                                                                                                                                                                                                                                                                                             |       | $                            | 2,353      |                        | $          | 695 |   |

 

As of September 30, 2006,maturities on the aforementioned long-term notes payable were as follows:
|            | ** ** | **(in thousands)** | ** ** |
|------------|------------|-------------------------|------------|
| 2006       |       | $                       | 110        |   |
| 2007       |       | 758                     |       |
| 2008       |       | 759                     |       |
| 2009       |       | 473                     |       |
| 2010       |       | 432                     |       |
| 2011       |       | 191                     |       |
| Thereafter |       | 305                     |       |
|       |       | $                       | 3,028      |   |

 

**(8) Business and Credit Concentrations**

***Cash***

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

***Revenueand Trade Receivables***

The Company has aconcentration of customers who are engaged in oil and gas production within theAppalachian region.  This concentrationof customers may impact the Company’s overall exposure to credit risk, eitherpositively or negatively, in that the customers may be similarly affected bychanges in economic or other conditions. The Company performs ongoing credit evaluations of its customers andgenerally does not require collateral.

19

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A majority of the Company’slargest customers are oil and gas producers and suppliers.  For the three and nine months ended September30, 2006, the Company’s two largest customers represented approximately 48% and26%, and 60% and 10%, respectively, of the Company’s sales.  The Company’s two largest customers representedapproximately 60% and 18%, and 59% and 18%, of the Company’s sales for thethree and nine months ended September 30, 2005, respectively.

At September 30, 2006,two customers’ trade accounts receivable from oil and gas sales accounted formore than 10% of the Company’s total trade accounts receivable.  At September 30, 2006, trade accountsreceivable from these customers represented approximately 50%, and 21% of theCompany’s receivables.  At December 31,2005, two customers’ trade accounts receivable from oil and gas sales accountedfor more than 10% of the Company’s total trade accounts receivable.  At December 31, 2005, trade accountsreceivable from these customers represented approximately 70%, and 13% of theCompany’s receivables.

**(9) Unit-Based Compensation**

*Incentive Plan Summary*

The Linn Energy, LLCLong-Term Incentive Plan (the “Plan”) permits the granting of unit grants, unitoptions, restricted units, phantom units and unit appreciation rights under theterms of the Plan.  The Plan limits thenumber of units that may be delivered pursuant to awards to 3.9 million units,provided that no more than 500,000 of such units (as adjusted) may be issued asrestricted units.  The plan isadministered by the Compensation Committee of our Board of Directors.

The Board of Directorsand the Compensation Committee of the Board of Directors have the right toalter or amend the Plan or any part of the Plan from time to time, includingincreasing the number of units that may be granted, subject to unitholder approvalas required by the exchange upon which the units are listed at that time.  However, no change in any outstanding grantmay be made that would materially reduce the benefits to the participantwithout the consent of the participant.

Upon exercise or vestingof an award of, or settled in, units, the Company will issue new units, acquireunits on the open market or directly from any person or use any combination ofthe foregoing, in the compensation committee’s discretion.  If we issue new units upon exercise orvesting of an award of, or settled in, units, the total number of unitsoutstanding will increase.  The planprovides for following types of awards:

*UnitGrants* A unit grant is aunit that vests immediately upon issuance.

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

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

*Phantom Units/Unit AppreciationRights*  These awards may besettled in units, cash or a combination thereof.  Such grants will contain terms as determinedby the compensation committee, including the period or terms over which phantomunits will vest.  If a grantee’semployment or service relationship terminates for any reason, the grantee’sphantom units or unit appreciation rights will be automatically forfeitedunless, and to the extent, the compensation committee or the terms of the awardagreement provide otherwise.  Whilephantom units require no payment from the grantee, unit appreciation rightswill have an exercise price that will not be less than the fair market value ofthe units on the date of grant.

20

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*SecuritiesAuthorized for Issuance Under the Plan*

As of September 30,2006, approximately 1.4 million units were issuable under the Plan pursuant tooutstanding award or other agreements and an additional 2.5 million units werereserved for issuance under the Plan.

*Accounting for Unit-BasedCompensation*

SFAS No. 123(R),(revised 2004), *“Share-Based Payment*”(“SFAS 123R”), was effective January 1, 2006. SFAS 123R requires an entity to recognize expense at the grant date, thefair value of unit options and other equity-based compensation issued toemployees.  The value of the portion ofthe award that is ultimately expected to vest is recognized as expense over therequisite service period using the straight-line method in the Company’sconsolidated statement of operations.

SFAS 123R providesspecific guidance on income tax accounting and clarifies how SFAS No.109, *“Accounting for Income Taxes,”* should be applied tounit-based compensation.  For example,the expense for types of option grants is only deductible for tax purposes atthe time that the taxable event takes place. SFAS 123R does not allow companies to “predict” when these taxableevents will take place.  Furthermore, itrequires that the benefits associated with the tax deductions in excess ofrecognized compensation cost be reported as a financing cash flow, rather thanas an operating cash flow as required under SFAS No. 123 *“Accountingfor Stock-Based Compensation.”* This requirement will reduce net operating cash flows and increase netfinancing cash flows in periods.  Thesefuture amounts cannot be estimated, because they depend on, among other things,when employees exercise unit options.

For the three and ninemonths ended September 30, 2006, we recorded unit-based compensation expense ofapproximately $4.2 million and $14.1 million, respectively, as a charge againstincome before income taxes and it is included in general and administrativeexpense on the consolidated statement of operations.  No related income tax benefit was recognizeddue to Internal Revenue Code Section 162(m) deductibility limits andrecognition of a valuation allowance for resulting net operating losses.  The Company recorded no unit-basedcompensation for the three and nine months ended September 30, 2005, as therewere no unit-based awards granted during those periods.

*Restricted/Unrestricted Units*

The fair value ofunrestricted unit grants and restricted units issued is determined based on thefair market value of the Company units on the date of grant.  This value is amortized over the vestingperiod, which varied between one to two years from the date of grant forcertain officers.  A summary of thestatus of the non-vested units as of September 30, 2006, and changes during thenine months ended September 30, 2006, is presented below:
|                                         | ** ** | **Number of  Non-vested  Units** | ** ** | **Weighted Average  Grant-Date  Fair Value** | ** ** |
|-----------------------------------------|------------|---------------------------------------|------------|--------------------------------------------------------|------------|
| Non-vested units  at December 31, 2005  |       | —                                |       | $                                                      | —     |   |
| Granted                                 |       | 1,039,145                             |       | 21.22                                                  |       |
| Vested                                  |       | (114,455                              | )          | 21.00                                                  |       |
| Forfeited                               |       | —                                |       | —                                                 |       |
|                                    |       |                                  |       |                                                   |       |
| Non-vested units at  September 30, 2006 |       | 924,690                               |       | $                                                      | 21.24      |   |

 

As of September 30,2006, there was approximately $8.5 million of unrecognized compensation costrelated to non-vested restricted units. The cost is expected to be recognized over a weighted average period ofapproximately 0.8 years.

21

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*Changesin Unit Options and Unit Options Outstanding*

The following tableprovides information related to unit option activity for the nine months endedSeptember 30, 2006:
|                                    | ** ** | **Number of  Units Underlying  Options** | ** ** | **Weighted  Average  Exercise Price  Per Unit** | ** ** | **Weighted  Average  Grant Date  Fair Value** | ** ** | **Weighted  Average  Contractual Life  in Years** | ** ** |
|------------------------------------|------------|----------------------------------------------------|------------|-----------------------------------------------------------|------------|---------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| Outstanding at  December 31, 2005  |       | —                                             |       | $                                                         | —     |                                                    | $          | —                                                      |       | — |   |
| Granted                            |       | 588,584                                            |       | 20.58                                                     |       | 3.02                                                    |       | 10.00                                                       |       |
| Exercised                          |       | —                                             |       | —                                                    |       | —                                                  |       | —                                                      |       |
| Forfeited                          |       | (87,084                                            | )          | 20.37                                                     |       | 2.61                                                    |       | 10.00                                                       |       |
|                               |       |                                               |       |                                                      |       |                                                    |       |                                                        |       |
| Outstanding at  September 30, 2006 |       | 501,500                                            |       | $                                                         | 20.62      |                                                    | $          | 3.09                                                        |       | 10.00 |   |
|                               |       |                                               |       |                                                      |       |                                                    |       |                                                        |       |
| Exercisable at  September 30, 2006 |       | 30,000                                             |       | $                                                         | 20.18      |                                                    | $          | 2.52                                                        |       | 10.00 |   |

 

As of September 30,2006, there was approximately $1.1 million of total unrecognized compensationcost related to non-vested unit options. The cost is expected to be recognized over a weighted average period ofapproximately 1.7 years.  In addition,the exercisable unit options at September 30, 2006 have an aggregate intrinsicvalue of approximately $76,000 and all outstanding unit options have anaggregate intrinsic value of approximately $975,000.  No options expired during the period.

The fair value ofunit-based compensation for unit options was estimated on the date of grantusing a Black-Scholes pricing model based on certain assumptions.  The Company’s determination of fair value ofunit-based payment awards is affected by the Company’s unit price as well asassumptions regarding a number of highly complex and subjective variables.  The Company’s employee unit options havevarious restrictions including vesting provisions and restrictions on transfersand hedging, among others, and often are expected to be exercised prior totheir contractual maturity.  Expectedvolatilities used in the estimation of fair value have been determined usingavailable volatility data for the Company as well as an average of volatilitycomputations of other identified peer companies in the oil and gasindustry.  The Company uses historicaldata to estimate unit option exercises, expected term and forfeitures used inthe Black-Scholes pricing model. Forfeitures are revised, if necessary, in subsequent periods if actualforfeitures differ from estimates.  Allemployees granted awards have been determined to have similar behaviors forpurposes of determining the expected term used to estimate fair value.  The risk-free rate for periods within thecontractual term of the unit option is based on the U.S. Treasury yield curvein effect at the time of grant.  The fairvalues of the unit option grants were based upon the following assumptions:
| Expected volatility       |   | 29.70-30.40 | % |
|---------------------------|--------|-------------|---|
| Expected  dividends       |   | 7.20%-8.50  | % |
| Expected term  (in years) |   | 5.00        |
| Risk free rate            |   | 4.31%-5.04  | % |
| Expected forfeiture  rate |   | 23.10       | % |

 

Although the fair valueof unit option grants is determined in accordance with SFAS 123R using aBlack-Scholes option-pricing model, that value may not be indicative of thefair value observed in a willing buyer/willing seller market transaction.  The Company is responsible for determiningthe assumptions used in estimating the fair value of its unit-based paymentawards.

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**(10) Property and Equipment**

Propertyand equipment consists of the following:
|                                       | ** ** | **September 30,**  | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                            | ** ** | **(in thousands)** | ** ** |
| Land                                  |       | $                       | 308        |                  | $          | 203 |   |
| Buildings and  leasehold improvements |       | 2,220                   |       | 608                   |       |
| Vehicles                              |       | 6,292                   |       | 1,317                 |       |
| Drilling  equipment                   |       | 1,933                   |       | —                |       |
| Furniture and  equipment              |       | 1,567                   |       | 888                   |       |
|                                  |       | 12,320                  |       | 3,016                 |       |
|                                  |       |                    |       |                  |       |
| Less:  accumulated depreciation       |       | (1,023                  | )          | (491                  | )          |
|                                  |       |                    |       |                  |       |
|                                  |       | $                       | 11,297     |                  | $          | 2,525 |   |

 

Depreciation expense for the three and nine monthsended September 30, 2006 was approximately $219,000 and $573,000,respectively.  Depreciation expense forthe three and nine months ended September 30, 2005 was approximately $93,000and $204,000 respectively.

**(11) Commitments and Contingencies**

TheCompany would be exposed to oil and gas price fluctuations on underlying salecontracts should the counterparties to the Company’s derivative instruments orthe counterparties to the Company’s oil and gas marketing contracts notperform.  Such nonperformance is notanticipated.  There were no counterpartydefault losses during the three and nine months ended September 30, 2006 or2005.

Fromtime to time the Company is a party to various legal proceedings or is subjectto industry rulings that could bring rise to claims in the ordinary course ofbusiness.  The Company is not currently aparty to any litigation or pending claims that it believes would have a materiallyadverse effect on the Company’s business, financial condition, results ofoperations or liquidity.

**(12) Oil and Gas Derivatives**

TheCompany sells oil and gas in the normal course of its business and utilizesderivative instruments to minimize the variability in forecasted cash flows dueto price movements in crude oil and natural gas.  The Company enters into derivativeinstruments such as swap contracts and put options to hedge a portion of itsforecasted oil and gas sales.

Settledderivatives on gas production for the three and nine months ended September 30,2006 included a volume of 2,029 MMBtu and 6,083 MMBtu at an average price of$9.23 and $9.23, respectively. Currently, we use fixed price swaps and puts to manage commodityprices.  These transactions are settledbased upon the NYMEX price of natural gas at Henry Hub on the final trading dayof the month, and settlement occurs on the third day of the next productionmonth.  Settled derivatives on oil productionfor the three and nine months ended September 30, 2006 included a volume of 40 MBbls at an average price of $76.32.

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Thefollowing tables summarize open positions as of September 30, 2006 andrepresents, as of such date, our derivatives in place through December 31,2010:
|                          | ** ** | **October 1 –   December 31,   2006** | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** |
|--------------------------|------------|---------------------------------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas  Positions**       | ** ** | ** **                                                          | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Fixed Price  Swaps:      | ** ** | ** **                                                          | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume (MMBtu)    |       | 2,625                                                               |       | 8,968          |       | 10,264         |       | 8,005          |       |
| Average Price ($/MMBtu)  |       | $                                                                   | 9.18       |           | $          | 8.72           |       | $              | 8.37       |   | $ | 7.89 |   |
| Puts:                    |       |                                                                |       |           |       |           |       |           |       |
| Hedged Volume (MMBtu)    |       | 184                                                                 |       | 3,296          |       | 2,013          |       | —         |       |
| Average Price ($/MMBtu)  |       | $                                                                   | 8.83       |           | $          | 9.22           |       | $              | 9.50       |   | — |   |
| Total:                   |       |                                                                |       |           |       |           |       |           |       |
| Hedged Volume (MMBtu)    |       | 2,809                                                               |       | 12,264         |       | 12,277         |       | 8,005          |       |
| Average Price  ($/MMBtu) |       | $                                                                   | 9.16       |           | $          | 8.85           |       | $              | 8.56       |   | $ | 7.89 |   |

 
|                         | ** ** | **October 1 –   December 31,   2006** | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** |
|-------------------------|------------|---------------------------------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Oil  Positions**      | ** ** | ** **                                                          | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Fixed Price  Swaps:     | ** ** | ** **                                                          | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume (MBbls)   |       | 110                                                                 |       | 500            |       | 500            |       | 500            |       | 500            |       |
| Average Price ($/MBbl)  |       | $                                                                   | 77.68      |           | $          | 75.83          |       | $              | 75.83      |           | $          | 75.83 |   | $ | 75.83 |   |
| Puts:                   |       |                                                                |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)   |       | 36                                                                  |       | 200            |       | 200            |       | 200            |       | 200            |       |
| Average Price ($/MBbl)  |       | $                                                                   | 75.00      |           | $          | 75.00          |       | $              | 75.00      |           | $          | 75.00 |   | $ | 75.00 |   |
| Total:                  |       |                                                                |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)   |       | 146                                                                 |       | 700            |       | 700            |       | 700            |       | 700            |       |
| Average Price  ($/MBbl) |       | $                                                                   | 77.02      |           | $          | 75.60          |       | $              | 75.60      |           | $          | 75.60 |   | $ | 75.60 |   |

 

Theoil and gas derivatives are not designated as cash flow hedges under SFAS No.133, *“Accounting for Derivatives and Hedging Activity”*(“SFAS 133”), and, accordingly, the changes in fair value are recorded incurrent period earnings.

Thefollowing table presents the outstanding notional amounts and maximum number ofmonths outstanding of our derivatives:
|                                                     | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **2006**               | ** ** | **2005**              | ** ** |
| ** **                                          | ** ** | ** **             | ** ** | ** **            | ** ** |
| Outstanding notional  amounts of gas hedges (MMBtu) |       | 35,355                 |       | 28,069                |       |
| Maximum number of  months gas hedges outstanding    |       | 39                     |       | 48                    |       |
| Outstanding notional  amounts of oil hedges (MBbls) |       | 2,946                  |       | —                |       |
| Maximum number of months oil hedges outstanding     |       | 51                     |       | —                |       |

 

Byusing derivative instruments to hedge exposures to changes in commodity prices,the Company exposes itself to credit risk and market risk.  Credit risk is the failure of thecounterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contractis positive, the counterparty owes the Company, which creates credit risk.  The Company minimizes the credit risk inderivative instruments by entering into transactions with high-qualitycounterparties.

**(13) Related Party**

For the three and nine months ended September 30,2006, the Company made payments of approximately $182,000 and $424,000,respectively, to a company owned by one of our senior executives and boardmembers.  The payments reflectreimbursement for maintenance and hourly usage fees for business use anaircraft that is partially owned by the senior executive.  These costs are included in general andadministrative expense on the consolidated statement of operations.  The fees and expenses associated withthe reimbursements were consummated on terms equivalent to those that prevailin arm’s-length 

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transactions.  In the third quarter of 2006, the Companypurchased an ownership interest in an airplane for corporate travel from athird party; therefore these reimbursements will not be ongoing.  Simultaneous with this transaction, thesenior executive was able to fully liquidate the investment in the aircraftowned by Linn Resources.  The Company isevaluating whether the senior executive benefited from this transaction.

**(14) Subsequent Event**

On October 24, 2006, the Company entered into aClass B Unit and Unit Purchase Agreement with certain third party investorswhereby it privately placed 9,185,965 class B units at a unit price of $20.55,and 5,534,687 units at a unit price of $21.00, for aggregate net proceeds of$305.0 million (the “Private Placement”).

The class B units represent a new class of equitysecurities that is entitled to a special quarterly distribution equal to 115%of the distribution received by the existing class A units.  The class B units have no voting rights otherthan as required by law and are subordinated to the units on dissolution andliquidation.  If approved by a vote ofthe Company’s unitholders, the class B units will convert to units on aone-for-one basis.  The Company hasagreed to hold a special meeting of its unitholders to consider the conversionas soon as feasible, but no later than 90 days following the closing.  Certain existing holders of Linn unitstotaling over 50% have committed in advance to vote at the unitholder meetingin favor of the conversion of class B units to units.  In connection with the Private Placement, theCompany also agreed to register the units and the units underlying the class Bunits with the SEC as soon as practicable, but no later than 165 days followingthe closing.

All proceeds from the Private Placement were used torepay in full the Company’s $250.0 million Subordinated Bridge Loan, $53.3million of borrowings under its Credit Facility and accrued interest ofapproximately $2.0 million (see Note 6). In connection with the repayment of the Subordinated Bridge Loan, theCompany wrote off approximately $2.7 million of deferred financing fees, whichwas recognized as expense in October 2006.

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**Item 2.    Management’s Discussion and Analysis ofFinancial Condition and Results of Operations**

**Results of Operations - ExecutiveSummary**

***Acquisitions andStrategy***

Weare an independent oil and gas company focused on the development andacquisition of long-lived properties in the United States.  We operate in the Appalachian Basin,including in West Virginia, Pennsylvania, New York and Virginia, as well as inCalifornia and Oklahoma.  Our goal is toprovide stability and growth in distributions to our unitholders through acombination of continued successful drilling and acquisitions.  Our company was formed in March 2003.  In January 2006, we completed our initialpublic offering of 12,450,000 units at a price of $21.00 per unit, for netproceeds after underwriting discounts and offering expenses of $238.8 million,of which $122.0 million was used to reduce indebtedness under the Company’srevolving credit facility and repay, in full, the subordinated term loan,$114.4 million was used to redeem a portion of the membership interests in theCompany and units held by certain affiliated and non-affiliated holders and$2.0 million was used to pay bonuses to certain executive officers of theCompany.  In October 2006, theCompany privately placed 9,185,965 class B units at a unit price of $20.55, and5,534,687 units at a unit price of $21.00, or a total of 14,720,652 units at ablended unit price of $20.72, for aggregate net proceeds of $305.0 million,which was used to repay indebtedness (see “Private Placement” below).

From inception through September 30, 2006, we havecompleted 14 acquisitions of oil and gas properties and related gathering andpipeline assets for an aggregate purchase price of approximately $656.0million, with total proved reserves of approximately 441.2 Bcfe, or anacquisition cost of approximately $1.49 per Mcfe.  The Company made two significant acquisitionsin the third quarter of 2006.  TheCompany acquired certain affiliated entities of Blacksand, located in the LosAngeles Basin, for an aggregate purchase price of approximately $300.7 millionand certain Mid-Continent Kaiser-Francis Assets, located in Oklahoma, for anaggregate purchase price of approximately $126.3 million, in both cases subjectto customary post-closing adjustments. Results of Blacksand and the Kaiser-Francis Assets are included in theconsolidated results of the Company beginning August 1, 2006 and September 1,2006, respectively.  See Note 3 in theNotes to Condensed Consolidated Financial Statements for further details aboutthe Blacksand and Kaiser-Francis acquisitions.
| **Date**       | ** ** | **Seller**                                | ** ** | **Gross  Wells** | ** ** | **Location**                | ** ** | **Purchase  Price**    | ** ** |
|----------------|------------|-------------------------------------------|------------|------------------|------------|-----------------------------|------------|------------------------|------------|
| ** **     | ** ** | ** **                                | ** ** | ** **       | ** ** | ** **                  | ** ** | **(in millions)** | ** ** |
| May 2003       |       | Emax Oil Company                          |       | 34               |       | West Virginia               |       | $                      | 3.2        |   |
| August 2003    |       | Lenape  Resources, Inc.              |       | 61               |       | New York               |       | 2.2                    |       |
| September 2003 |       | Cabot Oil &  Gas Corporation     |       | 50               |       | Pennsylvania                |       | 15.8                   |       |
| October 2003   |       | Waco Oil & Gas  Company          |       | 353              |       | West Virginia and  Virginia |       | 31.5                   |       |
| May 2004       |       | Mountain V  Oil & Gas, Inc. |       | 251              |       | Pennsylvania                |       | 12.5                   |       |
| September 2004 |       | Pentex  Energy, Inc.                 |       | 447              |       | Pennsylvania                |       | 15.1                   |       |
| April 2005     |       | Columbia Natural  Resources, LLC     |       | 38               |       | West Virginia and  Virginia |       | 4.4                    |       |
| August 2005    |       | GasSearch Corporation                     |       | 130              |       | West Virginia               |       | 5.4                    |       |
| October 2005   |       | Exploration Partners,  LLC                |       | 550              |       | West Virginia and  Virginia |       | 111.4                  |       |
| April 2006     |       | Excel Energy, Inc.                        |       | 106              |       | West Virginia               |       | 7.5                    |       |
| April 2006     |       | T&F Exploration LP                    |       | 13               |       | West Virginia               |       | 0.9                    |       |
| May 2006       |       | Devonian Gas  Production, Inc.            |       | 81               |       | West Virginia               |       | 19.1                   |       |
| August 2006    |       | Blacksand Energy, LLC.                    |       | 388              |       | California                  |       | 300.7                  |       |
| August 2006    |       | Kaiser-Francis Oil  Company.              |       | 842              |       | Oklahoma                    |       | 126.3                  |       |
|           |       |                                      |       |             |       |                        |       |                   |       |
|           | ** ** | **Total**                                 |       | 3,344            |       |                        |       | $                      | 656.0      |   |

 

Our acquisitions werefinanced with a combination of proceeds from bank borrowings and cash flow fromoperations.  Our activities are focusedon evaluating and developing our asset base, increasing our acreage positionsand evaluating potential acquisitions. Because of our rapid growth through acquisitions and accelerateddevelopment of our properties, our historical results of operations andperiod-to-period comparisons of these results and certain financial data maynot be meaningful or indicative of future results.

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

We utilize the successfulefforts method of accounting for our oil and gas properties.  Leasehold costs are capitalized whenincurred.  Unproved properties that areindividually insignificant are amortized. Unproved properties that are individually 

26

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significant are assessedfor impairment on a property-by-property basis. If considered impaired, costs are charged to expense when suchimpairments are deemed to have occurred. Geological and geophysical expenses and delay rentals are charged toexpense as incurred.  Drilling costs aretypically capitalized, but charged to expense if an exploratory well isdetermined to be unsuccessful.

Higher oil and gas priceshave led to higher demand for drilling rigs, operating personnel and fieldsupplies and services and have caused increases in the costs of those goods andservices.  The Company performs certainactivities in connection with its drilling of oil and gas wells, which includespreparing and clearing well sites, providing drilling engineers, roustaboutsand other personnel necessary for drilling. The Company took delivery of its first two drilling rigs and has oneadditional rig ordered, which will reduce or eliminate reliance on contractrigs.  In the third quarter of 2006, theCompany began, for the first time, operating its own drilling rigs staffed withCompany personnel.  Given the inherentvolatility of crude oil and natural gas prices, which are influenced by manyfactors beyond our control, we plan our activities and budget based onconservative sales price assumptions, which generally are lower than theaverage sales prices ultimately realized. We focus our efforts on increasing oil and gas reserves and productionwhile controlling costs at a level that is appropriate for long-termoperations.  Our future cash flow fromoperations is dependent on our ability to manage our overall cost structure.

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

***Operations***

Our revenues are highlysensitive to changes in crude oil and natural gas prices and levels ofproduction.  As of September 30, 2006, wehave hedged a significant portion of our expected production using oil and gasderivatives, which allows us to mitigate, but not eliminate, commodity pricerisk.  Our expected increase in levels ofproduction as a result of the anticipated drilling of 153 wells during 2006 isdependent on our ability to quickly and efficiently bring the newly drilledwells online.  Any delays in drilling,completion or connection to gathering lines of our new wells will negatively impactthe rate of increase in our production, which may have an adverse effect on ourrevenues and as a result, cash available for distribution.  We continuously conduct financial sensitivityanalyses to assess the effect of changes in pricing and production. Theseanalyses allow us to determine how changes in crude oil and natural gas priceswill affect the ability to drill additional wells and to meet future financialobligations.  Further, the financialanalyses allow us to monitor any impact such changes in crude oil and naturalgas prices may have on the value of our proved reserves and their impact, ifany, on any redetermination of the borrowing base under our credit facility.

***Production andOperating Costs Reporting***

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

***Land and LeaseTracking System***

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

27

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**Results of Operations - Three MonthsEnded September 30, 2006 Compared to Three Months Ended September 30, 2005(Unaudited)**

The following tables set forthselected financial and operating data for the periods indicated:
|                                                     | ** ** | **Three Months Ended  September 30,** | ** ** | ** ** | ** ** |
|-----------------------------------------------------|------------|------------------------------------------------------|------------|------------|------------|
| ** **                                          | ** ** | **2006**                                             | ** ** | **2005**   | ** ** | **Variance** | ** ** |
| ** **                                          | ** ** | **(in thousands)**                              | ** ** |
| **Revenues:**                                       |       |                                                 |       |       |       |   |   |
| Gas sales                                           |       | $                                                    | 15,553     |       | $          | 10,022 |   | $ | 5,531 |   |
| Oil sales                                           |       | 7,953                                                |       | 385        |       | 7,568 |   |
| Realized gain  (loss) on oil and gas derivatives    |       | 8,198                                                |       | 1,246      |       | 6,952 |   |
| Realized loss on  cancelled natural gas derivatives |       | —                                               |       | (30,304    | )          | 30,304 |   |
| Unrealized gain  on oil and gas derivatives         |       | 49,198                                               |       | (21,405    | )          | 70,603 |   |
| Natural gas  marketing income                       |       | 1,090                                                |       | 1,618      |       | (528 | ) |
| Other income                                        |       | 265                                                  |       | 20         |       | 245 |   |
| Total revenue                                       |       | $                                                    | 82,257     |       | $          | (38,418 | ) | $ | 120,675 |   |
| **Expenses:**                                       |       |                                                 |       |       |       |   |   |
| Operating  expenses                                 |       | 4,845                                                |       | 1,386      |       | 3,459 |   |
| Natural gas  marketing expense                      |       | 954                                                  |       | 1,768      |       | (814 | ) |
| General and  administrative expenses                |       | 6,536                                                |       | 1,197      |       | 5,339 |   |
| Depreciation,  depletion and amortization           |       | 5,654                                                |       | 1,448      |       | 4,206 |   |
| Total expenses                                      |       | 17,989                                               |       | 5,799      |       | 12,190 |   |
| **Other Income and (Expenses):**                    | ** ** | ** **                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest and financing  expenses                    |       | $                                                    | (11,204    | )          | $          | (998 | ) | $ | (10,206 | ) |

 
|                                              | ** ** | **Three Months Ended  September 30,** | ** ** | **Percentage  Increase** | ** ** |
|----------------------------------------------|------------|------------------------------------------------------|------------|--------------------------|------------|
| ** **                                   | ** ** | **2006**                                             | ** ** | **2005**                 | ** ** | **(Decrease)** | ** ** |
| **Production:**                              |       |                                                 |       |                     |       |   |   |
| Gas production  (MMcf)                       |       | 2,265                                                |       | 1,132                    |       |   | * |
| Oil production  (MBbls)                      |       | 153                                                  |       | 6                        |       |   | * |
| Total production  (MMcfe)                    |       | 3,181                                                |       | 1,165                    |       |   | * |
| Average daily  production (Mcfe/d)           |       | 34,576                                               |       | 12,663                   |       |   | * |
| ** **                                   |       |                                                 |       |                     |       |   |   |
| **Weighted Average Realized  Prices:**       |       |                                                 |       |                     |       |   |   |
| Gas (Mcf)                                    |       | $                                                    | 10.27      |                     | $          | 5.62 |   | 82.7 | % |
| Oil (Bbl) (1)                                |       | $                                                    | 55.24      |                     | $          | 59.09 |   | (6.5 | )% |
| Total (Mcfe)                                 |       | $                                                    | 9.97       |                     | $          | 6.77 |   | 47.3 | % |
| ** **                                   |       |                                                 |       |                     |       |   |   |
| **Average Unit Costs per Mcfe  (Non-GAAP):** |       |                                                 |       |                     |       |   |   |
| Operating  expenses                          |       | $                                                    | 1.52       |                     | $          | 1.19 |   | 27.7 | % |
| General and  administrative expenses (2)     |       | $                                                    | 0.74       |                     | $          | 1.03 |   | (28.2 | )% |
| Depreciation, depletion  and amortization    |       | $                                                    | 1.78       |                     | $          | 1.24 |   | 43.5 | % |

 

----

(1)      The majority of our oil production, which is inCalifornia, is sold pursuant to a long-term contract at 79% of NYMEX.

(2)      Thisis a non-GAAP performance measure used by our management and is a quantitativemeasure used in the oil and gas industry. The measure for the three months ended September 30, 2006 excludesapproximately $4.2 million of unit-based compensation expense primarilyresulting from January 2006 awards to certain executive officers in connectionwith our IPO.  General and administrativeexpenses including these amounts was $2.05 per Mcfe for the three months endedSeptember 30, 2006.

*             Amount is greaterthan 100%, therefore is not meaningful.

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***Revenue***

Oil and gas salesincreased to approximately $23.5 million, from $10.4 million during the threemonths ended September 30, 2006 as compared to the three months ended September30, 2005.

The increase in revenue from oil and gas sales wasprimarily attributable to increased production. Total production increased to 3,181 MMcfe during the three months endedSeptember 30, 2006, from 1,165 MMcfe during the three months ended September30, 2005.  Oil production increased to153 MBbls during the three months ended September 30, 2006, from 6 MBbls duringthe three months ended September 30, 2005, primarily due to the acquisition ofBlacksand in August 2006.  Gas productionincreased to 2,265 MMcf during the three months ended September 30, 2006, from1,132 MMcf during the three months ended September 30, 2005.  The increase in gas production was due to thedrilling of new wells and to production added by eight acquisitions of oil andgas properties during 2006 and 2005.  TheCompany drilled 127 wells during 2006 (through September 30) and 110 wells in2005.

***HedgingActivities***

During the three monthsended September 30, 2006, we effectively hedged 90% of our gas production and26% of our oil production, which resulted in revenues that were $8.2 milliongreater than we would have achieved at unhedged prices.  During the three months ended September 30,2005, we effectively hedged approximately 111% of our oil and gas production,which resulted in revenues that were $1.2 million greater than we would haveachieved at unhedged prices.  During thethree months ended September 30, 2005, we cancelled (before their originalsettlement date) a portion of out-of-the-money natural gas hedges and realizeda loss of $30.3 million, then subsequently hedged similar volumes at higherprices.  Unrealized gain on derivativesin the amount of $49.2 million for the three months ended September 30, 2006and unrealized loss on derivatives in the amount of $21.4 million for the threemonths ended September 30, 2005 were also recorded.  Unrealized gains and losses result from crudeoil and natural gas price fluctuations as compared to the settlement price onthe derivative.

***Expenses***

Operating expensesconsist of lease operating expenses, labor, field office rent, vehicleexpenses, supervision, transportation, minor maintenance, tools and supplies,severance and ad valorem taxes and other customary charges.  Severance taxes are a function of volumes andrevenues generated from production.  Advalorem taxes vary by state/county and are based on the value of our reserves.  We assess our operating expenses bymonitoring the expenses in relation to the amount of production and the numberof wells operated.  Operating expensesincreased to $4.8 million for the three months ended September 30, 2006, from$1.4 million for the three months ended September 30, 2005, due to the increasein the number of producing wells as a result of the acquisitions completed inboth 2006 and in 2005 and the drilling of 127 wells during 2006 (throughSeptember 30) and 110 wells during 2005. Of the 127 wells drilled during 2006, 42 were drilled during the quarterended September 30, 2006.

General andadministrative expenses include the costs of our employees and executiveofficers, related benefits, office leases, professional fees and other costsnot directly associated with field operations. We monitor general and administrative expenses in relation to the amountof production and the number of wells operated. General and administrative expenses increased to $6.5 million, from $1.2million during the three months ended September 30, 2006 as compared to thethree months ended September 30, 2005. General and administrative expenses are presented net of approximately$0.2 million and $0.3 million during the three months ended September 30, 2006and 2005, respectively, which represent expense reimbursements from otherworking interest owners.  The increase ingeneral and administrative expenses was due to the recognition of unit-basedcompensation expense of $4.2 million during the three months ended September30, 2006, compared to none during the three months ended September 30,2005.  In addition, acquisition coststhat are not eligible for capitalization, including internal and indirect costsfor completed acquisitions, as well as direct costs associated with possiblefuture acquisitions, contributed to the increase.  Costs to support our rapidly growingoperations, including increasing our staffing level to manage the additionalwells acquired and drilled in 2006 and 2005, and to perform the functionsassociated with being a public company also contributed to the increase.

Depreciation, depletionand amortization increased to $5.7 million for the three months ended September30, 2006, from $1.4 million for the three months ended September 30, 2005, dueto the increase in the number of wells as a result of the acquisitionscompleted and the wells drilled in 2006 and 2005, as noted above.  During the three months ended September 30,2006 and 2005, the Company capitalized approximately $2.1 million and $0.7million, respectively, of internal costs related to drilling.  Capitalized drilling costs increased comparedto the prior year quarter due to the Company’s placement of its own drillingrigs into service during the third quarter of 2006.  The Company began, for the first time,operating its own 

29

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drilling rigs staffedwith Company personnel.  The aggregateamount spent on drilling and development for the three months ended September30, 2006 and 2005 was approximately $13.0 million and $7.3 million,respectively.

Interest and financingincome (expense) increased to a net expense of $11.2 million for the threemonths ended September 30, 2006, compared to a net expense of $1.0 million forthe three months ended September 30, 2005, primarily due to increased debtlevels associated with acquisitions and drilling.  Cash payments for interest expense increasedto $8.5 million for the three months ended September 30, 2006, from $1.9million for the three months ended September 30, 2005.  Our interest rate swaps were not specificallydesignated as hedges under SFAS 133, even though they reduce our exposure tochanges in interest rates.  Therefore,the mark-to-market of these instruments was recorded as a loss of approximately$0.6 million and a gain of approximately $0.8 million for the three monthsended September 30, 2006 and 2005, respectively.  Further, these amounts represent non-cashcharges.

There was no income taximpact recorded for the three months ended September 30, 2006.  Income tax was a benefit of $0.4 million forthe three months ended September 30, 2005. Linn is an LLC, and is taxed substantially as a partnership.

30

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**Results of Operations - Nine MonthsEnded September 30, 2006 Compared to Nine Months Ended September 30, 2005(Unaudited)**

The following tables set forthselected financial and operating data for the periods indicated:
|                                                     | ** ** | **Nine Months Ended  September 30,** | ** ** | ** ** | ** ** |
|-----------------------------------------------------|------------|-----------------------------------------------------|------------|------------|------------|
| ** **                                          | ** ** | **2006**                                            | ** ** | **2005**   | ** ** | **Variance** | ** ** |
| ** **                                          | ** ** | **(in thousands)**                             | ** ** |
| **Revenues:**                                       |       |                                                |       |       |       |   |   |
| Gas sales                                           |       | $                                                   | 44,727     |       | $          | 23,692 |   | $ | 21,035 |   |
| Oil sales                                           |       | 8,683                                               |       | 716        |       | 7,967 |   |
| Realized gain  (loss) on oil and gas derivatives    |       | 17,361                                              |       | (7,541     | )          | 24,902 |   |
| Realized loss on  cancelled natural gas derivatives |       | —                                              |       | (38,281    | )          | 38,281 |   |
| Unrealized gain  (loss) on oil and gas derivatives  |       | 77,176                                              |       | (26,788    | )          | 103,964 |   |
| Natural gas  marketing income                       |       | 3,654                                               |       | 3,087      |       | 567 |   |
| Other income                                        |       | 758                                                 |       | 158        |       | 600 |   |
| Total revenue                                       |       | $                                                   | 152,359    |       | $          | (44,957 | ) | $ | 197,316 |   |
| **Expenses:**                                       |       |                                                |       |       |       |   |   |
| Operating  expenses                                 |       | 10,772                                              |       | 4,691      |       | 6,081 |   |
| Natural gas  marketing expense                      |       | 3,126                                               |       | 3,162      |       | (36 | ) |
| General and  administrative expenses                |       | 22,934                                              |       | 2,345      |       | 20,589 |   |
| Depreciation,  depletion and amortization           |       | 13,470                                              |       | 4,035      |       | 9,435 |   |
| Total expenses                                      |       | 50,302                                              |       | 14,233     |       | 36,069 |   |
| **Other Income and (Expenses):**                    | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest and financing  expenses                    |       | $                                                   | (16,539    | )          | $          | (3,282 | ) | $ | (13,257 | ) |

 
|                                              | ** ** | **Nine Months Ended  September 30,** | ** ** | **Percentage  Increase** | ** ** |
|----------------------------------------------|------------|-----------------------------------------------------|------------|--------------------------|------------|
| ** **                                   | ** ** | **2006**                                            | ** ** | **2005**                 | ** ** | **(Decrease)** | ** ** |
| **Production:**                              |       |                                                |       |                     |       |   |   |
| Gas production  (MMcf)                       |       | 5,977                                               |       | 3,156                    |       | 89.4 | % |
| Oil production  (MBbls)                      |       | 166                                                 |       | 14                       |       |   | * |
| Total production  (MMcfe)                    |       | 6,973                                               |       | 3,240                    |       |   | * |
| Average daily  production (Mcfe/d)           |       | 25,542                                              |       | 11,868                   |       |   | * |
| ** **                                   |       |                                                |       |                     |       |   |   |
| **Weighted Average Realized  Prices:**       |       |                                                |       |                     |       |   |   |
| Gas (Mcf)                                    |       | $                                                   | 10.30      |                     | $          | 5.12 |   |   | * |
| Oil (Bbl) (1)                                |       | $                                                   | 55.31      |                     | $          | 53.00 |   | 4.4 | % |
| Total (Mcfe)                                 |       | $                                                   | 10.15      |                     | $          | 6.27 |   | 61.9 | % |
| ** **                                   |       |                                                |       |                     |       |   |   |
| **Average Unit Costs per Mcfe  (Non-GAAP):** |       |                                                |       |                     |       |   |   |
| Operating  expenses                          |       | $                                                   | 1.54       |                     | $          | 1.45 |   | 6.2 | % |
| General and  administrative expenses (2)     |       | $                                                   | 0.98       |                     | $          | 0.72 |   | 36.1 | % |
| Depreciation, depletion  and amortization    |       | $                                                   | 1.93       |                     | $          | 1.25 |   | 54.4 | % |

 

----

(1)      The majority of our oil production, which is in California,is sold pursuant to a long-term contract at 79% of NYMEX.

(2)      Thisis a non-GAAP performance measure used by our management and is a quantitativemeasure used in the oil and gas industry. The measure for the nine months ended September 30, 2006 excludesapproximately $2.0 million of bonuses paid to certain executive officers inconnection with our IPO and $14.1 million of unit-based compensationexpense.  General and administrativeexpenses including these amounts was $3.29 per Mcfe for the nine months endedSeptember 30, 2006.

*             Amount is greaterthan 100%, therefore is not meaningful.

31

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***Revenue***

Oil and gas salesincreased to approximately $53.4 million, from $24.4 million during the ninemonths ended September 30, 2006 as compared to the nine months ended September30, 2005.

The increase in revenue from oil and gas sales wasprimarily attributable to increased production. Total production increased to 6,973 MMcfe during the nine months endedSeptember 30, 2006, from 3,240 MMcfe during the nine months ended September 30,2005.  Oil production increased to 166MBbls during the nine months ended September 30, 2006, from 14 MBbls during thenine months ended September 30, 2005, primarily due to the acquisition ofBlacksand in August 2006.  Gas productionincreased to 5,977 MMcf during the nine months ended September 30, 2006, from3,156 MMcf during the nine months ended September 30, 2005.  The increase in gas production was due to thedrilling of new wells and to production added by eight acquisitions of oil andgas properties during 2006 and 2005.  TheCompany drilled 127 wells during 2006 (through September 30) and 110 wells in2005.

***HedgingActivities***

During the nine monthsended September 30, 2006, we effectively hedged 102% of our gas production and 24%of our oil production, which resulted in revenues that were $17.4 milliongreater than we would have achieved at unhedged prices.  During the nine months ended September 30,2005, we hedged approximately 82% of our oil and gas production, which resultedin revenues that were $7.5 million less than we would have achieved at unhedgedprices.  During the nine months endedSeptember 30, 2005, we cancelled (before their original settlement date) aportion of out-of-the-money natural gas hedges and realized a loss of $38.3million, then subsequently hedged similar volumes at higher prices.  Unrealized gain on derivatives in the amountof $77.2 million for the nine months ended September 30, 2006 and unrealizedloss on derivatives in the amount of $26.8 million for the nine months endedSeptember 30, 2005 were also recorded. Unrealized gains and losses result from crude oil and natural gas pricefluctuations as compared to the settlement price on the derivative.

***Expenses***

Operating expensesconsist of lease operating expenses, labor, field office rent, vehicleexpenses, supervision, transportation, minor maintenance, tools and supplies,severance and ad valorem taxes and other customary charges.  Severance taxes are a function of volumes andrevenues generated from production.  Advalorem taxes vary by state/county and are based on the value of ourreserves.  We assess our operatingexpenses by monitoring the expenses in relation to the amount of production andthe number of wells operated.  Operatingexpenses increased to $10.8 million for the nine months ended September 30,2006, from $4.7 million for the nine months ended September 30, 2005, due tothe increase in the number of producing wells as a result of the acquisitionscompleted in both 2006 and in 2005, and the drilling of 127 wells during 2006(through September 30) and 110 wells during 2005 (through December 31).

General andadministrative expenses include the costs of our employees and executiveofficers, related benefits, office leases, professional fees and other costsnot directly associated with field operations. We monitor general and administrative expenses in relation to the amountof production and the number of wells operated. General and administrative expenses increased to $22.9 million duringthe nine months ended September 30, 2006, from $2.3 million compared to thenine months ended September 30, 2005. General and administrative expenses are presented net of approximately$0.9 million and $0.8 million during the nine months ended September 30, 2006and 2005, respectively, which represent expense reimbursements from otherworking interest owners.  The increase ingeneral and administrative expenses was due in part to the recognition ofunit-based compensation expense of $14.1 million and $2.0 million of bonusespaid in connection with our IPO during the nine months ended September 30,2006, neither of which were incurred during 2005.  In addition, acquisition costs that are noteligible for capitalization, including internal and indirect costs forcompleted acquisitions, as well as direct costs associated with possible futureacquisitions, contributed to the increase. Costs to support our rapidly growing operations, including increasingour staffing level to manage the additional wells acquired and drilled in 2006and 2005, and to perform the functions associated with being a public companyalso contributed to the increase.

Depreciation, depletionand amortization increased to $13.5 million for the nine months ended September30, 2006, from $4.0 million for the nine months ended September 30, 2005, dueto the increase in the number of wells as a result of the acquisitionscompleted and the drilling of wells during 2006 and 2005, as noted above.  During the nine months ended September 30, 2006and 2005, the Company capitalized approximately $4.0 million and $1.1 million,respectively, of internal costs related to drilling.  Capitalized drilling costs increased comparedto the prior year period due to the Company’s placement of its own drillingrigs into service during the third quarter of 2006 as noted above.  The aggregate amount spent on drilling anddevelopment for the nine months ended September 30, 2006 and 2005 wasapproximately $26.7 million and $15.6 million, respectively.

32

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Interest andfinancing income (expense) increased to a net expense of $16.5 million forthe nine months ended September 30, 2006, compared to a net expense of $3.3million for the nine months ended September 30, 2005, primarily due toincreased debt levels associated with acquisitions and drilling.  Cash payments for interest expense increasedto approximately $13.6 million for the nine months ended September 30, 2006,from $3.6 million for the three months ended September 30, 2005.  Our interest rate swaps were not specificallydesignated as hedges under SFAS 133, even though they reduce our exposure tochanges in interest rates.  Therefore,the mark-to-market of these instruments was recorded as gains of approximately$0.1 million and $0.8 million for the nine months ended September 30, 2006 and2005, respectively.  Further, theseamounts represent non-cash charges.

Income tax was abenefit of approximately $74,000 for the nine months ended September 30, 2006,compared to income tax expense of $0.4 million for the nine months endedSeptember 30, 2005.  Linn is an LLC, andis taxed substantially as a partnership.

**CriticalAccounting Policies and Estimates**

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 September30, 2006, there have been no significant changes with regard to the criticalaccounting policies disclosed in the Company’s Annual Report on Form 10-K forthe year ended December 31, 2005.  Thepolicies disclosed included the accounting for oil and gas properties, oil andgas reserve quantities, revenue recognition and derivative instruments.  Effective January 1, 2006, the Companyimplemented SFAS 123R.  See Note 9 in theNotes to Condensed Consolidated Financial Statements for a comprehensivediscussion of the accounting for unit-based compensation expense, including adiscussion of the assumptions used to estimate the fair market value of awards.

33

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**Liquidity and Capital Resources**

***Statements of Cash Flow***

At September 30, 2006, we had cash and cash equivalentsof $1.8 million compared to $11.0 million at December 31, 2005.

Cash provided by operating activities for the nine monthsended September 30, 2006 was $8.0 million, compared to cash used in operatingactivities of $34.4 million for the nine months ended September 30, 2005.  The increase in cash provided by operatingactivities was primarily due to the increase in net income, which was $85.3million for the nine months ended September 30, 2006, compared to a net loss of$63.3 million for the nine months ended September 30, 2005.  See “Results of Operations” above for detailabout the increase in components of net income.

Cash used in investing activities was $509.1 million forthe nine months ended September 30, 2006, compared to $28.4 million for thenine months ended September 30, 2005. The increase in cash used in investing activities was due primarily tothe acquisitions of Blacksand and the Kaiser-Francis Assets in the thirdquarter of 2006, as well as to several other acquisitions that were completedin the second quarter of 2006.  See Note3 in the Notes to Condensed Consolidated Financial Statements.

Cash provided by financing activities was $491.8 millionfor the nine months ended September 30, 2006, compared to $63.6 million for thenine months ended September 30, 2005.  Inthe first quarter of 2006, we completed our IPO of an aggregate of 12,450,000units representing limited liability company interests at $21.00 per unit.  Theaggregate initial public offering price for the units issued was approximately$261.4 million.  Net proceeds tothe Company (after underwriting discounts of approximately $18.3 millionand offering expenses of approximately $4.3 million) were approximately$238.8 million, of which $122.0 million was used to reduce the Company’sthen-existing indebtedness, approximately$114.4 million was used to redeem a portion of the membership interests in theCompany and units held by certain affiliated and non-affiliated holders andapproximately $2.0 million was used to pay bonuses to certain executiveofficers of the Company.

Inthe third quarter of 2006, the Company received proceeds from borrowings on itsCredit Facility of $213.0 million, and from borrowing on its SubordinatedBridge Loan of $250.0 million.  Theseproceeds were used primarily to fund the acquisitions of Blacksand and theKaiser-Francis Assets.

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

In July 2006, theCompany’s Board of Directors declared a distribution of $0.40 per unit withrespect to the second quarter of 2006. The distribution totaling approximately $11.2 million was paid in August2006.

In October 2006,the Company’s Board of Directors declared a distribution of $0.43 per unit withrespect to the third quarter of 2006. The distribution totaling approximately $12.0 million will be paid onNovember 14, 2006 to unitholders of record at the close of business on October20, 2006.

Managementcurrently anticipates that it will recommend to the Board of Directors anincrease in the annualized cash distribution of $0.36 per unit, or a 21%increase, to an annual rate of $2.08 per unit from the current annual rate of$1.72 per unit, beginning with the cash distribution expected to be paid on orabout February 14, 2007 with respect to the fourth fiscal quarter of2006.  This is equivalent to a quarterlyrate of $0.52 per unit.

***Credit Facility***

In August 2006, inconnection with the acquisitions of Blacksand and the Kaiser-Francis Assets(see Note 3 in the Notes to CondensedConsolidated Financial Statements), the Company entered into an amendedand restated senior secured revolving credit facility (the “Credit Facility”)with a maturity of August 2010, including an increase in the facility to $800.0million and an increase in the borrowing base to $480.0 million.  We also entered into a subordinated bridgeloan (see “Subordinated Bridge Loan” below).

The terms under the amended Credit Facility remain substantially thesame as the terms under the prior facility.  The borrowing base under the Credit Facilitywill be redetermined semi-annually by the lenders in their sole discretion,based on, among other things, reserve reports as prepared by reserve engineerstaking into account the oil and gas prices at such time.  Our obligations under the Credit Facility aresecured by mortgages on our oil and gas properties as well as a pledge of allownership interests in our operating subsidiaries.  We are required to maintain the mortgages onproperties representing at

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least 80% of ouroil and gas properties.  Additionally,the obligations under the Credit Facility are guaranteed by all of ouroperating subsidiaries and may be guaranteed by any future subsidiaries.

At our election, interest on the Credit Facility is determined byreference to LIBOR plus an applicable margin between 1.00% and 1.75% per annum;or a domestic bank rate plus an applicable margin between 0.00% and 0.25% perannum.  LIBOR margins increased by 0.25%during the term of the Subordinated Bridge Loan, which was repaid in October2006.  Interest is generally payablequarterly for domestic bank rate loans and at the applicable maturity date forLIBOR loans.

The CreditFacility contains various covenants that limit the Company’s ability to incuradditional indebtedness, make acquisitions or certain capital expenditures;make distributions other than from available cash; merge or consolidate; andengage in certain asset dispositions. The Credit Facility also contains covenants that, among other things,require us to maintain specified financial ratios.  The Company is in compliance with allfinancial and other covenants of its Credit Facility.  The Company repaid $53.0 million ofborrowings under its Credit Facility in October 2006 (see “Private Placement”below).

***Subordinated Bridge Loan***

In August 2006, inorder to fund a portion of the acquisitions of Blacksand and the Kaiser-FrancisAssets, we entered into a $250.0 million Subordinated Bridge Loan with atermination of August 1, 2007.  Financialcovenants under the Subordinated Bridge Loan are substantially similar to thoseunder the Credit Facility.  At ourelection, interest is determined by reference to LIBOR plus an applicablemargin of 4.00% per annum; or a domestic bank rate plus an applicable margin of2.50% per annum.  Interest is generallypayable quarterly for domestic bank rate loans and at the applicable maturitydate for LIBOR loans.  The Company repaidin full the Subordinated Bridge Loan in October 2006 (see “Private Placement”below).

***Private Placement***

On October 24,2006, the Company entered into a Class B Unit and Unit Purchase Agreement withcertain third party investors whereby it privately placed 9,185,965 class Bunits at a unit price of $20.55, and 5,534,687 units at a unit price of $21.00,or a total of 14,720,652 units at a blended unit price of $20.72, for aggregatenet proceeds of $305.0 million (the “Private Placement”).

The class B unitsrepresent a new class of equity securities that is entitled to a specialquarterly distribution equal to 115% of the distribution received by theexisting Class A units.  The class Bunits have no voting rights other than as required by law and are subordinatedto the units on dissolution and liquidation. If approved by a vote of the Company’s unitholders, the class B unitswill convert to units on a one-for-one basis. The Company has agreed to hold a special meeting of its unitholders toconsider the conversion as soon as feasible, but no later than 90 daysfollowing the closing.  Certain existingholders of Linn units totaling over 50% have committed in advance to vote atthe unitholder meeting in favor of the conversion of class B units to units.  In connection with the Private Placement, theCompany also agreed to register the units and the units underlying the class Bunits with the SEC as soon as practicable, but no later than 165 days followingthe closing.

All proceeds fromthe Private Placement were used to repay in fullthe Company’s $250.0 millionSubordinated Bridge Loan, $53.3 million of borrowings under its Credit Facilityand accrued interest of approximately $2.0 million (see Note 6 in the Notes to Condensed Consolidated FinancialStatements).  In connection withthe repayment of the Subordinated Bridge Loan, the Company wrote offapproximately $2.7 million of deferred financing fees, which was recognized asexpense in October 2006.

***Off-BalanceSheet Arrangements***

At September 30,2006, the Company did not have any off-balance sheet arrangements that have, orare reasonably likely to have, a material effect on our financial position orresults of operations.

***Commitmentsand Contractual Obligations***

The Company hascontractual obligations for long-term debt, operating leases and otherlong-term liabilities that were summarized in a table of contractualobligations in the 2005 Annual Report on Form 10-K.  Additional long-term obligations include theCompany’s Credit Facility (see Note 6 in the Notesto Condensed Consolidated Financial Statements) and asset retirementobligations acquired with the Company’s purchase of Blacksand and the Kaiser-FrancisAssets (see Note 3 in the

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Notes to Condensed Consolidated Financial Statements), whichconstitute the significant changes to the Company’s contractual obligationsfrom December 31, 2005.

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**Non-GAAP Financial Measure**

**Adjusted EBITDA**

We define Adjusted EBITDA as netincome (loss) plus:

·                  Interest expense;

·                  Depreciation, depletion andamortization;

·                  Write-off of deferred financing fees;

·                  (Gain) loss on sale of assets;

·                  (Gain) loss from equity investment;

·                  Accretion of asset retirementobligation;

·                  Unrealized (gain) loss on oil and gasderivatives;

·                  Realized (gain) loss on cancellednatural gas swaps;

·                  Unit-based compensation expense;

·                  IPO cash bonuses; and

·                  Incometax provision.

The costs of canceling natural gas swaps before theiroriginal settlement date are adjustments to Adjusted EBITDA that requireexpenditure of cash.  These costs werefinanced with borrowings under our Credit Facility, and such long-term debt isrecognized as an increase in cash from financing activities.

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

The following table presents a reconciliation of ourconsolidated net income (loss) to Adjusted EBITDA:
|                                                        | ** ** | **Three months ended September 30,** | ** ** | **Nine months ended September 30,** | ** ** |
|--------------------------------------------------------|------------|----------------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                             | ** ** | **2006**                                                 | ** ** | **2005**                                                | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                             | ** ** | **(in thousands)**                                  | ** ** |
| Net income  (loss)                                     |       | $                                                        | 53,057     |                                                    | $          | (45,590 | ) | $ | 85,273 |   | $ | (63,265 | ) |
| Plus:                                                  |       |                                                     |       |                                                    |       |   |   |   |   |
| Interest expense                                       |       | 11,204                                                   |       | 998                                                     |       | 16,539 |   | 3,282 |   |
| Depreciation, depletion and amortization               |       | 5,654                                                    |       | 1,448                                                   |       | 13,470 |   | 4,035 |   |
| Write-off of deferred financing fees                   |       | 161                                                      |       | —                                                  |       | 664 |   | 364 |   |
| (Gain) loss on sale of assets                          |       | (47                                                      | )          | 3                                                       |       | — |   | 43 |   |
| Loss from equity investment                            |       | —                                                   |       | —                                                  |       | — |   | 17 |   |
| Accretion of asset retirement obligation               |       | 61                                                       |       | 67                                                      |       | 180 |   | 124 |   |
| Unrealized (gain) loss on oil and gas derivatives      |       | (49,198                                                  | )          | 21,405                                                  |       | (77,176 | ) | 26,788 |   |
| Realized loss on cancelled natural gas derivatives (1) |       | —                                                   |       | 30,304                                                  |       | — |   | 38,281 |   |
| Unit-based compensation expense                        |       | 4,191                                                    |       | —                                                  |       | 14,067 |   | — |   |
| IPO cash bonuses                                       |       | —                                                   |       | —                                                  |       | 2,039 |   | — |   |
| Income tax provision (benefit) (2)                     |       | —                                                   |       | 385                                                     |       | (74 | ) | 385 |   |
| Adjusted EBITDA                                        |       | $                                                        | 25,083     |                                                    | $          | 9,020 |   | $ | 54,982 |   | $ | 10,054 |   |

 

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(1)                                  During the three and nine months ended September30, 2005, we cancelled (before their original settlement date) a portion ofout-of-the-money natural gas swaps and realized a loss of $30.3 million and$38.3 million, respectively.  Wesubsequently hedged similar volumes at higher prices.

(2)                                  Linn Operating, LLC was not subject to federalincome tax before converting to a subchapter C corporation on June 1,2005.  Prior to the conversion, there wasno tax provision included in our consolidated financial statements because allof our taxable income or loss was included in the income tax returns of theindividual members.

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Asnoted above, Adjusted EBITDA is non-GAAP performance measure used by ourmanagement and is a quantitative measure used in the oil and gas industry.  On our consolidated statements of cash flows,our net cash provided by operating activities for the nine months ended September30, 2006 was approximately $8.0 million and includes approximately $77.2million unrealized gain on oil and gas derivatives, $13.9 million unit-basedcompensation expense and $2.0 million of bonuses paid to certain executiveofficers in connection with our IPO.  Ournet cash used by operating activities for the nine months ended September 30,2005 was approximately $34.4 million and includes $26.8 million unrealized losson oil and gas derivatives and $38.3 million realized loss on cancelled naturalgas derivatives.

**NewAccounting Standards**

Therehave been no accounting standards adopted that materially affected the Companythis period; however, see Note 9 in the Notes to Condensed ConsolidatedFinancial Statements for a discussion of SFAS 123R.

**CautionaryStatement**

This QuarterlyReport on Form 10-Q contains forward-looking statements within the meaning offederal securities laws that are subject to a number of risks anduncertainties, many of which are beyond our control.  These statements may include statements aboutour:

·                  business strategy;

·                  financial strategy;

·                  drilling locations;

·                  oil and gas reserves;

·                  realized oil and gas prices;

·                  production volumes;

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

·                  future operating results; and

·                  plans,objectives, expectations and intentions.

All of these typesof statements, other than statements of historical fact included in thisQuarterly Report on Form 10-Q, are forward looking statements.  These forward-looking statements may be foundin Item 2.  In some 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,” thenegative of such terms or other comparable terminology.

Theforward-looking statements contained in this Quarterly Report on Form 10-Q arelargely based on our expectations, which reflect estimates and assumptions madeby our management.  These estimates andassumptions reflect our best judgment based on currently known marketconditions and other factors.  Althoughwe believe such estimates to be reasonable, they are inherently uncertain andinvolve a number of risks and uncertainties beyond our control.  In addition, management’s assumptions mayprove to be inaccurate.  We caution thatthe forward-looking statements contained in this Quarterly Report on Form 10-Qare not guarantees of future performance and that such statements may not berealized or the forward-looking statements or events may not occur.  Actual results may differ materially fromthose anticipated or implied in forward-looking statements due to factorslisted in “Item 1A. Risk Factors” and elsewhere in this Quarterly Report onForm 10-Q and in the reports and other information we file with the SEC.  These forward-looking statements speak onlyas of the date made, and other than as required by law, we undertake noobligation to publicly update or revise any forward-looking statement, whetheras a result of new information, future events or otherwise.

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**Item 3.    Quantitative and Qualitative DisclosuresAbout Market Risk**

The primaryobjective of the following information is to provide forward-lookingquantitative and qualitative information about our potential exposure to marketrisks.  The term “market risk” refers tothe risk of loss arising from adverse changes in crude oil prices, natural gasprices and interest rates.  Thedisclosures are not meant to be precise indicators of expected future losses,but rather indicators of reasonably possible losses.  This forward-looking information providesindicators of how we view and manage our ongoing market risk exposures.  All of our market risk sensitive instrumentswere entered into for purposes other than speculative trading.

***Commodity PriceRisk***

Our major market risk exposure is in the pricingapplicable to our oil and gas production. Realized pricing is primarily driven by the spot market pricesapplicable to our natural gas production and the prevailing price for crudeoil.  Pricing for crude oil and naturalgas production has been volatile and unpredictable for several years, and weexpect this volatility to continue in the future.  The prices we receive for production dependon many factors outside of our control.

We periodically have entered into and anticipate enteringinto hedging arrangements with respect to a portion of our projected crude oiland natural gas production through various transactions that hedge the futureprices received.  These transactions mayinclude price swaps whereby we will receive a fixed price for our productionand pay a variable market price to the contract counterparty.  At the settlement date, we receive theexcess, if any, of the fixed floor over the floating rate.  Additionally, we have put options for whichwe pay the counterparty the fair value at the purchase date.  These hedging activities are intended tosupport crude oil and natural gas prices at targeted levels and to manage ourexposure to crude oil and natural gas price fluctuations.  We do not hold or issue derivativeinstruments for speculative trading purposes.

At September 30, 2006, the fair value of hedges thatsettle during the next twelve months was an asset of approximately $30.4million and a liability of approximately $0.6 for a net asset of approximately$29.8 million, which we are owed from the counterparty.  A 10% increase in the index natural gas priceabove the September 30, 2006 price for the next twelve months would result in areduction of approximately $10.8 million; conversely, a 10% decrease in theindex natural gas price would result in an increase of approximately $10.8million.

Our derivatives as of September 30, 2006, for 2006through 2010, are summarized in the table presented in Note 12 in the Notes toCondensed Consolidated Financial Statements.

***Interest RateRisk***

At September 30, 2006, we had long-term debt outstandingof $406.0 million under our Credit Facility, which incurred interest atfloating rates in accordance the Credit Facility agreement.  As of September 30, 2006, the one-month LIBORwas approximately 5.3%.  A 1% increase inthe one-month LIBOR would result in an estimated $4.1 million increase inannual interest expense.

In order to finance the acquisitions of Blacksand and theKaiser-Francis Assets in August 2006, the Company modified its Credit Facility,including an increase in the facility to $800.0 million and an increase in theborrowing base to $480.0 million.  Inaddition, the Company entered into a $250.0 million Subordinated BridgeLoan.  See Note 6 in the Notes toCondensed Consolidated Financial Statements.

InOctober 2006, proceeds from the Private Placement were used to repay in fullthe Company’s $250.0 million Subordinated Bridge Loan, $53.3 million ofborrowings under its Credit Facility and accrued interest of approximately $2.0million (see Note 14 in the Notes toCondensed Consolidated Financial Statements).

In 2003, we entered into two interest rate swapagreements to minimize the effect of fluctuation in interest rates.  The agreements have a notional amount of$30.0 million each.  One of the interestrate swap agreements settled quarterly in 2005 and the second settles quarterlyin 2006, and we are required to pay an interest rate of 3.17% and 4.40%,respectively, while receiving a floating interest rate.  In 2004, we entered into two additionalinterest rate swap agreements with a notional amount of $50.0 millioneach.  These interest rate swapagreements settle quarterly in 2007 and 2008, and we are required to pay aninterest rate of 5.30% and 5.79%, respectively, while receiving a floatinginterest rate.

Also in 2004, we entered into two additional interestrate swap agreements with a notional amount of $20.0 million each.  One of the agreements settled quarterly in2005 and the second settles quarterly in 2006. We are required to pay an interest rate of 3.08% and 4.42%,respectively, while receiving a floating interest rate.

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A 1% change in LIBOR from the rate at September 30, 2006,would result in an estimated $1.5 million change in annual interest expenseassociated with our interest swap agreements.

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

We did not specifically designate the interest rate swapagreements we entered into as cash flow hedges under SFAS 133, even though theyprotect us from changes in interest rates. Therefore, the mark-to-market of these instruments was recorded in ourcurrent earnings.  Further, these amountsrepresent non-cash charges.

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**Item 4.****            Controls andProcedures**

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

The Companymaintains disclosure controls and procedures that are designed to ensure thatinformation required to be disclosed in the Company’s reports under theExchange Act is recorded, processed, summarized and reported within the timeperiods specified in the SEC’s rules and forms, and that such information isaccumulated and communicated to management, including the Company’s ChiefExecutive Officer and Chief Financial Officer, and the Company’s AuditCommittee of the Board of Directors, as appropriate, to allow timely decisionsregarding 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.

We carried out anevaluation under the supervision and with the participation of our management,including our Chief Executive Officer and Chief Financial Officer, of theeffectiveness of our disclosure controls and procedures as of the end of theperiod covered by this report.

Due to the material weakness described below, our CEO and CFOcontinue to conclude that our disclosure controls and procedures were noteffective as of September 30, 2006.  Asnoted below, we believe we have taken the necessary steps to address thematters related to the material weakness. However, before concluding that the material weakness has beenremediated, management believes that the new internal controls should beimplemented and operational for a sufficient period of time to demonstrate thatthe controls are operating effectively. We believe our consolidated financial statements included in 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.

*Materialweaknesses in internal control*.  In connection with the preparation of theCompany’s Annual Report on Form 10-K for the year ended December 31, 2005(“2005 10-K”), an evaluation was performed under the supervision and with theparticipation of the Company’s management, including the Chief ExecutiveOfficer and the Chief Financial Officer, of the effectiveness of the design andoperation of the Company’s disclosure controls and procedures as defined inRule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of1934, as amended (the “Exchange Act”). The Company concluded that the disclosure controls and procedures werenot effective as of December 31, 2005.

Specifically, theCompany lacked (i) personnel with sufficient technical accounting andfinancial reporting expertise, (ii) adequate review controls over accountreconciliations and account analyses, (iii) policies and procedures inplace to determine and document the appropriate application of accountingprinciples and (iv) policies and procedures requiring a detailed andcomprehensive review of the underlying information supporting the amountsincluded in the annual and interim consolidated financial statements anddisclosures.  We undertook numerousremedial actions, as described below, to enhance controls.

*Remediationactivities.*  During2006, Company management has taken the following steps to strengthen internalcontrol over financial reporting.

1.     We engaged outsideconsultants with extensive oil and gas financial reporting experience toaugment our current accounting resources to assist with this quarterly reportand future filings.

2.     We performed additionalanalysis and other post closing procedures to enable the preparation ofaccurate consolidated financial statements, including all requireddisclosures.  In addition, we implementedcertain review and monitoring controls over account reconciliations, andanalysis and post closing procedures.

3.     We developed and implementeda process for determining the effective accounting date for an oil and gasproperty acquisition and formalized procedures necessary to appropriatelyaccount for future acquisitions.

4.     We implemented the use ofdisclosure checklists addressing the disclosure requirements under GAAP as wellas the incremental financial and nonfinancial information required by SECregulations.

5.     We hired experiencedpersonnel with technical accounting, financial reporting and oil and gasexperience.

6.     We provided extensivetraining on our accounting software system to both new and establishedaccounting personnel.

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We believe we have taken the necessary steps to address thematters related to the material weakness described above.  However, before concluding that the materialweakness has been remediated, management believes that the new internalcontrols should be implemented and operational for a sufficient period of timeto demonstrate that the controls are operating effectively.

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

In response to the material weakness noted in 4(a) above,during the three months ended September 30, 2006, Company management has takenthe following remedial actions (i) hiring experienced personnel with technicalaccounting, financial reporting and oil and gas experience, (ii) providingextensive training on our accounting software system to both new andestablished accounting personnel and (iii) continuing to perform and to enhanceadditional analysis and other post closing procedures, including certain reviewand monitoring controls over account reconciliation.  These three items constitute the changes inour internal control over financial reporting, as defined inRule 13(a)-15(f) under the Exchange Act, during the three months endedSeptember 30, 2006 that have materially affected, or are reasonably likely tomaterially affect, our internal control over financial reporting.

Further aspreviously reported, we expect to continue to make changes in our internalcontrol over financial reporting during the periods prior to December 31,2007 in connection with our compliance efforts under Section 404 of theSarbanes-Oxley Act of 2002.  As such, wewill continue to assess the adequacy of our internal control over financialreporting, remediate any control weaknesses that may be identified, validatethrough testing that controls are functioning as designed and implement acontinuous reporting and improvement process for internal control overfinancial reporting.

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**PART II - OTHER INFORMATION**

**Item 1.****       ****LegalProceedings**

Not applicable.

**Item 1A.****     Risk Factors**

Our business has many risks.  As of the date of this report, factors thathave materially changed from those reported in “Item 1A. Risk Factors” in ourQuarterly Report on Form 10-Q for the three and six months ended June 30, 2006,are described below.  This informationshould be considered carefully, together with other information in this reportand other reports and materials we file with the SEC.

## **Related to Our Business**

***We have significant indebtednessunder our Credit Facility.  Our CreditFacility has substantial restrictions and financial covenants and we may havedifficulty obtaining additional credit, which could adversely affect ouroperations and our ability to pay distributions to our unitholders.***

We have significant indebtedness under our CreditFacility.  As of November 1, 2006, we hadapproximately $352.8 million outstanding under our Credit Facility (withadditional borrowing capacity of approximately $123.2 million).  As a result of our indebtedness, we will usea portion of our cash flow to pay interest and principal when due, which willreduce the cash available to finance our operations and other businessactivities and could limit our flexibility in planning for or reacting to,changes in our business and the industry in which we operate.  The amount of our debt may also cause us tobe more vulnerable to economic downturns and adverse developments in ourbusiness.  Our ability to access thecapital markets to raise capital on favorable terms will be affected by ourdebt level and by adverse market conditions resulting from, among other things,general economic conditions, contingencies and uncertainties that are difficultto predict and impossible to control. 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 a portion of our distributions.  The Credit Facility restricts our ability toobtain additional financing, make investments, lease equipment, sell assets andengage in business combinations.  We alsoare required to comply with certain financial covenants and ratios.  Our ability to comply with these restrictionsand covenants in the future is uncertain and will be affected by the levels ofcash flow from our operations and events or circumstances beyond our control.Our failure to comply with any of the restrictions and covenants under ourCredit Facility could result in a default under our Credit Facility, whichcould cause all of our existing indebtedness to 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 andgas prices.  The lenders can unilaterallyadjust the borrowing base and the borrowings permitted to be outstanding underthe Credit Facility.  Any increase in theborrowing base requires the consent of all the lenders.  If the required lenders do not agree on anincrease, then the borrowing base will be the highest borrowing base acceptableto the lenders holding 66 2/3% of the commitments.  Outstanding borrowings in excess of theborrowing base must be repaid immediately, or we must pledge other oil and gasproperties as additional collateral.  Wedo not currently have any substantial unpledged properties, and we may not havethe financial resources in the future to make any mandatory principalprepayments required under the Credit Facility. Significant declines in our production or significant declines inrealized oil or gas prices for prolonged periods and resulting decreases in ourborrowing base may force us to reduce or suspend distributions to ourunitholders.

***Increases in interest rates couldadversely affect our business, results of operations, cash flows fromoperations and financial condition.***

In addition to our exposure to commodity prices, wehave significant exposure to increases in interest rates.  As of November 1, 2006, we had approximately$352.8 million of indebtedness outstanding under the Credit Facility, all ofwhich is at variable interest rates, after giving effect to existing interestswap arrangements.  Therefore, ourbusiness, results of operations, cash flows from operations could be adverselyaffected by significant increases in interest rates.

An increase in interest rates may cause acorresponding decline in demand for equity investments, in general, and inparticular for yield-based equity investments such as our units.  Any such reduction in demand for our unitsresulting from other more attractive investment opportunities may cause thetrading price of our units to decline.

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## ***We depend on certain key customersfor sales of our oil and gas. To the extent these and other customers reducethe volumes of oil or gas they purchase from us, our revenues and cashavailable for distribution could decline.***

For the nine months ended September 30, 2006, DominionResources, Inc., Cabot Oil & Gas Corporation, ConocoPhillips and AmeradaHess Corporation accounted for approximately 60%, 10%, 8% and 3%, respectively,of our total volumes, or 81% in the aggregate. For the year ended December 31, 2005, Dominion Resources, Inc., CabotOil & Gas Corporation, UGI Energy Services, Inc., Amerada Hess Corporationand Equitable Resources, Inc. accounted for approximately 48%, 14%, 10%, 7% and6%, respectively, of our total volumes, or 85% in the aggregate.  To the extent these and other customersreduce the volumes of oil or gas that they purchase from us, our revenues andcash available for distribution could decline.

## ***Our management and Quantum Energy Partnersown, in the aggregate, a significant interest in us, with management andQuantum Energy Partners owning approximately 13.6% and 30.4%, respectively, ofour outstanding units.***

Our management and Quantum Energy Partners own orcontrol an aggregate 40.0% of our outstanding units (without giving effect tothe potential conversion of 9,185,965 non-voting Class B units into units).Accordingly, management and Quantum Energy Partners, acting together, possesssignificant voting power on substantially all matters submitted to a vote ofthe holders of our units.  Thisconcentration of ownership may have the effect of preventing or discouragingtransactions involving an actual or a potential change of control of ourcompany, regardless of whether a premium is offered over then-current marketprices.

## ***Quantum Energy Partners and othersmay sell units in the future, which could reduce the market price of ouroutstanding units.***

As of November 1, 2006, Quantum Energy Partnerscontrolled an aggregate of 10,144,585 units. In addition, we have agreed, upon demand by Quantum, to register forsale units held by Quantum Energy Partners, certain non-affiliated investorsand certain members of our management. These registration rights allow Quantum Energy Partners to request registrationof their units and to include any of those units in a registration of othersecurities by us.  If Quantum EnergyPartners were to sell a substantial portion of their units, then the marketprice of our outstanding units may decline.

We also completed a private offering of 5,534,687 unitsand 9,185,965 newly created Class B units on October 24, 2006.  In connection with the Private Placement, wealso agreed to register the units and the units underlying the class B unitswith the SEC as soon as practicable, but no later than 165 days following theclosing.  If the purchasers were to sella substantial portion of their units, then the market price of our outstandingunits may decline.

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

Not applicable.

**Item 3.****        Defaults Upon SeniorSecurities**

Not applicable.

**Item 4.****        Submission of Matters to aVote of Security Holders**

Not applicable.

**Item 5.****        Other Information**

Not applicable.

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**Item 6.****        Exhibits**

##### **EXHIBITINDEX**

| Exhibit Number | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|----------------|------------|------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|           |       |       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| 2.1            |       | —     |       | Purchase and Sale Agreement by and among Linn  Energy, LLC and Blacksand Energy, LLC, dated July 19, 2006 (incorporated  herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by  Linn Energy, LLC on July 25, 2006 (the “July 25, 2006 Form 8-K”))                                                                                                                                                                                                              |
| 2.2            |       | —     |       | Purchase and Sale Agreement between Kaiser-Francis  Oil Company and Linn Energy Mid-Continent Holdings, LLC, dated July 21, 2006  (incorporated herein by reference to Exhibit 2.2 to the July 25, 2006 Form  8-K)                                                                                                                                                                                                                                                                               |
| 3.1            |       | —     |       | Certificate of Formation of Linn Energy Holdings,  LLC (now Linn Energy, LLC) (incorporated herein by reference to  Exhibit 3.1 to the Registration Statement on Form S-1 (File  No. 333-125501) filed by Linn Energy, LLC on June 30, 2005) (the  “Form S-1”)                                                                                                                                                                                                |
| 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 the Form S-1)                                                                                                                                                                                                                                                                                                           |
| 3.3            | †     | —     |       | Second Amended and Restated Limited Liability  Company Agreement of Linn Energy, LLC                                                                                                                                                                                                                                                                                                                                                                                                             |
| 3.4            | †     | —     |       | Amendment No. 1 to Second Amended and Restated  Limited Liability Company Agreement of Linn Energy, LLC                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.1            |       | —     |       | Form of specimen unit certificate for the units of  Linn Energy, LLC (incorporated herein by reference to Exhibit 4.1 to the  Annual Report on Form 10-K filed by Linn Energy, LLC on May 31, 2006)                                                                                                                                                                                                                                                                                              |
| 4.2            |       | —     |       | Form of Class B specimen unit certificate for the  Class B units of Linn Energy, LLC (incorporated herein by reference to  Exhibit 4.2 to the Current Report on Form 8-K filed by Linn Energy, LLC on  October 24, 2006)                                                                                                                                                                                                                                                                         |
| 10.1           | *          | —     |       | Form of Linn Energy, LLC Long-Term Incentive Plan  (incorporated herein by reference to Exhibit 10.10 to Amendment  No. 4 to the Registration Statement on Form S-1 filed by Linn  Energy, LLC on December 14, 2005)                                                                                                                                                                                                                                                         |
| 10.2           | *          | —     |       | Form of Unit Option Agreement pursuant to the Linn  Energy, LLC Long-Term Inceptive Plan (incorporated herein by reference to  Exhibit 10.2 to the Current Report on Form 8-K filed by Linn  Energy, LLC on February 21, 2006)                                                                                                                                                                                                                                                    |
| 10.3           | *          | —     |       | Employment Agreement, dated effective as of July 7,  2006 between Linn Operating, Inc. and Lisa D. Anderson (incorporated herein  by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Linn  Energy, LLC on July 13, 2006)                                                                                                                                                                                                                                                    |
| 10.4           | *†    | —     |       | Linn Energy, LLC Long-Term Incentive Plan Restricted  Unit Agreement, dated effective as of July 17, 2006 between Linn Energy,  LLC and Lisa D. Anderson                                                                                                                                                                                                                                                                                                                                    |
| 10.5           | *          | —     |       | Form of Phantom Unit Grant Agreement for Independent  Directors pursuant to the Linn Energy, LLC Long-Term Incentive Plan  (incorporated herein by reference to Exhibit 10.1 to the Current Report on  Form 8-K filed by Linn Energy, LLC on August 9, 2006)                                                                                                                                                                                                                                     |
| 10.6           |       | —     |       | Second Amended and Restated Credit Agreement dated  as of August 1, 2006 among Linn Energy, LLC as Borrower, BNP Paribas, as  Administrative Agent, Royal Bank of Canada, as Syndication Agent, Societe  Generale, Comerica Bank and Citibank Texas, N.A. as Co-Documentation Agents  and the Lenders Party thereto (incorporated herein by reference to Exhibit  10.1 to the Current Report on Form 8-K filed by Linn Energy, LLC on August 7,  2006 (the “August 7, 2006 Form 8-K”)) |
| 10.7           |       | —     |       | Second Lien Bridge Loan Agreement dated as of August  1, 2006 among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative  Agent, Royal Bank of Canada, as Syndication Agent, Societe Generale, Citicorp  North America, Inc. and McDonald Investments Inc., as Co-Documentation Agents  and the Lenders Party thereto (incorporated herein by reference to Exhibit  10.2 to the August 7, 2006 Form 8-K)                                                                                 |
| 10.8           |       | —     |       | Second Amended and Restated Guaranty and Pledge  Agreement dated as of August 1, 2006 made by Linn Energy, LLC and each of the  other Obligors in favor of BNP Paribas, as Administrative Agent (incorporated  herein by reference to Exhibit 10.3 to the August 7, 2006 Form 8-K)                                                                                                                                                                                                               |
|                |            |            |            |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  |

 

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| 10.9 |   | — |   | Second Lien Guaranty and Pledge Agreement dated as  of August 1, 2006 made by Linn Energy, LLC and each of the other Obligors in  favor of BNP Paribas, as Administrative Agent (incorporated herein by  reference to Exhibit 10.4 to the August 7, 2006 Form 8-K) |
|------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 31.1 | † | — |   | Rule 13a-14(a)/15d-14(a) Certification of  Michael C. Linn, Chairman, President and Chief Executive Officer of Linn  Energy, LLC                                                                                                                              |
| 31.2 | † | — |   | Rule 13a-14(a)/15d-14(a) Certification of Kolja  Rockov, Executive Vice President and Chief Financial Officer of Linn Energy,  LLC                                                                                                                            |
| 32.1 | † | — |   | Section 1350 Certification of Michael C. Linn,  Chairman, President and Chief Executive Officer of Linn Energy, LLC                                                                                                                                           |
| 32.2 | † | — |   | Section 1350 Certification of Kolja Rockov,  Executive Vice President and Chief Financial Officer of Linn Energy, LLC                                                                                                                                         |

 

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| † |   | Filed herewith.                                                                                                                           |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------|
| *      |   | Management Contract, Compensatory Plan or  Arrangement required to be filed as an exhibit hereto pursuant to Item 601 of  Regulation S-K. |

 

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**SIGNATURE**

Pursuant to therequirements of the Securities Exchange Act of 1934, the registrant has dulycaused this report to be signed on its behalf by the undersigned, thereuntoduly authorized.
|                         | **LINN  ENERGY, LLC**                                      |
|-------------------------|------------------------------------------------------------|
|                    | (Registrant)                                               |
|                    |                                                       |
|                    |                                                       |
| Date: November 14, 2006 | /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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