** **

**UNITEDSTATES SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**Form10-Q**
| **x**  | **QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)  OF THE SECURITIES EXCHANGE ACT OF 1934**  |
|--------|-----------------------------------------------------------------------------------------------|
|   | ** **                                                                                    |
|   | **For the Quarterly Period Ended June 30, 2006**                                              |
|   | ** **                                                                                    |
| **OR** |
|   | ** **                                                                                    |
| **o**  | **TRANSITION REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |

 

**forthe transition period from                               to                             **

**CommissionFile Number: 000-51719**

**LINNENERGY, LLC**(Exact name of registrantas specified in its charter)

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

 

**650Washington Road**

**8****th Floor**

**Pittsburgh,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 accelerated  filer  o        Accelerated  filer    o      Non-accelerated  filer  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 August 1, 2006, there were 27,882,500units outstanding.

 

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** **

**TABLEOF CONTENTS**
|           | ** ** | ** **                                                                                                             | **Page**   |
|-----------|------------|------------------------------------------------------------------------------------------------------------------------|------------|
|      | ** ** | ** **                                                                                                             |       |
|      | ** ** | **Glossary of Terms**                                                                                                  | 3          |
|      | ** ** | ** **                                                                                                             |       |
|      | ** ** | **Part I - Financial  Information**                                                                                    | ** ** |
| Item 1.   |       | Financial  Statements                                                                                                  |       |
|      |       | Condensed Consolidated Balance Sheets as of June 30,  2006 (Unaudited) and December 31, 2005                 | 5          |
|      |       | Condensed Consolidated Statements of Operations for  the three and six months ended June 30, 2006 and 2005 (Unaudited) | 7          |
|      |       | Condensed Consolidated Statements of Unitholders’  Capital for the six months ended June 30, 2006 (Unaudited)     | 8          |
|      |       | Condensed Consolidated Statements of Cash Flows for  the six months ended June 30, 2006 and 2005 (Unaudited)           | 9          |
|      |       | Notes to Condensed Consolidated Financial Statements  (Unaudited)                                                      | 10         |
| Item 2.   |       | Management’s Discussion  and Analysis of Financial Condition and Results of Operations                            | 21         |
| Item 3.   |       | Quantitative  and Qualitative Disclosures About Market Risk                                                            | 33         |
| Item 4.   |       | Controls and Procedures                                                                                                | 35         |
|      | ** ** | **Part  II - Other Information**                                                                                       |       |
| Item 1.   |       | Legal Proceedings                                                                                                      | 37         |
| Item  1A. |       | Risk  Factors                                                                                                          | 37         |
| Item 2.   |       | Unregistered  Sales of Equity Securities and Use of Proceeds                                                           | 49         |
| Item 3.   |       | Defaults Upon Senior  Securities                                                                                       | 49         |
| Item 4.   |       | Submission of  Matters to a Vote of Security Holders                                                                   | 49         |
| Item 5.   |       | Other Information                                                                                                      | 49         |
| Item  6.  |       | Exhibits                                                                                                               | 50         |
|      | ** ** | **Signature**                                                                                                          | 52         |

 

 

2

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**GLOSSARYOF TERMS**

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

*Bbl.*One stock tank barrel or 42 U.S. 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.

*Bbl.*One barrel of crude oil or other liquidhydrocarbons.

*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 a natural gas or oil 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 natural gas and oil expected to be obtained through theapplication of fluid injection or other improved recovery techniques forsupplementing the natural forces and mechanisms of primary recovery areincluded in “proved developed reserves” only after testing by a pilot projector after the operation of an installed program has confirmed through productionresponse that increased recovery will be achieved.

*Proved reserves.* Proved natural gasand oil reserves are the estimated quantities of natural gas, natural gasliquids and crude oil which geological and engineering data demonstrate withreasonable certainty to be recoverable in future years from known reservoirsunder existing economic and operating conditions, i.e., prices and costs as 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 tothose drilling 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 naturalgas and/or oil 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 natural gas and/or oil 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 natural gas and oil regardless ofwhether such acreage contains proved 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.    Financial Statements**

**LINN ENERGY, LLC**

**CONDENSED CONSOLIDATED BALANCE SHEETS**
| ** **                                                                                                          | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                                                          | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                                                                                          | ** ** | **(Unaudited)**         | ** ** | ** **            | ** ** |
| ** **                                                                                                          | ** ** | **(in thousands)** | ** ** |
| **Assets**                                                                                                          |       |                    |       |                  |       |
| **Current assets:**                                                                                                 |       |                    |       |                  |       |
| Cash and cash  equivalents                                                                                          |       | $                       | 3,635      |                  | $          | 11,041 |   |
| Receivables:                                                                                                        |       |                    |       |                  |       |
| Natural gas and  oil, net of allowance for doubtful accounts of $100,000 as of June 30, 2006  and December 31, 2005 |       | 9,428                   |       | 17,103                |       |
| Other                                                                                                               |       | 332                     |       | 650                   |       |
| Fair value of  interest rate swaps                                                                                  |       | 376                     |       | 202                   |       |
| Inventory                                                                                                           |       | 212                     |       | 68                    |       |
| Current portion  of natural gas derivatives                                                                         |       | 12,041                  |       | 1,601                 |       |
| Other current  assets                                                                                               |       | 960                     |       | 4,068                 |       |
| Total current  assets                                                                                               |       | 26,984                  |       | 34,733                |       |
|                                                                                                                |       |                    |       |                  |       |
| Natural gas and  oil properties and related equipment                                                               |       | 315,264                 |       | 250,000               |       |
| Less accumulated  depreciation, depletion, and amortization                                                         |       | 18,190                  |       | 10,707                |       |
|                                                                                                                |       | 297,074                 |       | 239,293               |       |
|                                                                                                                |       |                    |       |                  |       |
| Property and  equipment, net                                                                                        |       | 5,932                   |       | 2,525                 |       |
|                                                                                                                |       |                    |       |                  |       |
| **Other assets:**                                                                                                   |       |                    |       |                  |       |
| Long-term  portion of natural gas derivatives                                                                       |       | 13,385                  |       | 2,795                 |       |
| Deferred tax assets, net                                                                                            |       | 307                     |       | —                |       |
| Operating bonds                                                                                                     |       | 197                     |       | 198                   |       |
|                                                                                                                |       | 13,889                  |       | 2,993                 |       |
| Total assets                                                                                                        |       | $                       | 343,879    |                  | $          | 279,544 |   |

 

*Theaccompanying notes are an integral part of these financial statements**.*

5

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED BALANCE SHEETS**
| ** **                                                 | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                                 | ** ** | **(Unaudited)**         | ** ** | ** **            | ** ** |
| ** **                                                 | ** ** | **(in thousands)** | ** ** |
| **Liabilities  and Unitholders’ Capital (Deficit)**   |       |                    |       |                  |       |
| **Current liabilities:**                                   |       |                    |       |                  |       |
| Current portion  of long-term notes payable                |       | $                       | 635        |                  | $          | 113 |   |
| Subordinated  term loan                                    |       | —                  |       | 59,501                |       |
| Accounts payable  and accrued expenses                     |       | 5,092                   |       | 5,572                 |       |
| Current portion  of natural gas derivatives                |       | 4,413                   |       | 12,094                |       |
| Revenue  distribution                                      |       | 1,193                   |       | 6,082                 |       |
| Accrued interest  payable                                  |       | 2,173                   |       | 1,448                 |       |
| Gas purchases  payable                                     |       | 877                     |       | 1,208                 |       |
| Other current  liabilities                                 |       | 40                      |       | 40                    |       |
| Total current  liabilities                                 |       | 14,423                  |       | 86,058                |       |
|                                                       |       |                    |       |                  |       |
| **Long-term liabilities:**                                 |       |                    |       |                  |       |
| Long-term portion  of notes payable                        |       | 2,068                   |       | 695                   |       |
| Credit facility                                            |       | 191,858                 |       | 206,119               |       |
| Long-term  portion of interest rate swaps                  |       | 90                      |       | 663                   |       |
| Asset retirement  obligation                               |       | 5,753                   |       | 5,443                 |       |
| Long-term  portion of natural gas derivatives              |       | 18,498                  |       | 27,139                |       |
| Other long-term  liabilities                               |       | 473                     |       | 258                   |       |
| Total long-term  liabilities                               |       | 218,740                 |       | 240,317               |       |
| Total  liabilities                                         |       | 233,163                 |       | 326,375               |       |
| ** **                                                 |       |                    |       |                  |       |
| **Unitholders’ capital (deficit):**                   |       |                    |       |                  |       |
| 27,832,500 units  issued and outstanding at June 30, 2006  |       | 141,355                 |       | 16,024                |       |
| Accumulated loss                                           |       | (30,639                 | )          | (62,855               | )          |
|                                                       |       | 110,716                 |       | (46,831               | )          |
| Total liabilities and  unitholders’ capital (deficit) |       | $                       | 343,879    |                  | $          | 279,544 |   |

 

*Theaccompanying notes are an integral part of these financial statements**.*

6

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF OPERATIONS**

**(Unaudited)**
| ** **                                             | ** ** | **Three months ended June 30,**                                     | ** ** | **Six months ended June 30,** | ** ** |
|--------------------------------------------------------|------------|-----------------------------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                             | ** ** | **2006**                                                                                | ** ** | **2005**                                          | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                             | ** ** | **(in thousands, except unit and per unit amounts)** | ** ** |
| **Revenues:**                                          |       |                                                                                    |       |                                              |       |   |   |   |   |
| Natural gas and  oil sales                             |       | $                                                                                       | 13,529     |                                              | $          | 7,855 |   | $ | 29,904 |   | $ | 14,001 |   |
| Realized gain  (loss) on natural gas derivatives       |       | 5,840                                                                                   |       | (8,189                                            | )          | 9,163 |   | (16,764 | ) |
| Unrealized gain  (loss) on natural gas derivatives     |       | 7,055                                                                                   |       | 1,197                                             |       | 27,978 |   | (5,383 | ) |
| Natural gas  marketing income                          |       | 1,346                                                                                   |       | 655                                               |       | 2,564 |   | 1,469 |   |
| Other income                                           |       | 204                                                                                     |       | 64                                                |       | 493 |   | 138 |   |
|                                                   |       | 27,974                                                                                  |       | 1,582                                             |       | 70,102 |   | (6,539 | ) |
| **Expenses:**                                          |       |                                                                                    |       |                                              |       |   |   |   |   |
| Operating  expenses                                    |       | 2,933                                                                                   |       | 1,488                                             |       | 5,927 |   | 3,305 |   |
| Natural gas  marketing expense                         |       | 1,189                                                                                   |       | 604                                               |       | 2,172 |   | 1,394 |   |
| General and  administrative expenses                   |       | 6,928                                                                                   |       | 670                                               |       | 16,398 |   | 1,148 |   |
| Depreciation,  depletion and amortization              |       | 4,116                                                                                   |       | 1,406                                             |       | 7,816 |   | 2,587 |   |
|                                                   |       | 15,166                                                                                  |       | 4,168                                             |       | 32,313 |   | 8,434 |   |
|                                                   |       | 12,808                                                                                  |       | (2,586                                            | )          | 37,789 |   | (14,973 | ) |
| **Other income and (expenses):**                       |       |                                                                                    |       |                                              |       |   |   |   |   |
| Interest income                                        |       | 92                                                                                      |       | 3                                                 |       | 238 |   | 3 |   |
| Interest and  financing expense                        |       | (2,696                                                                                  | )          | (2,304                                            | )          | (5,335 | ) | (2,284 | ) |
| Write-off of  deferred financing fees and other losses |       | (158                                                                                    | )          | (389                                              | )          | (550 | ) | (421 | ) |
|                                                   |       | (2,762                                                                                  | )          | (2,690                                            | )          | (5,647 | ) | (2,702 | ) |
| Income (loss) before  income taxes                     |       | 10,046                                                                                  |       | (5,276                                            | )          | 32,142 |   | (17,675 | ) |
| Income tax  benefit                                    |       | 193                                                                                     |       | —                                            |       | 74 |   | — |   |
| Net income  (loss)                                     |       | $                                                                                       | 10,239     |                                              | $          | (5,276 | ) | $ | 32,216 |   | $ | (17,675 | ) |
|                                                   |       |                                                                                    |       |                                              |       |   |   |   |   |
| Net income (loss) per  unit - basic                    |       | $                                                                                       | 0.37       |                                              | $          | (0.26 | ) | $ | 1.19 |   | $ | (0.86 | ) |
| Net income (loss) per  unit - diluted                  |       | $                                                                                       | 0.36       |                                              | $          | (0.26 | ) | $ | 1.18 |   | $ | (0.86 | ) |
| Weighted average units  outstanding - basic            |       | 27,829,863                                                                              |       | 20,518,065                                        |       | 27,055,515 |   | 20,518,065 |   |
| Weighted average units  outstanding - diluted          |       | 28,093,798                                                                              |       | 20,518,065                                        |       | 27,325,341 |   | 20,518,065 |   |
|                                                   |       |                                                                                    |       |                                              |       |   |   |   |   |
| Distributions declared per unit                        |       | $                                                                                       | 0.32       |                                              | $          | — |   | $ | 0.32 |   | $ | — |   |

 

*Theaccompanying notes are an integral part of these financial statements**.*

7

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL (DEFICIT)**

**(Unaudited)**
| ** **                                        | ** ** | **Unitholders’  Capital** | ** ** | **Accumulated  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                           |       | (8,826                         | )          | —                |       | —                              |       | (8,826                                               | )          |
| Unit-based compensation  expense                  |       | 9,796                          |       | —                |       | —                              |       | 9,796                                                |       |
| Net income                                        |       | —                         |       | 32,216                |       | —                              |       | 32,216                                               |       |
| **Balance as of June 30, 2006**                   |       | $                              | 141,355    |                  | $          | (30,639                             | )          | —                                               |       | $ | 110,716 |   |

 

*Theaccompanying notes are an integral part of these financial statements**.*

8

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS**

**(Unaudited)**
| ** **                                                                                                                | ** ** | **Six months ended June 30,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                                                                                | ** ** | **2006**                                          | ** ** | **2005** | ** ** |
| ** **                                                                                                                | ** ** | **(in thousands)**                           | ** ** |
| **Cash flow from operating  activities:**                                                                                 |       |                                              |       |   |   |
| Net income  (loss)                                                                                                        |       | $                                                 | 32,216     |   | $ | (17,675 | ) |
| **Adjustments  to reconcile net income (loss) to net cash provided by (used in) operating  activities:**                  |       |                                              |       |   |   |
| Depreciation,  depletion and amortization                                                                                 |       | 7,816                                             |       | 2,587 |   |
| Amortization of  deferred financing fees                                                                                  |       | 309                                               |       | 90 |   |
| Write-off of  deferred financing fees                                                                                     |       | 503                                               |       | 389 |   |
| Accretion of asset  retirement obligation                                                                                 |       | 119                                               |       | 57 |   |
| Unrealized  (gain) loss on natural gas and interest rate derivatives                                                      |       | (28,725                                           | )          | 5,367 |   |
| Unit-based  compensation                                                                                                  |       | 9,796                                             |       | — |   |
| Deferred income  tax                                                                                                      |       | (307                                              | )          | — |   |
| **Changes  in assets and liabilities:**                                                                                   |       |                                              |       |   |   |
| Decrease in  accounts receivable                                                                                          |       | 7,993                                             |       | 412 |   |
| (Increase)  decrease in other assets                                                                                      |       | 3,809                                             |       | (862 | ) |
| Increase  (decrease) in accounts payable and accrued expenses                                                             |       | (5,791                                            | )          | 70 |   |
| (Decrease) in  natural gas and interest rate derivatives                                                                  |       | (9,374                                            | )          | (732 | ) |
| (Decrease) in  revenue distribution                                                                                       |       | (4,889                                            | )          | (324 | ) |
| Increase in  accrued interest payable                                                                                     |       | 725                                               |       | 572 |   |
| Increase  (decrease) in gas purchases payable                                                                             |       | (331                                              | )          | 73 |   |
| Increase in  asset retirement obligation                                                                                  |       | 8                                                 |       | 15 |   |
| Increase in  other liabilities                                                                                            |       | 215                                               |       | — |   |
| Net cash  provided by (used in) operating activities                                                                      |       | 14,092                                            |       | (9,961 | ) |
| **Cash flow from investing  activities:**                                                                                 |       |                                              |       |   |   |
| Acquisition and  development of natural gas and oil properties                                                            |       | (65,079                                           | )          | (13,321 | ) |
| Purchases of  property and equipment                                                                                      |       | (1,668                                            | )          | (384 | ) |
| Obligations  related to drilling activities                                                                               |       | 971                                               |       | — |   |
| Proceeds from  sale of assets                                                                                             |       | 25                                                |       | 73 |   |
| Other investing  activities                                                                                               |       | —                                            |       | (68 | ) |
| Net cash (used  in) investing activities                                                                                  |       | (65,751                                           | )          | (13,700 | ) |
| **Cash flow from financing  activities:**                                                                                 |       |                                              |       |   |   |
| Proceeds from  sale of units                                                                                              |       | 243,149                                           |       | — |   |
| Redemption of  members’ units                                                                                        |       | (114,449                                          | )          | — |   |
| Proceeds from  notes payable                                                                                              |       | —                                            |       | 5,000 |   |
| Principal  payments on notes payable                                                                                      |       | (60,516                                           | )          | (5,279 | ) |
| Proceeds from  credit facility                                                                                            |       | 48,303                                            |       | 101,400 |   |
| Principal  payment on credit facility                                                                                     |       | (62,000                                           | )          | (75,605 | ) |
| Distribution to  members                                                                                                  |       | (8,826                                            | )          | — |   |
| Deferred  offering costs                                                                                                  |       | (844                                              | )          | (1,366 | ) |
| Deferred  financing fees                                                                                                  |       | (564                                              | )          | (165 | ) |
| Net cash  provided by financing activities                                                                                |       | 44,253                                            |       | 23,985 |   |
| Net increase  (decrease) in cash                                                                                          |       | (7,406                                            | )          | 324 |   |
| **Cash and cash equivalents:**                                                                                            |       |                                              |       |   |   |
| Beginning                                                                                                                 |       | 11,041                                            |       | 2,188 |   |
| Ending                                                                                                                    |       | $                                                 | 3,635      |   | $ | 2,512 |   |
| **Supplemental disclosure of cash  flow information:**                                                                    |       |                                              |       |   |   |
| Cash payments  for interest                                                                                               |       | $                                                 | 4,957      |   | $ | 1,690 |   |
| **Supplemental disclosure of non  cash investing and financing activities:**                                              |       |                                              |       |   |   |
| Increase in  natural gas and oil properties and related asset retirement obligation due to  acquisitions and new drilling |       | $                                                 | 184        |   | $ | 112 |   |
| Acquisition of vehicles  and equipment through issuance of notes payable                                                  |       | $                                                 | 2,097      |   | $ | — |   |

 

*Theaccompanying notes are an integral part of these financial statements**.*

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** **

**LINN ENERGY, LLC**

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS**

**(Unaudited)**

**(1) Basis of Presentation**

The condensedconsolidated financial statements at June 30, 2006, and for the three and sixmonths ended June 30, 2006 and 2005, are unaudited, but in the opinion ofmanagement include all adjustments (consisting only of normal recurringadjustments) necessary for a fair presentation of the results for the interimperiods.  Certain information and notedisclosures 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 limitedliability company in April 2005 under the laws of the State of Delaware.  The Company is an independent natural gas andoil company focused on the development and acquisition of long-lived propertiesin the United States.  We operateprimarily in the Appalachian Basin, including in West Virginia, Pennsylvania,New York and Virginia, with recentacquisitions in California and Oklahoma (see Note 3).  As of June 30, 2006, Linn’s wholly ownedsubsidiaries included Linn Energy Holdings, LLC (“Holdings”), Linn Operating,Inc. (“Operating”), Penn West Pipeline, LLC (“Penn West”), and Mid AtlanticWell Service, Inc. (“Mid Atlantic”).

***(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)******                                 Natural Gas and Oil Properties***

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

Depreciationand depletion of producing natural gas and oil properties is recorded based onunits of production.  Unit rates arecomputed for unamortized drilling and development costs using proved developedreserves and for 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 proveddeveloped reserves using the units of production method.  Asset retirement costs are estimated by theCompany’s engineers using existing regulatory requirements and anticipatedfuture inflation rates.

Geological,geophysical, and exploratory dry hole costs on natural gas and oil propertiesrelating to 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.

Naturalgas and oil 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 natural gas and oil properties by comparing netcapitalized costs to estimated undiscounted future net cash flows usingexpected prices.  If net capitalizedcosts exceed estimated undiscounted future net cash flows, the measurement ofimpairment is based on estimated fair value, which would consider estimatedfuture discounted cash flows.  Noimpairments were recorded during the three or six months ended June 30, 2006 or2005.

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 six months ended June 30, 2006 or 2005.

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

TheCompany’s estimate of proved reserves is based on the quantities of natural gasand oil 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 economicevaluation of 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 madeconcurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flowsderived from 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 oileventually 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 assetsand liabilities 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 June 30, 2006 andDecember 31, 2005, respectively.  At June30, 2006, deferred tax assets of approximately $0.3 million, net of avaluation allowance of $1.2 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 natural gas production by reducing its exposureto price fluctuations.  As of June 30,2006, these transactions were in the form of swaps and puts.  Additionally, the Company uses derivativefinancial instruments in the form of interest

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rateswaps to mitigate its interest rate exposure. The Company accounts for its derivatives at fair value as an asset orliability and the change in the fair value of derivatives is included inincome.

***(h)******                                 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.  For the three and six months ended June 30,2006, all unit options outstanding were excluded in the computation of dilutedearnings per unit, because to do so would have been antidilutive for the periods.For the three and six months ended June 30, 2006, the effect of unvestedunits awarded but not issued to the Chief Executive Officer were included inthe computation of diluted earnings per unit. The dilutive effect of these unitequivalents was 263,935 units and 269,826 units, for a total of 28,093,798 and27,325,341 diluted units outstanding for the three and six months ended June 30,2006, respectively.

***(i)******                                    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 ofnatural gas and oil reserves, future cash flows from natural gas and oilproperties, depreciation, depletion and amortization, asset retirementobligations, the fair value of derivatives and unit awards.

***(j)******                                    Revenue Recognition***

Salesof natural gas and oil are recognized when natural gas has been delivered to acustody transfer point, persuasive evidence of a sales arrangement exists, therights and responsibility of ownership pass to the purchaser upon delivery,collection of revenue from the sale is reasonably assured, and the sales priceis fixed or determinable.  Natural gas issold by the Company on a monthly basis. Virtually all of the Company’s contracts’ pricing provisions are tied toa market index, with certain adjustments based on, among other factors, whethera well delivers to a gathering or transmission line, quality of natural gas,and prevailing supply and demand conditions, so that the price of the naturalgas fluctuates to remain competitive with other available natural gas supplies.  As a result, the Company’s revenues from thesale of natural gas will suffer if market prices decline and benefit if theyincrease.  The Company believes that thepricing provisions of its natural gas contracts are customary in 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 June 30, 2006 or December 31, 2005.

Naturalgas marketing is recorded on the gross accounting method because Penn West, theCompany’s marketing subsidiary, takes title to the natural gas it purchasesfrom the various producers and bears the risks and enjoys the benefits of thatownership.  Natural gas marketingrevenues and natural gas marketing expense, titled as such, are reported on theconsolidated statement of operations for the three and six months ended June30, 2006 and 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 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 six months ended June 30, 2006, the operating fees netted against generaland administrative expense were approximately $352,000 and $636,000respectively.  For the three and sixmonths ended June 30, 2005, the operating fees netted against general andadministrative expense were approximately $222,000 and $509,000, respectively.

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

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

***(l)******                                    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 in securitizedfinancial assets to identify interests that are freestanding derivatives orthat are hybrid financial instruments that contain an embedded derivativerequiring bifurcation.  The standard iseffective for all financial instruments acquired or issued after the beginningof an entity’s first fiscal year that begins after September 15, 2006.  The Company is currently evaluating theeffect that the adoption of SFAS 155 will have on its results of operations andfinancial condition, but does 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.

**(3) Acquisitions**

In the second quarter of2006, the Company purchased from the owners of property operated by DevonianGas Production, Inc., Excel Energy, Inc. and T&F Exploration LP, a total of200 producing wells and tangible wellhead equipment in West Virginia, for anaggregate purchase price of approximately $27.5 million, subject to customary post-closingadjustments.  Also in the second quarterof 2006, the Company purchased a natural gas gathering pipeline system inwestern Pennsylvania for approximately $0.8 million.

InAugust 2006, the Company acquired certain affiliated entities of BlacksandEnergy, LLC ("Blacksand Assets"), located in the Los Angeles Basin,for approximately $291.0 million and certain Mid-Continent assets ofKaiser-Francis Oil Company ("Kaiser Assets") located in Oklahoma forapproximately $125.0 million, in both cases subject to customary post-closing adjustments.  Theacquisitions of the Kaiser Assets and Blacksand Assets 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).

**(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 approximately $18.3 million andoffering expenses of $4.3 million, of approximately $238.8 million, of which$122.0 million was used to reduce indebtedness under the Company’s revolvingcredit facility and repay, in full, the subordinated term loan, 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.

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**(5)  Natural Gas and Oil Properties**
| ** **                                                 | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                                 | ** ** | **(in thousands)** | ** ** |
| Unproved  properties                                       |       | $                       | 4,964      |                  | $          | 4,562 |   |
| Proved developed  properties:                              |       |                    |       |                  |       |
| Acquisition, equipment and drilling                        |       | 303,525                 |       | 239,858               |       |
| Pipelines                                                  |       | 6,775                   |       | 5,580                 |       |
|                                                       |       | 315,264                 |       | 250,000               |       |
|                                                       |       |                    |       |                  |       |
| Less accumulated  depletion, depreciation and amortization |       | (18,190                 | )          | (10,707               | )          |
|                                                       |       |                    |       |                  |       |
|                                                       |       | $                       | 297,074    |                  | $          | 239,293 |   |

 

**(6) Debt**

***Credit Facility***

AtJune 30, 2006 the Company had a $400.0 million credit facility, with a maturityof April 2009, with the amount available for borrowing at any one time limitedto a borrowing base of $265.0 million. In August 2006, in connection with the acquisitions of the BlacksandAssets and the Kaiser Assets (see Note 3), the Company entered into anincremental senior secured revolving credit facility and extended the maturityto August 2010 (“Credit Facility”), including an increase in the facility to$800.0 million and an increase in the borrowing base to $480.0 million.  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 natural gas and oilprices at such time.  Our obligationsunder the Credit Facility are secured by mortgages on our natural gas and oilproperties as well as a pledge of all ownership interests in our operatingsubsidiaries.  We are required tomaintain the mortgages on properties representing at least 80% of our naturalgas and oil properties.  Additionally,the obligations under the Credit Facility are guaranteed by all of ouroperating subsidiaries 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 increase by 0.25%while the subordinated bridge loan is outstanding.  Interest is generally payable quarterly fordomestic bank rate loans and at the applicable maturity date for LIBOR loans.

TheCredit Facility contains various covenants that limit the Company’s ability toincur additional indebtedness, make acquisitions or certain capitalexpenditures; make distributions other than from available cash; merge orconsolidate; and engage in certain asset dispositions.  The Credit Facility also contains covenantsthat, among other things, require us to maintain specified financial ratios,including a ratio of earnings before interest, taxes, depreciation andamortization (“EBITDA”) of 2.0 to 1.0 while the subordinated bridge loan (seebelow) is outstanding.  The Company is incompliance with all financial and other covenants of its Credit Facility.

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As of June 30, 2006 and December 31, 2005, the creditfacility consisted of the following:
| ** **                                                                  | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                  | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                                                  | ** ** | **(in thousands)** | ** ** |
| Outstanding  balance                                                        |       | $                       | 193,000    |                  | $          | 207,000 |   |
| Less deferred  financing fees, net of amortization of $463,000 and $160,000 |       | (1,142                  | )          | (881                  | )          |
|                                                                        |       |                    |       |                  |       |
|                                                                        |       | $                       | 191,858    |                  | $          | 206,119 |   |

 

Totalaccrued interest on the credit facility and the subordinated term loan (seebelow) was approximately $2.2 million and $1.4 million at June 30, 2006 andDecember 31, 2005, respectively.

***Subordinated Bridge Loan***

InAugust 2006, in order to fund a portion of the acquisitions of the BlacksandAssets and the Kaiser Assets, we entered into a $250.0 million subordinatedbridge loan (“Subordinated Bridge Loan”) with a termination of August 1,2007.  Financial covenants under theSubordinated Bridge Loan are substantially similar to those under the CreditFacility.  At our election, interest isdetermined by reference to LIBOR plus an applicable margin of 4.00% per annum;or a domestic bank 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.

***SubordinatedTerm Loan***

During 2005, the Companyhad a facility for a $60.0 million second lien senior subordinated termloan.  The borrowings under thesubordinated term loan were used to fund a portion of the purchase price forthe acquisition of natural gas and oil properties from Exploration Partners.  The outstanding balance was paid in full inJanuary 2006 with proceeds from our IPO.

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

TheCompany has the following long-term notes payable outstanding:
| ** **                                                                                                                                                                                                                                                                                                                                                                      | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                                                                                                                                                                                                                                      | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                                                                                                                                                                                                                                                                                                                                                                      | ** ** | **(in thousands)** | ** ** |
| Note payable to  a bank with an interest rate of 6.14%, payable in monthly installments of  approximately $3,000, including interest, through September 2024. The note is  secured by an office building                                                                                                                                                                        |       | $                       | 381        |                  | $          | 387 |   |
| Various notes  for the purchase of vehicles and equipment, payable in monthly installments  totaling approximately $63,000 and $11,000, as of June 30, 2006 and December  31, 2005, respectively, including interest. The interest rates range from  0-8.87%. The notes are secured by the vehicles and equipment purchased and  expire at various dates from 2008 through 2011 |       | 2,322                   |       | 421                   |       |
|                                                                                                                                                                                                                                                                                                                                                                            |       | 2,703                   |       | 808                   |       |
|                                                                                                                                                                                                                                                                                                                                                                            |       |                    |       |                  |       |
| Less current  portion                                                                                                                                                                                                                                                                                                                                                           |       | (635                    | )          | (113                  | )          |
|                                                                                                                                                                                                                                                                                                                                                                            |       | $                       | 2,068      |                  | $          | 695 |   |

 

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As of June 30, 2006, maturitieson the aforementioned long-term notes payable were as follows:
| **June 30:** | ** ** | **(in thousands)** | ** ** |
|-------------------|------------|-------------------------|------------|
| 2006              |       | $                       | 635        |   |
| 2007              |       | 856                     |       |
| 2008              |       | 333                     |       |
| 2009              |       | 329                     |       |
| 2010              |       | 237                     |       |
| Thereafter        |       | 313                     |       |
|              |       | $                       | 2,703      |   |

 

**(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 natural gas and oil productionwithin the Appalachian 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.

The Company’s largestcustomers are natural gas producers and suppliers located within theAppalachian region.  For the three andsix months ended June 30, 2006, the Company’s two largest customers representedapproximately 65% and 9%, and 68% and 10%, respectively, of the Company’ssales.  The Company’s three largestcustomers represented approximately 28%, 23%, and 17%, and 30%, 19% and 18%, ofthe Company’s sales for the three and six months ended June 30, 2005,respectively.

At June 30, 2006, twocustomers’ trade accounts receivable from natural gas sales accounted for morethan 10% of the Company’s total trade accounts receivable.  At June 30, 2006, trade accounts receivablefrom these customers represented approximately 64%, and 15% of the Company’sreceivables.  At December 31, 2005, twocustomers’ trade accounts receivable from natural gas sales accounted for morethan 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.

Our 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 unitholderapproval as required by the exchange upon which the units are listed at thattime.  However, no change in anyoutstanding grant may be made that would materially reduce the benefits to theparticipant without the consent of the participant.

Upon exercise or 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

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we issue new units uponexercise or vesting of an award of, or settled in, units, the total number ofunits outstanding will increase.  Theplan provides 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 the equityappreciation of our units.  Therefore,plan participants will not pay any consideration for the units theyreceive.  If a grantee’s employment,consulting relationship or membership on the Board of Directors terminates forany reason, the grantee’s restricted units will be automatically forfeitedunless the compensation committee or the terms of the award agreement provideotherwise.

*Phantom Units/Unit AppreciationRights* These awards may be settled in units, cash or a combinationthereof.  Such grants will contain termsas determined by the compensation committee, including the period or terms overwhich phantom units will vest.  If agrantee’s employment or service relationship terminates for any reason, thegrantee’s phantom units or unit appreciation rights will be automaticallyforfeited unless, and to the extent, the compensation committee or the terms ofthe award agreement provide otherwise. While phantom units require no payment from the grantee, unitappreciation rights will have an exercise price that will not be less than thefair market value of the units on the date of grant.

*SecuritiesAuthorized for Issuance Under the Plan*

As of June 30, 2006,approximately 1.5 million units were issuable under the Plan pursuant tooutstanding award or other agreements and an additional 2.4 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,the fair 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 sixmonths ended June 30, 2006, we recorded unit-based compensation expense ofapproximately $4.2 million and $9.9 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-based compensationfor the three and six months ended June 30, 2005, as there were no unit-basedawards granted during those periods.

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*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 June 30, 2006, and changes during the sixmonths ended June 30, 2006, is presented below:
| ** **                             | ** ** | ** **         | ** ** | **Weighted**        | ** ** |
|----------------------------------------|------------|--------------------|------------|---------------------|------------|
| ** **                             | ** ** | **Number of** | ** ** | **Average**         | ** ** |
| ** **                             | ** ** | **Non-vested**     | ** ** | **Grant-Date**      | ** ** |
| ** **                             | ** ** | **Units**          | ** ** | **Fair Value** | ** ** |
| Non-vested units  at December 31, 2005 |       | —             |       | $                   | —     |   |
| Granted                                |       | 989,145            |       | 21.23               |       |
| Vested                                 |       | (114,455           | )          | 21.00               |       |
| Forfeited                              |       | —             |       | —              |       |
|                                   |       |               |       |                |       |
| Non-vested units at  June 30, 2006     |       | 874,690            |       | $                   | 21.26      |   |

 

As of June 30, 2006,there was approximately $11.4 million of unrecognized compensation cost relatedto non-vested restricted units.  The costis expected to be recognized over a weighted average period of approximately0.8 years.

*Changesin Unit Options and Unit Options Outstanding*

The following tableprovides information related to unit option activity for the six months endedJune 30, 2006:
| ** **                        | ** ** | **Number**        | ** ** | **Weighted**            | ** ** | **Weighted**        | ** ** | **Weighted**                | ** ** |
|-----------------------------------|------------|-------------------|------------|-------------------------|------------|---------------------|------------|-----------------------------|------------|
| ** **                        | ** ** | **Units of** | ** ** | **Average**             | ** ** | **Average**         | ** ** | **Average**                 | ** ** |
| ** **                        | ** ** | **Underlying**    | ** ** | **Exercise Price** | ** ** | **Grant Date** | ** ** | **Contractual**             | ** ** |
| ** **                        | ** ** | **Options**       | ** ** | **Per Unit**       | ** ** | **Fair Value** | ** ** | **Life in Years** | ** ** |
| Outstanding at  December 31, 2005 |       | —            |       | $                       | —     |                | $          | —                      |       | — |   |
| Granted                           |       | 531,084           |       | 20.57                   |       | 3.04                |       | 10.00                       |       |
| Exercised                         |       | —            |       | —                  |       | —              |       | —                      |       |
| Vested                            |       | —            |       | —                  |       | —              |       | —                      |       |
| Forfeited                         |       | (41,750           | )          | 20.18                   |       | 2.52                |       | 10.00                       |       |
|                              |       |              |       |                    |       |                |       |                        |       |
| Outstanding at  June 30, 2006     |       | 489,334           |       | $                       | 20.60      |                | $          | 3.09                        |       | 10.00 |   |
|                              |       |              |       |                    |       |                |       |                        |       |
| Exercisable at June 30,  2006     |       | 30,000            |       | $                       | 20.18      |                | $          | 2.52                        |       | 10.00 |   |

 

As of June 30, 2006,there was approximately $1.1 million of total unrecognized compensation costrelated to non-vested unit options.  Thecost is expected to be recognized over a weighted average period ofapproximately 1.7 years.  In addition,the exercisable unit options at June 30, 2006 have an aggregate intrinsic valueof approximately $23,000 and all outstanding unit options have an aggregateintrinsic value of approximately $184,000. No options expired during the period.

Subsequent to June 30,2006, the Company granted an aggregate 50,000 unit options and 50,000restricted units to an executive officer. Subsequent to June 30, 2006, the Company granted an aggregate 9,000phantom units to independent members of the Board of Directors.

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.  TheCompany’s determination of fair value of unit-based payment awards is affectedby the Company’s unit price as well as assumptions regarding a number of highlycomplex and subjective variables. The Company’s employee unit options have various restrictions includingvesting provisions and restrictions on transfers and hedging, among others, andoften are expected to be exercised prior to their contractual maturity.  Expected volatilities used in the estimationof fair value have been determined using available volatility data for theCompany as well as an average of volatility computations of other identifiedpeer companies in the oil and gas industry. The Company uses historical data to estimate unit option exercises,expected term and forfeitures used in the 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:

18

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| Expected  volatility      |   | 29.70-30.40 | %      |
|---------------------------|--------|-------------|--------|
| Expected  dividends       |   | 7.20%-8.10  | %      |
| Expected term  (in years) |   | 5.00        |   |
| Risk free rate            |   | 4.31%-4.97  | %      |
| 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.

**(10) Property and Equipment**

Propertyand equipment consists of the following:
| ** **                            | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2006**                | ** ** | **2005**              | ** ** |
| ** **                            | ** ** | **(in thousands)** | ** ** |
| Land                                  |       | $                       | 308        |                  | $          | 203 |   |
| Buildings and  leasehold improvements |       | 1,194                   |       | 608                   |       |
| Vehicles                              |       | 2,277                   |       | 1,317                 |       |
| Drilling equipment not yet in service |       | 1,749                   |       | —                |       |
| Furniture and  equipment              |       | 1,192                   |       | 888                   |       |
|                                  |       | 6,720                   |       | 3,016                 |       |
|                                  |       |                    |       |                  |       |
| Less:  accumulated depreciation       |       | (788                    | )          | (491                  | )          |
|                                  |       |                    |       |                  |       |
|                                  |       | $                       | 5,932      |                  | $          | 2,525 |   |

 

Depreciation expense for the three and six monthsended June 30, 2006 was approximately $201,000 and $354,000, respectively.  Depreciation expense for the three and sixmonths ended June 30, 2005 was approximately $71,000 and $124,000 respectively.

**(11) Commitments and Contingencies**

TheCompany would be exposed to natural gas price fluctuations on underlying salecontracts should the counterparties to the Company’s derivative instruments orthe counterparties to the Company’s natural gas marketing contracts notperform. Such nonperformance is not anticipated.  There were no counterparty default lossesduring the three and six months ended June 30, 2006 or 2005.

Fromtime to time the Company is a party to various legal proceedings in theordinary course of business.  The Companyis not currently a party to any litigation that it believes would have amaterially adverse effect on the Company’s business, financial condition,results of operations or liquidity.

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**(12) Natural Gas Derivatives**

TheCompany sells natural gas in the normal course of its business and utilizesderivative instruments to minimize the variability in forecasted cash flows dueto price movements in natural gas.  TheCompany enters into derivative instruments such as swap contracts and putoptions to hedge a portion of its forecasted natural gas sales.

Settledderivatives on production for the three and six months ended June 30, 2006included a volume of 4,054 MMMBtu and 2,035 MMMBtu at an average price of $9.22and $9.22, respectively.  Currently, weuse fixed price swaps and puts to manage commodity prices.  These transactions are settled based upon theNYMEX price of natural gas at Henry Hub on the final trading day of the month,and settlement occurs on the third day of the production month.  The following table summarizes open positionsas of June 30, 2006 and represents, as of such date, our derivatives in placethrough December 31, 2009:
|                          | ** ** | **July 1 –  December 31,  2006** | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** |
|--------------------------|------------|------------------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|
|                     |       |                                                 |       |           |       |           |       |           |       |
| Fixed Price Swaps:       |       |                                                 |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)  |       | 3,720                                                |       | 7,168          |       | 8,464          |       | 6,205          |       |
| Average Price  ($/MMBtu) |       | $                                                    | 9.25       |           | $          | 8.64           |       | $              | 8.23       |   | $ | 7.56 |   |
| Puts:                    |       |                                                 |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)  |       | 368                                                  |       | 2,336          |       | 2,013          |       | —         |       |
| Average Price  ($/MMBtu) |       | $                                                    | 8.83       |           | $          | 9.11           |       | $              | 9.50       |   | — |   |
| Total:                   |       |                                                 |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)  |       | 4,088                                                |       | 9,504          |       | 10,477         |       | 6,205          |       |
| Average Price ($/MMBtu)  |       | $                                                    | 9.21       |           | $          | 8.75           |       | $              | 8.47       |   | $ | 7.56 |   |

 

Thenatural 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:

|                                                  | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
|--------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **2006**          | ** ** | **2005**              | ** ** |
| ** **                                       | ** ** | ** **        | ** ** | ** **            | ** ** |
| Outstanding notional  amounts of hedges (MMMBtu) |       | 30,274            |       | 28,069                |       |
| Maximum number of months hedges outstanding      |       | 42                |       | 48                    |       |

 

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 sixmonths ended June 30, 2006, the Company made payments of approximately $182,000and $242,000, respectively, to a company owned by one of our seniorexecutives.  The payments reflectreimbursement for maintenance and hourly usage fees for business use oftransportation services and an asset which is partially owned by the seniorexecutive.  These costs are included ingeneral and administrative expense on the consolidated statement ofoperations.  The transactions wereconsummated on terms equivalent to those that prevail in arm’s-lengthtransactions.

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**Item 2.    Management’s Discussion andAnalysis of Financial Condition and Results of Operations**

**Results of Operations - ExecutiveSummary**

***Acquisitions andStrategy***

We are an independent natural gas and oil company focusedon the development and acquisition of long-lived properties in the UnitedStates.  We operate primarily in theAppalachian Basin, including in West Virginia, Pennsylvania, New York andVirginia, with recent acquisitions in California and Oklahoma.  Our goal is to provide stability and growthin distributions to our unitholders through a combination of continuedsuccessful drilling and acquisitions. Our company was formed in March 2003. In 2006, we completed our initial public offering of 12,450,000 units ata price of $21.00 per unit, for net proceeds after underwriting discounts andoffering expenses of approximately $238.8 million, of which $122.0 million wasused to reduce indebtedness under the Company’s revolving credit facility andrepay, in full, the subordinated term loan, approximately $114.4 million wasused to redeem a portion of the membership interests in the Company and unitsheld by certain affiliated and non-affiliated holders and approximately $2.0million was used to pay bonuses to certain executive officers of the Company.

From inception through June 30, 2006, we had completed 12acquisitions of natural gas properties and related gathering and pipelineassets for an aggregate purchase price of approximately $229.0 million, withtotal proved reserves of 177.6 Bcfe, or an acquisition cost of $1.29 per Mcfe.
| **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                |       |
|           |       |                                     |       |            |       |                       |       |                |       |
|           | ** ** | **Total  **                    |       | 2,114           |       |                       |       | $                   | 229.0      |   |

 

In August 2006, theCompany acquired certain affiliated entities of Blacksand Energy, LLC (“BlacksandAssets”), located in the Los Angeles Basin, for approximately $291.0 millionand certain Mid-Continent assets of Kaiser-Francis Oil Company (“Kaiser Assets”)located in Oklahoma for approximately $125.0 million, in both cases subject tocustomary post-closing adjustments.

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. Natural gas and oil prices historically have been volatile and mayfluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materiallyand adversely affect our financial position, our results of operations, thequantities of natural gas and oil reserves that we can economically produce andour access to capital.

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

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rentals are charged toexpense as incurred.  Drilling costs aretypically capitalized, but charged to expense if an exploratory well isdetermined to be unsuccessful.

Highernatural gas and oil prices have led to higher demand for drilling rigs,operating personnel and field supplies and services and have caused increasesin the costs of those goods and services. The Company performs certain activities in connection with its drillingof oil and gas wells, which includes preparing and clearing well sites,providing drilling engineers, roustabouts and other personnel necessary fordrilling.  The Company has received itsfirst drilling rig and has two additional rigs ordered, which will reduce oreliminate reliance on contract rigs.  Todate, the higher sales prices have more than offset the higher drilling andoperating costs.  Given the inherentvolatility of natural gas prices, which are influenced by many factors beyondour control, we plan our activities and budget based on conservative salesprice assumptions, which generally are lower than the average sales pricesultimately realized.  We focus ourefforts on increasing natural gas reserves and production while controllingcosts at a level that is appropriate for long-term operations.  Our future cash flow from operations isdependent on our ability to manage our overall cost structure.

We face the challenge ofnatural production declines.  As initialreservoir pressures are depleted, natural 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 costs to add 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 revenuesare highly sensitive to changes in natural gas prices and levels of production.  As of June 30, 2006, we have hedged asignificant portion of our expected production using natural gas derivatives,which allows us to mitigate, but not eliminate, commodity price risk.  Our expected increase in levels of productionas a result of the anticipated drilling of 153 wells during 2006 is dependenton our ability to quickly and efficiently bring the newly drilled wellsonline.  Any delays in drilling,completion or connection to gathering lines of our new wells will negativelyimpact the rate of increase in our production, which may have an adverse effecton our revenues and as a result, cash available for distribution.  We continuously conduct financial sensitivityanalyses to assess the effect of changes in pricing and production. These analysesallow us to determine how changes in natural gas prices will affect the abilityto drill additional wells and to meet future financial obligations.  Further, the financial analyses allow us tomonitor any impact such changes in natural gas prices may have on the value ofour proved reserves and their impact, if any, on any redetermination of theborrowing base under our credit facility. See Item 3. “Qualitative and Quantitative Disclosures About Market Risk”for derivatives entered into subsequent to June 30, 2006, in connection withour acquisition of the Blacksand Assets.

***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.

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**Results of Operations - Three MonthsEnded June 30, 2006 Compared to Three Months Ended June 30, 2005**

The following table sets forthselected financial data for the periods indicated:
|                                                  | ** ** | **Three Months Ended  June 30,** | ** ** | ** ** | ** ** |
|--------------------------------------------------|------------|-------------------------------------------------|------------|------------|------------|
| ** **                                       | ** ** | **2006**                                        | ** ** | **2005**   | ** ** | **Variance** | ** ** |
| ** **                                       | ** ** | **(in thousands)**                         | ** ** |
| ** **                                       | ** ** | **(Unaudited)**                                 | ** ** |
| **Revenues:**                                    |       |                                            |       |       |       |   |   |
| Natural gas and  oil sales                       |       | $                                               | 13,529     |       | $          | 7,855 |   | $ | 5,674 |   |
| Realized gain  (loss) on natural gas derivatives |       | 5,840                                           |       | (8,189     | )          | 14,029 |   |
| Unrealized gain  on natural gas derivatives      |       | 7,055                                           |       | 1,197      |       | 5,858 |   |
| Natural gas  marketing income                    |       | 1,346                                           |       | 655        |       | 691 |   |
| Other income                                     |       | 204                                             |       | 64         |       | 140 |   |
| Total revenue                                    |       | 27,974                                          |       | 1,582      |       | 26,392 |   |
| **Expenses:**                                    |       |                                            |       |       |       |   |   |
| Operating  expenses                              |       | $                                               | 2,933      |       | $          | 1,488 |   | $ | 1,445 |   |
| Natural gas  marketing expense                   |       | 1,189                                           |       | 604        |       | 585 |   |
| General and  administrative expenses             |       | 6,928                                           |       | 670        |       | 6,258 |   |
| Depreciation,  depletion and amortization        |       | 4,116                                           |       | 1,406      |       | 2,710 |   |
| Total expenses                                   |       | 15,166                                          |       | 4,168      |       | 10,998 |   |
| **Other Income and (Expenses):**                 |       |                                            |       |       |       |   |   |
| Interest and financing  expense                  |       | $                                               | (2,696     | )          | $          | (2,304 | ) | $ | (392 | ) |

 

The following table sets forthselected operating data for the periods indicated:
|                                                     | ** ** | **Three Months Ended  June 30,** | ** ** | **Percentage  Increase** | ** ** |
|-----------------------------------------------------|------------|-------------------------------------------------|------------|--------------------------|------------|
| ** **                                          | ** ** | **2006**                                        | ** ** | **2005**                 | ** ** | **(Decrease)** | ** ** |
| ** **                                          | ** ** | ** **                                      | ** ** |
| **Net Production:**                                 |       |                                            |       |                     |       |   |   |
| Total production  (MMcfe)                           |       | 1,956                                           |       | 1,103                    |       | 77.3 | % |
| Average daily  production (Mcfe/d)                  |       | 21,500                                          |       | 12,200                   |       | 76.2 | % |
|                                                |       |                                            |       |                     |       |   |   |
| **Average Sales Prices:**                           |       |                                            |       |                     |       |   |   |
| Weighted average  realized natural gas price (Mcfe) |       | $                                               | 9.90       |                     | $          | 6.19 |   | 59.9 | % |
|                                                |       |                                            |       |                     |       |   |   |
| **Average Unit Costs per Mcfe  (Non-GAAP):**        |       |                                            |       |                     |       |   |   |
| Operating  expenses                                 |       | $                                               | 1.50       |                     | $          | 1.35 |   | 11.1 | % |
| General and  administrative expenses (1)            |       | $                                               | 1.40       |                     | $          | 0.61 |   |   | * |
| Depreciation, depletion  and amortization           |       | $                                               | 2.10       |                     | $          | 1.27 |   | 65.4 | % |

----

(1)  This is a non-GAAP performance measure usedby our management and is a quantitative measure used in the natural gas and oilindustry.  The measure for the threemonths ended June 30, 2006 excludes approximately $4.2 million of unit-basedcompensation expense primarily resulting from January 2006 awards tocertain executive officers in connection with our IPO.  General and administrative expenses includingthese amounts were $3.54 per Mcfe for the three months ended June 30, 2006.

*  Amount is greater than 100%, therefore is notmeaningful.

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***Revenue***

Natural gasand oil sales increased to approximately $13.5 million from $7.9 million duringthe three months ended June 30, 2006 as compared to the three months ended June30, 2005.

The increase in revenue from natural gas and oil saleswas attributable primarily to the increase in production to 1,956 MMcfe duringthe three months ended June 30, 2006 from 1,103 MMcfe during the three monthsended June 30, 2005, the three acquisitions completed in 2005, and the drillingof 84 wells during 2006 (through June 30) and 110 wells in 2005.  In addition to the increase in production,the average natural gas sales price increased during the three months endedJune 30, 2006, as compared to the three months ended June 30, 2005.

***HedgingActivities***

During thethree months ended June 30, 2006, we have effectively hedged 95% of our naturalgas production, which resulted in revenues that were $5.8 million greater thanwe would have achieved at unhedged prices. During the three months ended June 30, 2005, we hedged approximately100% of our natural gas production, which resulted in revenues that were $8.2million less than we would have achieved at unhedged prices.  Unrealized gains on derivatives in theamounts of $7.1 million and $1.2 million for the three months ended June 30,2006 and 2005, respectively, were also recorded.  Unrealized gains and losses result fromnatural gas price fluctuations as compared to the settlement price on thederivative.

***Expenses***

Operatingexpenses consist 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 $2.9 million for the three months ended June 30, 2006 from$1.5 million for the three months ended June 30, 2005, due to the increase inthe number of wells as a result of the three acquisitions completed in both2006 and in 2005 and the drilling of 84 wells during 2006 (through June 30) and110 wells during 2005.

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 $6.9 million from $0.7million during the three months ended June 30, 2006 as compared to the threemonths ended June 30, 2005.  General andadministrative expenses are presented net of approximately $0.4 million and$0.2 million, during the three months ended June 30, 2006 and 2005,respectively, which represent operating 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 June 30,2006, to our rapidly growing operations and increasing our staffing level tomanage the additional wells acquired and drilled in 2006 and 2005, and toperform the functions associated with being a public company.

Depreciation,depletion and amortization increased to $4.1 million for the three months endedJune 30, 2006 from $1.4 million for the three months ended June 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 June 30, 2006and 2005, the Company capitalized approximately $0.6 million and $0.4 million,respectively, of internal costs related to drilling.

Interest andfinancing income (expense) was a net expense of $2.7 million for the threemonths ended June 30, 2006 as compared to a net expense of $2.3 million for thethree months ended June 30, 2005.  Ourinterest rate swaps were not specifically designated as hedges under SFAS 133,even though they reduce our exposure to changes in interest rates.  Therefore, the mark-to-market of theseinstruments was recorded as a gain of $0.3 million and loss of $0.9 million forthe three months ended June 30, 2006 and 2005, respectively.  Further, these amounts represent non-cashcharges.  Cash payments for interestexpense increased to $1.6 million for the three months ended June 30, 2006 from$0.4 million for the three months ended June 30, 2005, primarily due toincreased debt levels associated with the acquisitions completed and thedrilling of wells during the 2006 and 2005.

Income taxwas a benefit of approximately $193,000 for the three months ended June 30,2006, resulting from the recognition of deferred tax assets arising from netoperating losses which are expected to be realized to the extent of deferredtax liabilities arising from bases differences in property and equipment.  Deferred tax assets exceeding deferred taxliabilities of

24

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$0.3 millionhave been offset by an increase in the valuation allowance during the threemonths ended June 30, 2006.  Because wewere structured as a limited liability company through May 31, 2005, notax provision was recorded during the three months ended June 30, 2005 becauseall of our taxable income or loss is reportable in the income tax returns ofthe members.  On June 1, 2005, LinnOperating, LLC (predecessor to Linn Operating, Inc.) converted to subchapterC-corporation status and on November 1, 2005, Mid Atlantic Well Service, Inc.,one of our subsidiaries, commenced operations. Income tax benefit and expense relates to the income attributable tothose entities.

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**Results of Operations - Six Months EndedJune 30, 2006 Compared to Six Months Ended June 30, 2005**

The following table sets forthselected financial data for the periods indicated:
|                                                    | ** ** | **Six Months Ended  June 30,** | ** ** | ** ** | ** ** |
|----------------------------------------------------|------------|-----------------------------------------------|------------|------------|------------|
| ** **                                         | ** ** | **2006**                                      | ** ** | **2005**   | ** ** | **Variance** | ** ** |
| ** **                                         | ** ** | **(in thousands)**                       | ** ** |
| ** **                                         | ** ** | **(Unaudited)**                               | ** ** |
| **Revenues:**                                      |       |                                          |       |       |       |   |   |
| Natural gas and  oil sales                         |       | $                                             | 29,904     |       | $          | 14,001 |   | $ | 15,903 |   |
| Realized gain  (loss) on natural gas derivatives   |       | 9,163                                         |       | (16,764    | )          | 25,927 |   |
| Unrealized gain (loss)  on natural gas derivatives |       | 27,978                                        |       | (5,383     | )          | 33,361 |   |
| Natural gas  marketing income                      |       | 2,564                                         |       | 1,469      |       | 1,095 |   |
| Other income                                       |       | 493                                           |       | 138        |       | 355 |   |
| Total revenue                                      |       | 70,102                                        |       | (6,539     | )          | 76,641 |   |
| **Expenses:**                                      |       |                                          |       |       |       |   |   |
| Operating  expenses                                |       | $                                             | 5,927      |       | $          | 3,305 |   | $ | 2,622 |   |
| Natural gas  marketing expense                     |       | 2,172                                         |       | 1,394      |       | 778 |   |
| General and  administrative expenses               |       | 16,398                                        |       | 1,148      |       | 15,250 |   |
| Depreciation,  depletion and amortization          |       | 7,816                                         |       | 2,587      |       | 5,229 |   |
| Total expenses                                     |       | 32,313                                        |       | 8,434      |       | 23,879 |   |
| **Other Income and (Expenses):**                   |       |                                          |       |       |       |   |   |
| Interest and financing  expense                    |       | $                                             | (5,335     | )          | $          | (2,284 | ) | $ | (3,051 | ) |

 

The following table sets forth selectedoperating data for the periods indicated:
|                                                     | ** ** | **Six Months Ended  June 30,** | ** ** | **Percentage  Increase** | ** ** |
|-----------------------------------------------------|------------|-----------------------------------------------|------------|--------------------------|------------|
| ** **                                          | ** ** | **2006**                                      | ** ** | **2005**                 | ** ** | **(Decrease)** | ** ** |
| ** **                                          | ** ** | ** **                                    | ** ** |
| **Net Production:**                                 |       |                                          |       |                     |       |   |   |
| Total production  (MMcfe)                           |       | 3,792                                         |       | 2,075                    |       | 82.7 | % |
| Average daily production  (Mcfe/d)                  |       | 21,000                                        |       | 11,463                   |       | 83.2 | % |
|                                                |       |                                          |       |                     |       |   |   |
| **Average Sales Prices:**                           |       |                                          |       |                     |       |   |   |
| Weighted average  realized natural gas price (Mcfe) |       | $                                             | 10.30      |                     | $          | 5.95 |   | 73.1 | % |
|                                                |       |                                          |       |                     |       |   |   |
| **Average Unit Costs per Mcfe  (Non-GAAP):**        |       |                                          |       |                     |       |   |   |
| Operating  expenses                                 |       | $                                             | 1.56       |                     | $          | 1.59 |   | (1.9 | )% |
| General and  administrative expenses (1)            |       | $                                             | 1.18       |                     | $          | 0.55 |   |   |  * |
| Depreciation, depletion  and amortization           |       | $                                             | 2.06       |                     | $          | 1.25 |   | 64.8 | % |

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(1) This is anon-GAAP performance measure used by our management and is a quantitativemeasure used in the natural gas and oil industry.  The measure for the six months ended June 30,2006 excludes approximately $2.0 million of bonuses paid to certain executiveofficers in connection with our IPO and $9.9 million of unit-based compensationexpense.  General and administrativeexpenses including these amounts were $4.32 per Mcfe for the six months endedJune 30, 2006.

*  Amount is greater than 100%, therefore is notmeaningful.

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***Revenue***

Natural gasand oil sales increased to approximately $29.9 million from $14.0 millionduring the six months ended June 30, 2006 as compared to the six months endedJune 30, 2005.

The increase in revenue from natural gas and oil saleswas attributable primarily to the increase in production to 3,792 MMcfe duringthe six months ended June 30, 2006 from 2,075 MMcfe during the period endedJune 30, 2005.  In addition to theincrease in production, the average natural gas sales price increased duringthe six months ended June 30, 2006 as compared to the six months ended June 30,2005.

***HedgingActivities***

During thesix months ended June 30, 2006, we have effectively hedged 97% of our naturalgas production, which resulted in revenues that were $9.2 million greater thanwe would have achieved at unhedged prices. During the six months ended June 30, 2005, we hedged approximately 100%of our natural gas production, which resulted in revenues that were $16.8million less than we would have achieved at unhedged prices.  Unrealized gain on derivatives in the amountof $28.0 million for the six months ended June 30, 2006 and unrealized loss onderivatives in the amount of $5.4 million for the six months ended June 30,2005 were also recorded.  Unrealizedgains and losses result from natural gas price fluctuations as compared to thesettlement price on the derivative.

***Expenses***

Operatingexpenses consist 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 per unit of production decreased from $1.59 per Mcfe in 2005 to $1.56in 2006.  Total operating expensesincreased to $5.9 million for the six months ended June 30, 2006 from $3.3million for the six months ended June 30, 2005, due to the increase in thenumber of wells as a result of the three acquisitions completed in both 2006and in 2005, and the drilling of 84 and 110 wells during 2006 and 2005,respectively.

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 $16.4 million duringthe six months ended June 30, 2006, from $1.1 million compared to the sixmonths ended June 30, 2005.  General andadministrative expenses are presented net of approximately $0.6 million and$0.5 million during the six months ended June 30, 2006 and 2005, respectively,which represents operating expense reimbursements from other working interestowners.  The increase in general andadministrative expenses was due to the recognition of unit-based compensationexpense of $9.9 million and $2.0 million of bonuses paid in connection with ourIPO during the six months ended June 30, 2006. In addition, our rapidly growing operations and increasing our staffinglevel to manage the additional wells acquired and drilled in 2006 and 2005 andto perform the functions associated with being a public company contributed tothe increase.

Depreciation,depletion and amortization increased to $7.8 million for the six months endedJune 30, 2006 from $2.6 million for the six months ended June 30, 2005, due tothe increase in the number of wells as a result of the acquisitions completedand the drilling of wells during 2006 and 2005, as noted above.  During the six months ended June 30, 2006 and2005, the Company capitalized approximately $1.1 million and $0.4 million,respectively, of internal costs related to drilling.

Interest andfinancing income (expense) was a net expense of $5.3 million for the sixmonths ended June 30, 2006 compared to a net expense of $2.3 million for thesix months ended June 30, 2005.  Ourinterest rate swaps were not specifically designated as hedges under SFAS 133,even though they reduce our exposure to changes in interest rates.  Therefore, the mark-to-market of theseinstruments was recorded as a $0.7 million gain and a $16,000 gain for the sixmonths ended June 30, 2006 and 2005, respectively.  Further, these amounts represent non-cashcharges.  Cash payments for interestexpense increased to approximately $5.0 million for the six months ended June30, 2006, from $1.7 million for the six months ended June 30, 2005, primarilydue to increased debt levels associated with the acquisitions completed and thedrilling of wells during 2006 and 2005 as discussed above.

Income taxwas a benefit of approximately $74,000 for the six months ended June 30, 2006,resulting from the recognition of deferred tax assets arising from netoperating losses which are expected to be realized to the extent of deferredtax liabilities

27

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arising frombases differences in property and equipment. Deferred tax assets exceeding deferred tax liabilities of $0.3 millionhave been offset by an increase in the valuation allowance during the sixmonths ended June 30, 2006.  Because wewere structured as a limited liability company through May 31, 2005, notax provision was recorded during the six months ended June 30, 2005.

**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 June 30, 2006,there have been no significant changes with regard to the critical accountingpolicies disclosed in the Company’s Annual Report on Form 10-K for the yearended December 31, 2005.  The policiesdisclosed included the accounting for natural gas and oil properties, naturalgas and oil reserve quantities, revenue recognition and derivativeinstruments.  Effective January 1, 2006,the Company implemented SFAS 123R.  SeeNote 9 in the Notes to Condensed Consolidated Financial Statements for acomprehensive discussion of the accounting for unit-based compensation expense,including a discussion of the assumptions used to estimate the fair marketvalue of awards.

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**Liquidity and Capital Resources**

***Statements of Cash Flow***

At June 30, 2006, we had cash and cash equivalents of$3.6 million compared to $11.0 million at December 31, 2005.

Cash provided by operating activities for the six monthsended June 30, 2006 was $14.1 million, compared to cash used in operatingactivities of $10.0 million for the six months ended June 30, 2005.  The increase in cash provided by operatingactivities was primarily due to the increase in net income, which was $32.2million for the six months ended June 30, 2006, compared to a net loss of $17.7million for the six months ended June 30, 2005. See “Results of Operations” above for detail about the increase incomponents of net income.

Cashused in investing activities was $65.8 million for the six months ended June30, 2006, compared to $13.7 million for the six months ended June 30,2005.  The increase in cash used ininvesting activities was due to an increase in acquisition activity during thesix months ended June 30, 2006 compared to the prior year.  See Note 3 in the Notes to ConsolidatedFinancial Statements.

 

Cash provided by financing activities was $44.3 millionfor the six months ended June 30, 2006, compared to $24.0 million for the sixmonths ended June 30, 2005.  In the first quarter of 2006, wecompleted our IPO of an aggregate of 12,450,000 units representing limitedliability company interests at $21.00 per unit. The aggregate initialpublic offering price for the units issued was approximately $261.4million.  Net proceeds to the Company (after underwriting discountsof approximately $18.3 million and offering expenses of approximately$4.3 million) were approximately $238.8 million, of which$122.0 million was used to reduce the Company’s then-existing indebtedness,approximately $114.4 millionwas used to redeem a portion of the membership interests in the Company andunits held by certain affiliated and non-affiliated holders and approximately $2.0 million was usedto pay bonuses to certain executive officers of the Company.

Duringthe six months ended June 30, 2006, the Company received proceeds fromborrowings on its credit facility of approximately $48.3 million, compared toproceeds of $101.4 million for the six months ended June 30, 2005.

In April2006, the Company’s Board of Directors declared a distribution of $0.32 perunit with respect to the first quarter of 2006 pro-rated for the period fromthe closing of the IPO on January 19, 2006 to March 31, 2006.  As a result, the Company paid aggregatedistributions of approximately $8.9 million in May 2006.

In July 2006, the Company’sBoard of Directors declared a distribution of $0.40 per unit with respect tothe second quarter of 2006.  Thedistribution totaling approximately $11.2 million was paid on August 14, 2006.

Managementcurrently anticipates that it will recommend to the Board of Directors anincrease in the annualized cash distribution of $0.12 per unit, or a 7.5%increase, to an annual rate of $1.72 per unit from the current annual rate of$1.60 per unit beginning with the cash distribution expected to be paid on orabout November 14, 2006 with respect to the third fiscal quarter of2006.  This is equivalent to a quarterlyrate of $0.43 per unit.

***Credit Facility***

In August 2006, inconnection with the acquisitions of the Blacksand Assets and the Kaiser Assets(see Note 3), the Company entered into an incremental senior secured revolvingcredit facility (the “Credit Facility”) with a maturity of August 2010,including an increase in the facility to $800.0 million and an increase in theborrowing base to $480.0 million.  Wealso entered into a subordinated bridge loan (see “Subordinated Bridge Loan”below).

Theterms under the incremental Credit Facility remain substantially the same asthe previous terms.  The borrowingbase under the Credit Facility will be redetermined semi-annually by thelenders in their sole discretion, based on, among other things, reserve reportsas prepared by reserve engineers taking into account the natural gas and oilprices at such time.  Our obligationsunder the Credit Facility are secured by mortgages on our natural gas and oilproperties as well as a pledge of all ownership interests in our operatingsubsidiaries.  We are required tomaintain the mortgages on properties representing at least 80% of our naturalgas and oil 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, intereston the Credit Facility is determined by reference to LIBOR plus an applicablemargin between 1.00% and 1.75% per annum; or a domestic bank rate plus anapplicable margin between 0.00% and 0.25% per annum.  LIBOR 

29

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margins increase by 0.25%while the Subordinated Bridge Loan is outstanding.  Interest is generally payable quarterly fordomestic bank rate loans and at the applicable maturity date for LIBOR loans.

The Credit Facilitycontains various covenants that limit the Company’s ability to incur additionalindebtedness, make acquisitions or certain capital expenditures; makedistributions other than from available cash; merge or consolidate; and engagein certain asset dispositions.  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.

***Subordinated Bridge Loan***

In August 2006, in orderto fund a portion of the acquisitions of the Blacksand Assets and the KaiserAssets, 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.

***Off-BalanceSheet Arrangements***

The Company did not haveany off-balance sheet arrangements as of June 30, 2006.

***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.  As of June 30, 2006, there have been nosignificant changes to the Company’s contractual obligations from 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 deferredfinancing fees;

·      (Gain) loss on sale ofassets;

·      (Gain) loss from equityinvestment;

·      Accretion of assetretirement obligation;

·      Unrealized (gain) loss onnatural gas derivatives;

·      Realized (gain) loss oncancelled natural gas swaps;

·      Unit-based compensationexpense;

·      IPO cash bonuses; and

·      Income tax 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 ourunitholders.  Specifically, this financialmeasure indicates to investors whether or not we are generating cash flow at alevel that can sustain or support an increase in our quarterly distributionrates.  Adjusted EBITDA is also aquantitative standard used throughout the investment community with respect topublicly-traded partnerships and limited liability companies.

The following table presents a reconciliation of ourconsolidated net income (loss) to Adjusted EBITDA:
|                                                                | ** ** | **Three months ended June 30,** | ** ** | **Six months ended June 30,** | ** ** |
|----------------------------------------------------------------|------------|-----------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                     | ** ** | **2006**                                            | ** ** | **2005**                                          | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                     | ** ** | **(in thousands)**                             | ** ** |
| Net income  (loss)                                             |       | $                                                   | 10,239     |                                              | $          | (5,276 | ) | $ | 32,216 |   | $ | (17,675 | ) |
| Plus:                                                          |       |                                                |       |                                              |       |   |   |   |   |
| Interest expense                                               |       | 2,696                                               |       | 2,279                                             |       | 5,335 |   | 2,259 |   |
| Depreciation, depletion and amortization                       |       | 4,116                                               |       | 1,406                                             |       | 7,816 |   | 2,587 |   |
| Write-off of deferred financing fees                           |       | 129                                                 |       | 389                                               |       | 503 |   | 389 |   |
| Loss on sale of assets                                         |       | 29                                                  |       | 18                                                |       | 47 |   | 40 |   |
| Loss from equity investment                                    |       | —                                              |       | 7                                                 |       | — |   | 17 |   |
| Accretion of asset retirement obligation                       |       | 61                                                  |       | 32                                                |       | 119 |   | 57 |   |
| Unrealized (gain) loss on natural gas derivatives              |       | (7,055                                              | )          | (1,197                                            | )          | (27,978 | ) | 5,383 |   |
| Realized (gain) loss on cancelled natural gas  derivatives (1) |       | —                                              |       | —                                            |       | — |   | 7,977 |   |
| Unit-based compensation expense                                |       | 4,196                                               |       | —                                            |       | 9,876 |   | — |   |
| IPO bonuses                                                    |       | —                                              |       | —                                            |       | 2,039 |   | — |   |
| Income tax benefit (2)                                         |       | (193                                                | )          | —                                            |       | (74 | ) | — |   |
| Adjusted EBITDA                                                |       | $                                                   | 14,218     |                                              | $          | (2,342 | ) | $ | 29,899 |   | $ | 1,034 |   |

 

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(1)           During the six months ended June 30, 2005, wecancelled (before their original settlement date) a portion of out-of-the-moneynatural gas swaps and realized a loss of $8.0 million.  We subsequently hedged similar volumes athigher 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 was no taxprovision included in our consolidated financial statements because all of ourtaxable income or loss was included in the income tax returns of the individualmembers.

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Asnoted above, Adjusted EBITDA is non-GAAP performance measure used by ourmanagement and is a quantitative measure used in the natural gas and oil industry.  On our consolidated statements of cash flows,our net cash provided by operating activities for the six months ended June 30,2006 was approximately $14.1 million and includes approximately $28.0 millionunrealized gain on natural gas derivatives, $9.8 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 six months ended June 30, 2005was approximately $10.0 million and includes $5.4 million unrealized loss onnatural gas derivatives and $8.0 million realized loss on cancelled natural gasderivatives.

**NewAccounting Standards**

Therehave been no new accounting standards that materially affected the Company thisperiod; however, see Note 9 in the Notes to Condensed Consolidated FinancialStatements for a discussion of SFAS 123R.

**CautionaryStatement**

This Quarterly Report onForm 10-Q contains forward-looking statements within the meaning of federalsecurities laws that are subject to a number of risks and uncertainties, manyof which are beyond our control.  Thesestatements may include statements about our:

·      business strategy;

·      financial strategy;

·      drilling locations;

·      natural gas and oil reserves;

·      realized natural gas and oil prices;

·      production volumes;

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

·      future operating results; and

·      plans,objectives, expectations and intentions.

All of these types of statements, otherthan statements of historical fact included in this Quarterly Report on Form10-Q, are forward looking statements. These forward-looking statements may be found in Item 2.  In some cases, forward-looking statements canbe identified by terminology such as “may,” “will,” “could,” “should,”“expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,”“predict,” “potential,” “pursue,” “target,” “continue,” the negative of suchterms or other comparable terminology.

 

The forward-lookingstatements contained in this Quarterly Report on Form 10-Q are largely based onour expectations, which reflect estimates and assumptions made by ourmanagement.  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.  These forward-looking statementsspeak only as of the date made, and other than as required by law, we undertakeno obligation to publicly update or revise any forward-looking statement,whether as a result of new information, future events or otherwise.

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

The primary objective ofthe following information is to provide forward-looking quantitative andqualitative information about our potential exposure to market risks.  The term “market risk” refers to the risk ofloss arising from adverse changes in natural gas prices and interestrates.  The disclosures are not meant tobe precise indicators of expected future losses, but rather indicators ofreasonably possible losses.  This forward-lookinginformation provides indicators of how we view and manage our ongoing marketrisk exposures.  All of our market risksensitive instruments were entered into for purposes other than speculativetrading.

***Commodity PriceRisk***

Our major market risk exposure is in the pricingapplicable to our natural 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 natural gas productionhas been volatile and unpredictable for several years, and we expect thisvolatility to continue in the future. The prices we receive for production depend on many factors outside ofour control.

We periodically have entered into and anticipate enteringinto hedging arrangements with respect to a portion of our projected naturalgas production through various transactions that hedge the future pricesreceived.  These transactions may includeprice swaps whereby we will receive a fixed price for our production and pay avariable 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 natural gas prices at targeted levels and to manage our exposure tonatural gas price fluctuations.  We donot hold or issue derivative instruments for speculative trading purposes.

At June 30, 2006, the fair value of hedges that settleduring the next twelve months was an asset of approximately $12.0 million and aliability of approximately $4.4 for a net asset of approximately $7.6 million,which we are owed from the counterparty. A 10% increase in the index natural gas price above the June 30, 2006price for the next twelve months would result in a change of approximately $5.8million for a net asset of approximately of $1.8 million; conversely, a 10%decrease in the index natural gas price would increase the asset byapproximately $5.8 million.

Ourderivatives as of June 30, 2006, for 2006 through 2009, are summarized in thetable presented in Note 12 in the Notes to Condensed Consolidated FinancialStatements.

 

The following table summarizes the crude oil positions wehave entered into subsequent to June 30, 2006, in connection with ouracquisition of the Blacksand Assets:

|                        | ** ** | **August 1 –  December 31,  2006** | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** |
|------------------------|------------|--------------------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|
|                   | ** ** | ** **                                             | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Fixed Price  Swaps:    | ** ** | ** **                                             | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume (Bbls)   |       | 150,000                                                |       | 450,000        |       | 450,000        |       | 450,000        |       |
| Average Price ($/Bbl)  |       | $                                                      | 77.32      |           | $          | 76.06          |       | $              | 76.06      |   | $ | 76.06 |   |
| Puts:                  |       |                                                   |       |           |       |           |       |           |       |
| Hedged Volume (Bbls)   |       | 36,000                                                 |       | 200,000        |       | 200,000        |       | 200,000        |       |
| Average Price ($/Bbl)  |       | $                                                      | 75.00      |           | $          | 75.00          |       | $              | 75.00      |   | $ | 75.00 |   |
| **Total:**             |       |                                                   |       |           |       |           |       |           |       |
| Hedged Volume (Bbls)   |       | 186,000                                                |       | 650,000        |       | 650,000        |       | 650,000        |       |
| Average Price  ($/Bbl) |       | $                                                      | 76.87      |           | $          | 75.73          |       | $              | 75.73      |   | $ | 75.73 |   |

 

***Interest RateRisk***

At June 30, 2006, we had debt outstanding of $193.0million, which incurred interest at floating rates in accordance with ourrevolving credit facility.  As of June30, 2006, the one-month LIBOR was approximately 5.3%.  A 1% increase in LIBOR as of June 30, 2006would result in an estimated $1.9 million increase in annual interest expense.

In order to finance the acquisitions of the BlacksandAssets and Kaiser Assets in August 2006, the Company modified its revolvingcredit facility, including an increase in the facility to $800.0 million and anincrease in the borrowing base to $480.0 million.  In addition, the Company entered into a$250.0 million subordinated bridge loan. See Note 6 in the Notes to Condensed 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 3.2% and 4.3%,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 5.2% and 5.7%, respectively, while receiving a floatinginterest rate.  In 2005, in connectionwith entering into a new credit facility, we transferred these four interestrate swap agreements to a different third party financial institution.  As a consequence of the transfer of thesefour agreements, the fixed interest rate we pay on each agreement increased byseven basis points.

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 3.1% and 4.4%, respectively,while receiving a floating interest rate.

A 1% change in LIBOR as of June 30, 2006 would result inan estimated $1.5 million change in 2006 interest expense associated with ourinterest swap agreements.

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

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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 and Procedures**

* *

***(a)*******Evaluation of disclosure controls andprocedures**

The Company maintainsdisclosure controls and procedures that are designed to ensure that informationrequired to be disclosed in the Company’s reports under the Exchange Act isrecorded, processed, summarized and reported within the time periods specifiedin the SEC’s rules and forms, and that such information is accumulated andcommunicated to management, including the Company’s Chief Executive Officer andChief Financial Officer, and the Company’s Audit Committee of the Board ofDirectors, as appropriate, to allow timely decisions regarding requireddisclosure.  In designing and evaluatingthe disclosure controls and procedures, management recognizes that any controlsand procedures, no matter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives, andmanagement is required to apply its judgment in evaluating the cost-benefitrelationship of possible controls and procedures.

In connection with thepreparation of the Company’s Annual Report on Form 10-K for the year endedDecember 31, 2005 (“2005 10-K”), an evaluation was performed under thesupervision and with the participation of the Company’s management, includingthe Chief Executive Officer and the Chief Financial Officer, of theeffectiveness of the design and operation of the Company’s disclosure controlsand procedures as defined in Rule 13a-15(e) and Rule 15d-15(e) under theSecurities Exchange Act of 1934, as amended (the “Exchange Act”).  The Company concluded that the disclosurecontrols and procedures were not effective as of December 31, 2005.

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.  Based onthe evaluation, the Chief Executive Officer and Chief Financial Officer haveconcluded that, as of June 30, 2006, the Company’s disclosure controls andprocedures were not effective as a result of the previously identified materialweaknesses.  As reported in the 2005 Form10-K, management is in the process of taking remedial steps to correct theweaknesses.

*Materialweaknesses in internal control*. Specifically, the Companylacked (i) personnel with sufficient technical accounting and financialreporting expertise, (ii) adequate review controls over accountreconciliations and account analyses, (iii) policies and procedures inplace to determine and document the appropriate application of accountingprinciples and (iv) policies and procedures requiring a detailed andcomprehensive review of the underlying information supporting the amountsincluded in the annual and interim consolidated financial statements anddisclosures.

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

*Remediationactivities.* During the second quarter of 2006, Companymanagement has taken and is taking the following steps to strengthen internalcontrol over financial reporting.

Remediationactivities that we implemented during the three months ended June 30, 2006 areas follows:

1.     Weengaged outside consultants with extensive natural oil and gas financialreporting experience to augment our current accounting resources to assist withthis quarterly report and future filings.

2.     Weperformed additional analysis and other post closing procedures to enable thepreparation of accurate consolidated financial statements, including allrequired disclosures.  In addition, weimplemented certain review and monitoring controls over accountreconciliations, and analysis and post closing procedures.

3.     Wedeveloped and implemented a process for determining the effective accountingdate for an oil and gas property acquisition and formalized proceduresnecessary to appropriately account for future acquisitions.

4.     Weimplemented the use of disclosure checklists addressing the disclosurerequirements under GAAP as well as the incremental financial and nonfinancialinformation required by SEC regulations.

Subsequent to June 30, 2006,we have hired experienced personnel with technical accounting, financialreporting and oil and gas experience.

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Further as previouslyreported, we expect to continue to make changes in our internal control overfinancial reporting during the periods prior to December 31, 2007 inconnection with our compliance efforts under Section 404 of the Sarbanes-OxleyAct of 2002.  As such, we will continueto assess the adequacy of our internal control over financial reporting,remediate any control weaknesses that may be identified, validate throughtesting that controls are functioning as designed and implement a continuousreporting and improvement process for internal control over financialreporting.

The Companybelieves the measures taken to date and planned for the future will address thereported material weakness and intends to complete the remediation effortsduring 2006.

*Changesin internal control over financial reporting.* All changes inour internal control over financial reporting, as defined inRule 13(a)-15(f) under the Exchange Act, during the three months endedJune 30, 2006, that have materially affected, or are reasonably likely to materiallyaffect, our internal control over financial reporting, are described aboveunder remediation activities.

 

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**PART II - OTHERINFORMATION**

**Item 1.       ****Legal Proceedings**

Notapplicable.

**Item 1A.     RiskFactors**

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

## **Related toOur Business**

## ***We may not have sufficient cash flow from operations to pay thequarterly distribution at the current distribution level and futuredistributions to our unitholders may fluctuate from quarter to quarter.***

We may not havesufficient cash flow from operations each quarter to pay the quarterlydistribution at the current distribution level. Under the terms of our limited liability company agreement, the amountof cash otherwise available for distribution will be reduced by our operatingexpenses and the amount of any cash reserve amounts that our Board of Directorsestablishes to provide for future operations, future capital expenditures,future debt service requirements and future cash distributions to ourunitholders.  The amount of cash we candistribute on our units principally depends upon the amount of cash we generatefrom our operations, which will fluctuate from quarter to quarter based on,among other things:

·                  theamount of natural gas and oil we produce;

·                  theprice at which we are able to sell our natural gas and oil production;

·                  thelevel of our operating costs;

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

·                  thelevel of our capital expenditures.

In addition, theactual amount of cash we will have available for distribution will depend onother factors, some of which are beyond our control, including:

·                  ourability to make working capital borrowings under our credit facility to paydistributions;

·                  thecosts of acquisitions, if any;

·                  fluctuationsin our working capital needs;

·                  timingand collectibility of receivables;

·                  restrictionson distributions contained in our credit facility;

·                  prevailingeconomic conditions; and

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

As a result ofthese factors, the amount of cash we distribute to our unitholders in anyquarter may fluctuate significantly from quarter to quarter and may be lessthan the current distribution level.

We will beprohibited from borrowing under our credit facility to pay distributions tounitholders if the amount of borrowings outstanding under our credit facilityreaches or exceeds 90% of the borrowing base, which is the amount of moneyavailable for borrowing, as determined semi-annually by our lenders in theirsole discretion.  The lenders willredetermine the borrowing base based on an engineering report with respect toour natural gas and oil reserves, which will take into account the prevailingnatural gas and oil prices at such time. Any time our borrowings exceed 90% of the then-specified borrowing base,our ability to pay distributions to our unitholders in any such quarter issolely dependent on our ability to generate sufficient cash from ouroperations.

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

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

·                  unableto identify attractive acquisition candidates or negotiate acceptable purchasecontracts with them;

·                  unableto obtain financing for these acquisitions on economically acceptable terms; or

·                  outbidby competitors.

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

Any acquisitioninvolves potential risks, including, among other things:

·                  mistakenassumptions about revenues and costs, including synergies;

·                  significantincreases in our indebtedness and working capital requirements;

·                  aninability to integrate successfully or timely the businesses we acquire;

·                  theassumption of unknown liabilities;

·                  limitationson rights to indemnity from the seller;

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

·                  increaseddemands on existing personnel; and

·                  customeror key employee losses at the acquired businesses.

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

## ***We have substantial indebtedness under our creditfacility.  Ourcredit facility has and our term loanhave substantial restrictions and financial covenantsand we may have difficulty obtaining additional credit, which could adverselyaffect our operations and our ability to pay distributions to our unitholders.***

We havesubstantial indebtedness under our credit facility,  (which wasconverted into a new $800.0 million credit facility in August 2006) and our term loan.  As of August 14, 2006, we had approximately $400.6million outstanding under our credit facility (with additional borrowingcapacity of approximately $79.4 million) and approximately $250.0 millionoutstanding under our subordinated bridge loan. As a result of our indebtedness, we will use a portion of our cash flowto pay interest and principal when due, which will reduce the cash available tofinance our operations and other business activities and could limit ourflexibility in planning for or reacting to changes in our business and theindustry in which we operate.  The amountof our debt may also cause us to be more vulnerable to economic downturns andadverse developments in our business.  Our ability to access the capital markets toraise capital on favorable terms will be affected by our debt level and byadverse market conditions resulting from, among other things, general economicconditions, contingencies and uncertainties that are difficult to predict andimpossible to control.  Such adevelopment could adversely affect our ability to obtain financing for workingcapital, capital expenditures or acquisitions or to refinance existingindebtedness.

We depend on ourcredit facility for future capital needs and to fund a portion of ourdistributions.  The credit facilityrestricts our ability to obtain additional financing, make investments, leaseequipment, sell assets and engage in business combinations.  We also are required to comply with certainfinancial covenants and ratios.  Ourability to comply with these restrictions and covenants in the future isuncertain and will be affected by the levels of cash flow from our operationsand events or circumstances beyond our control. Our failure to comply with anyof the restrictions and covenants under our credit facility could result in adefault under our credit facility, which could cause all of our existingindebtedness to be immediately due and payable.

Availability underour credit facility is determined semi-annually at the discretion of thelenders and is based in part on natural gas and oil prices.  The lenders can unilaterally adjust theborrowing base and the borrowings permitted to be outstanding under the creditfacility.  Any increase in the borrowingbase requires the consent of all the lenders. If the required lenders do not agree on an increase, then the borrowingbase will be the highest borrowing base acceptable to the lenders holding662⁄3% of the commitments. Outstanding borrowings in excess of the borrowing base must be repaid 

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immediately, or wemust pledge other natural gas and oil properties as additional collateral.  We do not currently have any substantialunpledged properties, and we may not have the financial resources in the futureto make any mandatory principal prepayments required under the creditfacility.  Significant declines in ourproduction or significant declines in realized natural gas or oil prices forprolonged periods and resulting decreases in our borrowing base may force us toreduce or suspend distributions to our unitholders.

***Increasesin interest rates could adversely affect our business, results of operations,cash flows from operations and financial condition.***

In addition to ourexposure to commodity prices, we have significant exposure to increases ininterest rates. As of August 14, 2006, we had approximately $650.6 million ofindebtedness outstanding under the credit facility and subordinated bridge loan,all of which is at variable interest rates, after giving effect to existinginterest swap arrangements.  Therefore,our business, results of operations, cash flows from operations could beadversely affected by significant increases in interest rates. 

An increase ininterest rates may cause a corresponding decline in demand for equityinvestments, in general, and in particular for yield-based equity investmentssuch as our units.  Any such reduction indemand for our units resulting from other more attractive investmentopportunities may cause the trading price of our units to decline.

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

Our revenue,profitability and cash flow depend upon the prices and demand for natural gasand oil.  The natural gas and oil marketsare very volatile and a drop in prices can significantly affect our financialresults and impede our growth.  Changesin natural gas and oil prices have a significant impact on the value of ourreserves and on our cash flow.  Pricesfor natural gas and oil may fluctuate widely in response to relatively minorchanges in the supply of and demand for natural gas and oil, market uncertaintyand a variety of additional factors that are beyond our control, such as:

·                  thedomestic and foreign supply of and demand for natural gas and oil;

·                  theprice and level of foreign imports;

·                  thelevel of consumer product demand;

·                  weatherconditions;

·                  overalldomestic and global economic conditions;

·                  politicaland economic conditions in natural gas and oil producing countries, includingthose in the Middle East and South America;

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

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

·                  technologicaladvances affecting energy consumption;

·                  domesticand foreign governmental regulations and taxation;

·                  theimpact of energy conservation efforts;

·                  theproximity and capacity of natural gas and oil and pipelines and other transportationfacilities; and

·                  theprice and availability of alternative fuels.

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

***Futureprice declines may result in a write-down of our asset carrying values.***

Declines innatural gas and oil prices may result in our having to make substantialdownward adjustments to our estimated proved reserves.  If this occurs, or if our estimates ofdevelopment costs increase, production data factors change or drilling resultsdeteriorate, accounting rules may require us to write down, as a non-cashcharge to earnings, the carrying value of our oil and gas properties forimpairments.  We are required to performimpairment tests on our assets periodically and whenever events or changes incircumstances warrant a review of our assets. To the extent such tests indicatea reduction of the estimated useful life or estimated future cash flows of ourassets, the carrying value may not be recoverable and therefore require awrite-down.  We may incur impairmentcharges in the future, which could have a material adverse effect on ourresults of operations in the period incurred and on our ability to borrow fundsunder our credit facility, which in turn may adversely affect our ability tomake cash distributions to our unitholders.

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## ***Unless we replace our reserves, our reserves and production willdecline, which would adversely affect our cash flow from operations and ourability to make distributions to our unitholders.***

Producing naturalgas and oil reservoirs generally are characterized by declining productionrates that vary depending upon reservoir characteristics and otherfactors.  The overall rate of decline forour production will change if production from our existing wells declines in adifferent manner than we have estimated and can change when we drill additionalwells, make acquisitions and under other circumstances.  Thus, our future natural gas and oil reservesand production and, therefore, our cash flow and income are highly dependent onour success in efficiently developing and exploiting our current reserves andeconomically finding or acquiring additional recoverable reserves.  We may not be able to develop, find oracquire additional reserves to replace our current and future production atacceptable costs, which would adversely affect our affect our cash flow fromoperations and our ability to make distributions to our unitholders.

## ***Our estimated reserves are based on many assumptions that may prove tobe inaccurate. Any material inaccuracies in these reserve estimates orunderlying assumptions will materially affect the quantities and present valueof our reserves.***

No one can measureunderground accumulations of natural gas or oil in an exact way.  Reserve engineering requires subjectiveestimates of underground accumulations of natural gas and oil and assumptionsconcerning future natural gas and oil prices, production levels, and operatingand development costs.  As a result,estimated quantities of proved reserves and projections of future productionrates and the timing of development expenditures may prove to beinaccurate.  Our independent petroleumengineers prepare estimates of our proved reserves.  Over time, our internal engineers may makematerial changes to reserve estimates taking into account the results of actualdrilling and production.  Some of ourreserve estimates are made without the benefit of a lengthy production history,which are less reliable than estimates based on a lengthy production history.  Also, we make certain assumptions regardingfuture natural gas and oil prices, production levels, and operating anddevelopment costs that may prove incorrect. Any significant variance from theseassumptions by actual figures could greatly affect our estimates of reserves,the economically recoverable quantities of natural gas or oil attributable toany particular group of properties, the classifications of reserves based onrisk of recovery, and estimates of the future net cash flows.  Numerous changes over time to the assumptionson which our reserve estimates are based, as described above, often result inthe actual quantities of natural gas and oil we ultimately recover beingdifferent from our reserve estimates. The present value of future net cashflows from our proved reserves is not necessarily the same as the currentmarket value of our estimated natural gas and oil reserves.  We base the estimated discounted future netcash flows from our proved reserves on prices and costs in effect on the day ofestimate.  However, actual future net cashflows from our natural gas and oil properties also will be affected by factorssuch as:

·                  actualprices we receive for natural gas and oil;

·                  theamount and timing of actual production;

·                  supplyof and demand for natural gas and oil; and

·                  changesin governmental regulations or taxation.

The timing of bothour production and our incurrence of expenses in connection with thedevelopment and production of natural gas and oil properties will affect thetiming of actual future net cash flows from proved reserves, and thus theiractual present value.  In addition, the10% discount factor we use when calculating discounted future net cash flowsmay not be the most appropriate discount factor based on interest rates in effectfrom time to time and risks associated with us or the natural gas and oilindustry in general.

## ***Our development operations require substantial capital expenditures,which will reduce our cash available for distribution. We may be unable toobtain needed capital or financing on satisfactory terms, which could lead to adecline in our reserves.***

The natural gasand oil industry is capital intensive. We make and expect to continue to make substantial capital expendituresin our business for the development, production and acquisition of natural gasand oil reserves.  These expenditureswill reduce our cash available for distribution.  We intend to finance our future capitalexpenditures with cash flow from operations and our financingarrangements.  Our cash flow fromoperations and access to capital are subject to a number of variables,including:

·                  ourproved reserves;

·                  thelevel of natural gas and oil we are able to produce from existing wells;

·                  theprices at which we are able to sell our natural gas and oil; and

·                  ourability to acquire, locate and produce new reserves.

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If our revenues orthe borrowing base under our credit facility decrease as a result of lowernatural gas or oil prices, operating difficulties, declines in reserves or forany other reason, we may have limited ability to obtain the capital necessaryto sustain our operations at current levels. Our credit facility restricts our ability to obtain new financing. Ifadditional capital is needed, we may not be able to obtain debt or equity financingon terms favorable to us, or at all.  Ifcash generated by operations or available under our credit facility is notsufficient to meet our capital requirements, the failure to obtain additionalfinancing could result in a curtailment of our development operations, which inturn could lead to a possible decline in our reserves.

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

Although we gathermost of our current production, the marketability of our natural gas and oilproduction depends in part on the availability, proximity and capacity ofgathering and pipeline systems.  Theamount of natural gas and oil that can be produced and sold is subject tolimitation in certain circumstances, such as pipeline interruptions due toscheduled and unscheduled maintenance, excessive pressure, physical damage tothe gathering or transportation system, or lack of contracted capacity on suchsystems.  The curtailments arising fromthese and similar circumstances may last from a few days to several months.  In many cases, we are provided only withlimited, if any, notice as to when these circumstances will arise and theirduration. In addition, some of our wells are drilled in locations that are notserviced by gathering and transportation pipelines, or the gathering andtransportation pipelines in the area may not have sufficient capacity totransport the additional production.  Asa result, we may not be able to sell the natural gas and oil production fromthese wells until the necessary gathering and transportation systems areconstructed.  Any significant curtailmentin gathering system or pipeline capacity, or significant delay in theconstruction of necessary gathering and transportation facilities, wouldinterfere with our ability to market the natural gas and oil we produce, andcould reduce our cash available for distribution and adversely impact expectedincreases in natural gas and oil production from our drilling program.

## ***We depend on certain key customers for sales of our natural gas andoil. To the extent these and other customers reduce the volumes of natural gasor oil they purchase from us, our revenues and cash available for distributioncould decline.***

For the year endedDecember 31, 2005, Dominion Resources, Inc., Cabot Oil & Gas Corporation, UGIEnergy Services, Inc., Amerada Hess Corporation and Equitable Resources, Inc.accounted for approximately 48%, 14%, 10%, 7% and 6%, respectively, of ourtotal volumes, or 85% in the aggregate. For the six months ended June 30, 2006, Dominion Resources, Inc.,Equitable Gas Co. and Cabot Oil & Gas Corporation accounted forapproximately 67%, 9% and 9%, respectively, of our total volumes, or 85% in theaggregate.  To the extent these and othercustomers reduce the volumes of natural gas that they purchase from us, ourrevenues and cash available for distribution could decline.

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

Higher natural gasor oil prices generally increase the demand for drilling rigs, pipe, equipmentand crews and can lead to shortages of, and increasing costs for, drillingequipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews andoil field equipment and services could restrict our ability to drill the wellsand conduct the operations which we currently have planned.  Any delay in the drilling of new wells orsignificant increase in drilling costs could impact our ability to generatesufficient cash flow from operations to pay quarterly distributions to ourunitholders at the current distribution level.

## ***Because we handle natural gas, oil and other petroleum products, we mayincur significant costs and liabilities in the future resulting from a failureto comply with new or existing environmental regulations or an accidentalrelease of hazardous substances into the environment.***

The operations ofour wells, gathering systems, turbines, pipelines and other facilities aresubject to stringent and complex federal, state and local environmental lawsand regulations.  These include, forexample:

·                  thefederal Clean Air Act and comparable state laws and regulations that imposeobligations related to air emissions;

·                  thefederal Clean Water Act and comparable state laws and regulations that imposeobligations related to discharges of pollutants into regulated bodies of water;

·                  thefederal Resource Conservation and Recovery Act, and comparable state laws thatimpose requirements for the handling and disposal of waste from our facilities;and

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·                  theComprehensive Environmental Response, Compensation and Liability Act of 1980,also known as “Superfund,” and comparable state laws that regulate the cleanupof hazardous substances that may have been released at properties currently orpreviously owned or operated by us or at locations to which we have sent wastefor disposal.

Failure to complywith these laws and regulations may trigger a variety of administrative, civiland criminal enforcement measures, including the assessment of monetarypenalties, the imposition of remedial requirements, and the issuance of ordersenjoining future operations.  Certainenvironmental statutes, including the RCRA, CERCLA and analogous state laws andregulations, impose strict, joint and several liability for costs required toclean up and restore sites where hazardous substances have been disposed of orotherwise released. Moreover, it is not uncommon for neighboring landowners andother third parties to file claims for personal injury and property damageallegedly caused by the release of hazardous substances or other waste productsinto the environment.

There is aninherent risk that we may incur environmental costs and liabilities due to thenature of our business and the substances we handle.  For example, an accidental release from oneof our wells or gathering pipelines could subject us to substantial liabilitiesarising from environmental cleanup and restoration costs, claims made byneighboring landowners and other third parties for personal injury and propertydamage, and fines or penalties for related violations of environmental laws orregulations.  Moreover, the possibilityexists that stricter laws, regulations or enforcement policies couldsignificantly increase our compliance costs and the cost of any remediationthat may become necessary.  We may not beable to recover these costs from insurance. Please read “Business - Operations- Environmental Matters and Regulation” in our Annual Report on Form 10-K forthe year ended December 31, 2005.

## ***We may decide not to drill some of the prospects we have identified,and locations that we decide to drill may not yield natural gas or oil incommercially viable quantities.***

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

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

## ***Many of our leases are in areas that have been partially depleted ordrained by offset wells.***

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

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

Our management hasspecifically identified and scheduled drilling locations as an estimation ofour future multi-year drilling activities on our existing acreage.  As of June 30, 2006, we had identified 1,037drilling locations, of which 391 were proved undeveloped locations and 646 wereother locations.  These identified drillinglocations represent a significant part of our growth strategy.  Our ability to drill and develop theselocations depends on a number of factors, including the availability ofcapital, seasonal conditions, regulatory approvals, natural gas and oil prices,costs and drilling results.  In addition,Schlumberger Data and Consulting Services has not assigned any proved reservesto the 646 other drilling locations we have identified and scheduled fordrilling and therefore there may exist greater uncertainty with respect to thesuccess of drilling wells at these drilling locations.  Our final determination on whether to drillany of these drilling locations will be dependent upon the factors describedabove as well as, to some degree, the results of our drilling activities withrespect to our proved drilling locations. Because of these uncertainties, we donot know if the numerous drilling locations we have identified will be drilledwithin our expected timeframe or will ever be drilled or if we will be able toproduce natural gas and oil from these 

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or any otherpotential drilling locations.  As such,our actual drilling activities may materially differ from those presentlyidentified, which could adversely affect our business.

## ***Drilling for and producing natural gas and oil are high risk activitieswith many uncertainties that could adversely affect our financial condition orresults of operations and, as a result, our ability to pay distributions to ourunitholders.***

Our drillingactivities are subject to many risks, including the risk that we will notdiscover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only from dryholes, but also from productive wells that do not produce sufficient revenuesto be commercially viable.  In addition,our drilling and producing operations may be curtailed, delayed or canceled asa result of other factors, including:

·                  thehigh cost, shortages or delivery delays of equipment and services;

·                  unexpectedoperational events;

·                  adverseweather conditions, particularly seasonal weather conditions in the spring;

·                  facilityor equipment malfunctions;

·                  titleproblems;

·                  pipelineruptures or spills;

·                  compliancewith environmental and other governmental requirements;

·                  unusualor unexpected geological formations;

·                  lossof drilling fluid circulation;

·                  formationswith abnormal pressures;

·                  fires;

·                  blowouts,craterings and explosions; and

·                  uncontrollableflows of natural gas, oil or well fluids.

Any of theseevents can cause substantial losses, including personal injury or loss of life,damage to or destruction of property, natural resources and equipment,pollution, environmental contamination, loss of wells and regulatory penalties.We ordinarily maintain insurance against certain losses and liabilities arisingfrom our operations.  However, it isimpossible to insure against all operational risks in the course of ourbusiness.  Additionally, we may elect notto obtain insurance if we believe that the cost of available insurance is excessiverelative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or inamounts in excess of existing insurance coverage.  The occurrence of an event that is not fullycovered by insurance could have a material adverse impact on our businessactivities, financial condition and results of operations.

## ***Properties that we buy may not produce as projected and we may beunable to determine reserve potential, identify liabilities associated with theproperties or obtain protection from sellers against such liabilities.***

One of our growthstrategies is to capitalize on opportunistic acquisitions of natural gas andoil reserves.  However, our reviews ofacquired properties are inherently incomplete because it generally is notfeasible to review in depth every individual property involved in eachacquisition.  Even a detailed review ofrecords and properties may not necessarily reveal existing or potentialproblems, nor will it permit a buyer to become sufficiently familiar with theproperties to assess fully their deficiencies and potential.  Inspections may not always be performed onevery well, and environmental problems, such as ground water contamination, arenot necessarily observable even when an inspection is undertaken.

## ***Our hedging activities could result in financial losses or could reduceour income, which may adversely affect our ability to pay distributions to ourunitholders.***

To achieve morepredictable cash flow and to reduce our exposure to adverse fluctuations in theprices of natural gas and oil, we currently and may in the future enter intohedging arrangements for a significant portion of our natural gas and oilproduction.  If we experience a sustainedmaterial interruption in our production or if we are unable to perform ourdrilling activity as planned, we might be forced to satisfy all or a portion ofour hedging obligations without the benefit of the cash flow from our sale ofthe underlying physical commodity, resulting in a substantial reduction of ourliquidity.  Under our credit facility, weare prohibited from hedging all of our production, and we therefore retain therisk of a price decrease on our unhedged volumes. 

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## ***We depend on our Chairman, President and Chief Executive Officer whowould be difficult to replace.***

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

## ***If we fail to develop or maintain an effective system of internalcontrols, we may not be able to accurately report our financial results orprevent fraud.  As a result, current andpotential unitholders could lose confidence in our financial reporting, whichwould harm our business and the trading price of our units.***

A company’sinternal control over financial reporting is a process designed to providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. Because of its inherent limitations, internal control over financialreporting may not prevent or detect misstatements.  Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.  If we cannot provide reliable financialreports or prevent fraud, our reputation and operating results could beharmed.  We cannot be certain that ourefforts to develop and maintain our internal controls will be successful, thatwe will be able to maintain adequate controls over our financial processes andreporting in the future or that we will be able to comply with our obligationsunder Section 404 of the Sarbanes-Oxley Act of 2002 by our initial compliancedate of December 31, 2007.  We identifieda material weakness in our internal controls during the course of evaluatingdisclosure controls and procedures as of December 31, 2005.  For additional information, please read Item 9A.“Controls and Procedures” in our Annual Report on Form 10-K for the year endedDecember 31, 2005. 

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

## ***We may be unable to compete effectively with larger companies, whichmay adversely affect our ability to generate sufficient revenue to allow us topay distributions to our unitholders.***

The natural gasand oil industry is intensely competitive, and we compete with companies thathave greater resources than we have.  Ourability to acquire additional properties and to discover reserves will bedependent upon our ability to evaluate and select suitable properties and toconsummate transactions in a highly competitive environment.  Many of our larger competitors not only drillfor and produce natural gas and oil, but also carry on refining operations andmarket petroleum and other products on a regional, national or worldwidebasis.  These companies may be able topay more for natural gas and oil properties and evaluate, bid for and purchasea greater number of properties than our financial or human resourcespermit.  In addition, these companies mayhave a greater ability to continue drilling activities during periods of lownatural gas and oil prices and to absorb the burden of present and futurefederal, state, local and other laws and regulations.  Our inability to compete effectively withlarger companies could have a material adverse impact on our businessactivities, financial condition and results of operations.

## ***We are subject to complex federal, state, local and other laws andregulations that could adversely affect the cost, manner or feasibility ofdoing business.***

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

Part of theregulatory environment in which we operate includes, in some cases, legalrequirements for obtaining environmental assessments, environmental impactstudies and/or plans of development before commencing drilling and productionactivities.  In addition, our activitiesare subject to the regulations regarding conservation practices and protectionof correlative rights.  These regulationsaffect our operations and limit the quantity of natural gas and oil we mayproduce and sell.  A major risk inherentin our drilling plans is the need to obtain drilling permits from state andlocal authorities.  Delays in obtainingregulatory approvals or drilling permits, the failure to obtain a drillingpermit for a well or the receipt of a permit with unreasonable conditions orcosts could have a material adverse effect on our ability to develop ourproperties.  

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Additionally, thenatural gas and oil regulatory environment could change in ways that mightsubstantially increase the financial and managerial costs of compliance withthese laws and regulations and, consequently, adversely affect our ability topay distributions to our unitholders. For a description of the laws and regulations that affect us, pleaseread “Business - Operations - Environmental Matters and Regulation” and“Business - Operations - Other Regulation of the Natural Gas and Oil Industry”in our Annual Report on Form 10-K for the year ended December 31, 2005.

## ***We may face risks related to the recent restatement of our financialstatements.***

We restated ourfinancial statements for the period from March 14, 2003 (inception) throughDecember 31, 2003, for the year ended December 31, 2004 and certain financialstatement line items for the nine months ended September 30, 2004 and 2005primarily to correct certain accounting entries related to the acquisition ofnatural gas and oil properties.  As aresult of these changes, which primarily affect fiscal 2003 and 2004, revenueswere reduced by $944,164 and $1,729,526, respectively, and net loss wasincreased by $353,305 and $83,018, respectively. Companies that restate theirfinancial statements sometimes face litigation claims and/or SEC proceedingsfollowing such a restatement of financial results.  Although we are unaware of any pending orthreatened claims or proceedings relating to our restatement, if any claim orproceeding were to be commenced and successfully asserted against us, we couldface monetary judgments, penalties or other sanctions which could adverselyaffect our financial condition and could cause the price of our units todecline.

## **RisksRelated to Our Structure**

## ***Our management and Quantum Energy Partners own, in the aggregate, acontrolling interest in us, with management and Quantum Energy Partners owningapproximately 16.2% and 36.4%, respectively, of our units.***

Our management andQuantum Energy Partners own or control an aggregate 52.6% of our outstandingunits. Accordingly, management and Quantum Energy Partners, acting together,possess a controlling vote on substantially all matters submitted to a vote ofthe holders of our units.  As long asmanagement and Quantum Energy Partners in the aggregate beneficially own acontrolling interest in us, they will have the ability to elect all members ofour Board of Directors and to control our management and affairs. Ourmanagement and Quantum Energy Partners will be able to cause a change ofcontrol of our company.  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.

## ***Each of management or Quantum Energy Partners, or both, may haveconflicts of interest with us.  Ourlimited liability company agreement limits the remedies available to ourunitholders in the event unitholders have a claim relating to conflicts ofinterest.***

Conflicts ofinterest may arise between our management or Quantum Energy Partners, and usand our unitholders. These potential conflicts may relate to the divergentinterests of our management or Quantum Energy Partners. Situations in which theinterests of our management or Quantum Energy Partners may differ frominterests of our non-affiliated unitholders include, among others, thefollowing situations:

·                  ourlimited liability company agreement gives our Board of Directors broaddiscretion in establishing cash reserves for the proper conduct of ourbusiness, which will affect the amount of cash available for distribution.  For example, our management will use itsreasonable discretion to establish and maintain cash reserves sufficient tofund our drilling program;

·                  ourmanagement team determines the timing and extent of our drilling program andrelated capital expenditures, asset purchases and sales, borrowings, issuancesof additional membership interests and reserve adjustments, all of which willaffect the amount of cash that we distribute to our unitholders; and

·                  QuantumEnergy Partners and other affiliates of our directors are not prohibited frominvesting or engaging in other businesses or activities that compete with us.

## ***We may issue additional units without unitholder approval, which woulddilute existing ownership interests.***

We may issue anunlimited number of limited liability company interests of any type, includingunits, without the approval of our unitholders.

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

·                  anindividual unitholder’s proportionate ownership interest in us may decrease;

·                  theamount of cash distributed on each unit may decrease;

·                  therelative voting strength of each previously outstanding unit may be reduced;and

·                  themarket price of the units may decline.

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

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

·                  changesin securities analysts’ recommendations and their estimates of our financialperformance;

·                  thepublic’s reaction to our press releases, announcements and our filings with theSEC;

·                  fluctuationsin broader securities market prices and volumes, particularly among securitiesof natural gas and oil companies and securities of publicly-traded limitedpartnerships and limited liability companies;

·                  changesin market valuations of similar companies;

·                  departuresof key personnel;

·                  commencementof or involvement in litigation;

·                  variationsin our quarterly results of operations or those of other natural gas and oilcompanies;

·                  variationsin the amount of our quarterly cash distributions;

·                  futureissuances and sales of our units; and

·                  changesin general conditions in the U.S. economy, financial markets or the natural gasand oil industry.

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

## ***Quantum Energy Partners may sell units in the future, which couldreduce the market price of our outstanding units.***

As of August 14,2006, Quantum Energy Partners controlled an aggregate of 10,144,585 units.  In addition, we have agreed, upon demand byQuantum, to register for sale units held by Quantum Energy Partners, certainnon-affiliated investors and certain members of our management.  These registration rights allow QuantumEnergy Partners to request registration of their units and to include any ofthose units in a registration of other securities by us.  If Quantum Energy Partners were to sell asubstantial portion of their units, then the market price of our outstandingunits may decline.

***We donot have the same flexibility as other types of organizations to accumulatecash and equity to protect against illiquidity in the future.***

Unlike acorporation, our limited liability company agreement requires us to makequarterly distributions to our unitholders of all available cash reduced by anyamounts of reserves for commitments and contingencies, including capital andoperating costs and debt service requirements. The value of our units may decrease in direct correlation with decreasesin the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we mayhave difficulty issuing more equity to recapitalize we may be unable to issuemore equity to recapitalize.

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## **Tax Risks to Unitholders**

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

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

If we were treatedas a corporation for federal income tax purposes, we would pay federal incometax on our taxable income at the corporate tax rates, currently at a maximumrate of 35%, and would likely pay state income tax at varying rates.  Distributions to unitholders would generallybe taxed as corporate dividends, and no income, gain, loss, deduction or creditwould flow through to unitholders. Because a tax may be imposed on us as a corporation, our cash availablefor distribution to our unitholders could be reduced.  Therefore, our treatment as a corporationcould result in a material reduction in the anticipated cash flow and after-taxreturn to our unitholders and therefore result in a substantial reduction inthe value of our units.

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

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

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

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

We have notrequested a ruling from the IRS with respect to our treatment as a partnershipfor federal income tax purposes or any other matter that affects us.  The IRS may adopt positions that differ fromthe positions we take. It may be necessary to resort to administrative or courtproceedings to sustain some or all of the positions we take and a court maydisagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the marketfor our units and the price at which they trade.  In addition, our costs of any contest withthe IRS will result in a reduction in cash available for distribution to ourunitholders and thus will be borne indirectly by our unitholders.

## ***We willtreat each purchaser of our units as having the same tax benefits withoutregard to the units purchased. The IRS may challenge this treatment, whichcould adversely affect the value of the units.***

Because we cannotmatch transferors and transferees of units, we will adopt depreciation andamortization positions that may not conform with all aspects of existing U.S.Treasury regulations.  A successful IRSchallenge to those positions could adversely affect the amount of tax benefitsavailable to our unitholders.  It alsocould affect the timing of these tax benefits or the amount of gain on the saleof units and could have a negative impact on the value of our units or resultin audits of and adjustments to our unitholders’ tax returns.

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

In addition tofederal income taxes, our unitholders will likely be subject to other taxes,including state and local taxes, unincorporated business taxes and estate,inheritance or intangible taxes that are imposed by the various jurisdictionsin which we do business or own property now or in the future, even if they donot reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and localincome tax returns and pay state and local income taxes in some or all of thesejurisdictions.  Further, our unitholdersmay be subject to penalties for failure to comply with those requirements.  We currently do business and own assets inWest Virginia, Pennsylvania, New York, Virginia, California and 

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Oklahoma.  As we make acquisitions or expand ourbusiness, we may do business or own assets in other states in the future.  It is the responsibility of each unitholderto file all United States federal, foreign, state and local tax returns thatmay be required of such unitholder.  Ourcounsel has not rendered an opinion on the state or local tax consequences ofan investment in the units.

## ***Tax gainor loss on the disposition of our units could be more or less than expectedbecause prior distributions in excess of allocations of income will decreasethe tax basis of the units.***

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

## ***We will beconsidered to have terminated for tax purposes due to a sale or exchange of 50%or more of our interests within a twelve-month period.***

We will beconsidered to have terminated for tax purposes if there is a sale or exchangeof 50% or more of the total interests in our capital and profits within atwelve-month period.  A constructivetermination results in the closing of our taxable year for all unitholders andin the case of a unitholder reporting on a taxable year other than a fiscalyear ending December 31, may result in more than 12 months of our taxableincome or loss being includable in his taxable income for the year oftermination.  A constructive terminationoccurring on a date other than December 31 will result in us filing two taxreturns (and unitholders receiving two Schedule K-ls) for one fiscal year andthe cost of the preparation of these returns will be borne by all of ourunitholders.

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**Item 2.        UnregisteredSales of Equity Securities and Use of Proceeds**

Notapplicable.

**Item 3.        DefaultsUpon Senior Securities**

Notapplicable.

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

Notapplicable.

**Item 5.        OtherInformation**

Notapplicable.

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**Item 6.    Exhibits**
| Exhibit Number | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|----------------|------------|------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.1            |       | —     |       | Purchase and Sale Agreement by and among Linn  Energy, LLC and Blacksand Energy, LLC, dated July 19, 2006 (incorporated  herein by reference to Exhibit 2.1 to 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 (incorporated herein by reference to  Exhibit 3.1 to the Current Report on Form 8-K filed by Linn Energy,  LLC on January 19, 2006)                                                                                                                                                                                                                                                          |
| 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)                                                                                                                                                                                                                                                                                              |
| 10.1*          |       | —     |       | 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)                                                                                                                                                                                                                                                    |
| 10.2*          |       | —     |       | Memorandum of Understanding Regarding Compensation  Arrangements for Members of the Linn Energy, LLC Board of Directors  (incorporated herein by reference to Exhibit 10.1 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  April 3, 2006 between Linn Operating, Inc. and Thomas A. Lopus  (incorporation herein by reference to Exhibit 10.1 to the current Report  on Form 8-K filed by Linn Energy, LLC on April 18, 2006 (the  “April 18, 2006 Form 8-K”)                                                                                                                                                                     |
| 10.4*          |       | —     |       | Linn Energy, LLC Long-Term Incentive Plan Restricted  Unit Agreement, dated effective as of April 13, 2006 between Linn Energy,  LLC and Thomas A. Lopus (incorporated herein by reference to  Exhibit 10.2 to the April 18, 2006 Form 8-K)                                                                                                                                                                                                                             |
| 10.5*          |       | —     |       | Linn Energy, LLC Long-Term Incentive Plan Option  Agreement, dated effective as of April 13, 2006 between Linn Energy, LLC  and Thomas A. Lopus (incorporated herein by reference to  Exhibit 10.3 to the April 18, 2006 Form 8-K)                                                                                                                                                                                                                                      |
| 10.6*          |       | —     |       | Separation Agreement and General Release, dated  effective as of April 7, 2006 between Linn Energy, LLC and its  subsidiaries and Gerald Merriam (incorporated herein by reference to  Exhibit 10.4 to the April 18, 2006 Form 8-K)                                                                                                                                                                                                                                          |
| 10.7           |       | —     |       | First Amendment to Amended and Restated Credit  Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as  Administrative Agent, and the Lender signatory thereto, effective as of  May 5, 2006 (incorporated herein by reference to Exhibit 10.23 to the  Annual Report on Form 10-K filed by Linn Energy, LLC on May 31, 2006)                                                                                                                                                   |
| 10.8*          |       | —     |       | Separation and General Release, dated effective as  of June 5, 2006 between Linn Energy, LLC and its subsidiaries and Donald T.  Robinson (incorporated herein by reference to Exhibit 10.1 to the Current  Report on Form 8-K filed by Linn Energy, LLC on June 6, 2006)                                                                                                                                                                                                                        |
| 10.9*          |       | —     |       | 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)                                                                                                                                                                                                                                                    |
| 10.10          |       | —     |       | 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”)) |
| 10.11          |       | —     |       | 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)                                                                                 |
| 10.12          |       | —     |       | 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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| 10.13  |   | — |   | 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) |
|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.14* |   | — |   | 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)       |
| 31.1** |   | — |   | Rule 13a-14(a)/15d-14(a) Certification of  Michael C. Linn, Chairman, President and Chief Executive Officer of Linn  Energy, LLC (filed herewith)                                                                                                             |
| 31.2** |   | — |   | Rule 13a-14(a)/15d-14(a) Certification of Kolja  Rockov, Executive Vice President and Chief Financial Officer of Linn Energy,  LLC (filed herewith)                                                                                                           |
| 32.1** |   | — |   | Section 1350 Certification of Michael C. Linn,  Chairman, President and Chief Executive Officer of Linn Energy, LLC (filed  herewith)                                                                                                                         |
| 32.2** |   | — |   | Section 1350 Certification of Kolja Rockov,  Executive Vice President and Chief Financial Officer of Linn Energy, LLC  (filed herewith)                                                                                                                       |

 

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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: August 15,  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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