**UNITEDSTATES SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**Form 10-Q**

| **x**                                                                                                                                                                                                                                                                                     | **QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)  OF THE SECURITIES EXCHANGE ACT OF 1934**  |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------|
| ** **                                                                                                                                                                                                                                                                                |
| **For the  Quarterly Period Ended June 30, 2007**                                                                                                                                                                                                                                    |
| ** **                                                                                                                                                                                                                                                                                |
| **OR**                                                                                                                                                                                                                                                                                    |
| ** **                                                                                                                                                                                                                                                                                |
| **o**                                                                                                                                                                                                                                                                                     | **TRANSITION REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
| ** **                                                                                                                                                                                                                                                                                |
| **for the  transition period from                       to                     ** |
|                                                                                                                                                                                                                                                                                      |
| **Commission  File Number: 000-51719**                                                                                                                                                                                                                                                    |

 

**LINNENERGY, LLC**

(Exact name of registrant as specified in its charter)

| **Delaware**                                                 |   | **65-1177591**       |
|--------------------------------------------------------------|--------|----------------------|
| (State or other  jurisdiction of incorporation or            |   | (IRS Employer        |
| organization)                                                |   | Identification  No.) |
| * *                                                     |   | * *             |
| **600  Travis, Suite 5100**                                  |   |                 |
| **Houston,  Texas**                                          |   | **77002**            |
| (Address of  principal executive offices)                    |   | (Zip Code)           |
|                                                         |   |                 |
| **(281) 840-4000**                                      |
| *(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 July 31, 2007,there were 65,629,506 unitsoutstanding.

 

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**TABLE OFCONTENTS**
| ** ** | ** ** | ** **                                                                                                                      | ** ** | **Page** |
|------------|------------|---------------------------------------------------------------------------------------------------------------------------------|------------|----------|
|            | ** ** | **Glossary  of Terms**                                                                                                          |       | ii       |
|       |       |                                                                                                                            |       |     |
|       | ** ** | **Part I - Financial  Information**                                                                                             |       |     |
| Item 1.    |       | Financial Statements                                                                                                            |       |     |
|       |       | Condensed  Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006                                 |       | 1        |
|       |       | Condensed  Consolidated Statements of Operations for the three and six months ended  June 30, 2007 and 2006                |       | 3        |
|       |       | Condensed  Consolidated Statements of Unitholders’ Capital for the three and six months  ended June 30, 2007 and 2006 |       | 4        |
|       |       | Condensed  Consolidated Statements of Cash Flows for the six months ended June 30,  2007 and 2006                          |       | 5        |
|       |       | Notes to  Condensed Consolidated Financial Statements (Unaudited)                                                               |       | 7        |
| Item 2.    |       | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                                     |       | 21       |
| Item 3.    |       | Quantitative  and Qualitative Disclosures About Market Risk                                                                     |       | 35       |
| Item 4.    |       | Controls and  Procedures                                                                                                        |       | 37       |
|       | ** ** | **Part II - Other  Information**                                                                                                |       |     |
| Item 1.    |       | Legal Proceedings                                                                                                               |       | 39       |
| Item  1A.  |       | Risk  Factors                                                                                                                   |       | 39       |
| Item 2.    |       | Unregistered  Sales of Equity Securities and Use of Proceeds                                                                    |       | 43       |
| Item 3.    |       | Defaults Upon  Senior Securities                                                                                                |       | 43       |
| Item 4.    |       | Submission of  Matters to a Vote of Security Holders                                                                            |       | 43       |
| Item 5.    |       | Other Information                                                                                                               |       | 43       |
| Item  6.   |       | Exhibits                                                                                                                        |       | 44       |
|       | ** ** | **Signature**                                                                                                                   |       | 46       |

 

i

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**GLOSSARYOF TERMS**

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

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

*Bcf.*  One billion cubic feet.

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

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

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

*Dth.*  One decatherm, equivalent to one millionBritish thermal units.

*Developed acres.*  Acres spaced or assigned to productive wells.

*Dry hole* or*well.* A well found to be incapable of producing hydrocarbons in sufficientquantities such that proceeds from the sale of such production would exceedproduction expenses and taxes.

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

*FERC. *FederalEnergy Regulatory Commission.

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

*MBbls.*  One thousand barrels of oil or other liquidhydrocarbons.

*Mcf.*  One thousand cubic feet.

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

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

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

*MMBtu.*  One million British thermal units.

*MMcf.*  One million cubic feet.

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

*MMcfe/d.* One MMcfe per day.

*MMMBtu.*  One billion British thermal units.

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

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

*NYMEX.*  The New York Mercantile Exchange.

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

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

ii

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*Proveddeveloped reserves.* Reserves that can be expected to be recovered through existing wellswith existing equipment and operating methods. Additional oil and gas expected to be obtained through the applicationof fluid injection or other improved recovery techniques for supplementing thenatural forces and mechanisms of primary recovery are included in “proveddeveloped reserves” only after testing by a pilot project or after theoperation of an installed program has confirmed through production responsethat increased recovery will be achieved.

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

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

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

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

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

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

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

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

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

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

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

iii

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**PART I – FINANCIAL INFORMATION**

**Item 1.        Financial Statements**

**LINN ENERGY, LLC**

**CONDENSED CONSOLIDATED BALANCE SHEETS**
| ** **                                                                | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                | ** ** | **2007**                | ** ** | **2006**              | ** ** |
| ** **                                                                | ** ** | **(Unaudited)**         | ** ** | ** **            | ** ** |
| ** **                                                                | ** ** | **(in thousands)** | ** ** |
| **Assets**                                                                |       |                    |       |                  |       |
| **Current assets:**                                                       |       |                    |       |                  |       |
| Cash and cash  equivalents                                                |       | $                       | 958        |                  | $          | 6,595 |   |
| Receivables –  trade, net                                            |       | 43,222                  |       | 19,124                |       |
| Inventory                                                                 |       | 599                     |       | 578                   |       |
| Current portion  of derivatives                                           |       | 29,402                  |       | 37,817                |       |
| Current portion  of deferred tax assets, net                              |       | —                  |       | 3,344                 |       |
| Other current  assets                                                     |       | 1,669                   |       | 2,218                 |       |
| Total current  assets                                                     |       | 75,850                  |       | 69,676                |       |
| ** **                                                                |       |                    |       |                  |       |
| Oil and gas properties  and related equipment (successful efforts method) |       | 1,370,824               |       | 766,638               |       |
| Less accumulated  depreciation, depletion and amortization                |       | (56,311                 | )          | (33,349               | )          |
|                                                                      |       | 1,314,513               |       | 733,289               |       |
|                                                                      |       |                    |       |                  |       |
| Property and equipment,  net                                              |       | 27,152                  |       | 20,754                |       |
|                                                                      |       |                    |       |                  |       |
| **Other assets:**                                                         |       |                    |       |                  |       |
| Long-term  portion of derivatives                                         |       | 65,333                  |       | 70,435                |       |
| Deposit for oil  and gas properties                                       |       | —                  |       | 20,086                |       |
| Deferred  financing fees and other assets, net                            |       | 7,312                   |       | 2,068                 |       |
|                                                                      |       | 72,645                  |       | 92,589                |       |
| Total assets                                                              |       | $                       | 1,490,160  |                  | $          | 916,308 |   |

 

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

1

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| ** **                                                                                                                   | ** ** | **June 30,**                                       | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                   | ** ** | **2007**                                                | ** ** | **2006**              | ** ** |
| ** **                                                                                                                   | ** ** | **(Unaudited)**                                         | ** ** | ** **            | ** ** |
| ** **                                                                                                                   | ** ** | **(in thousands,  except unit amounts)** | ** ** |
| **Liabilities and Unitholders’ Capital**                                                                                | ** ** | ** **                                              | ** ** | ** **            | ** ** |
| ** **                                                                                                                   |       |                                                    |       |                  |       |
| **Current  liabilities:**                                                                                                    |       |                                                    |       |                  |       |
| Current portion of long-term notes payable                                                                                   |       | $                                                       | 999        |                  | $          | 873 |   |
| Accounts payable and accrued expenses                                                                                        |       | 24,464                                                  |       | 12,506                |       |
| Current portion of derivatives                                                                                               |       | 4,661                                                   |       | 462                   |       |
| Revenue payable                                                                                                              |       | 4,832                                                   |       | 1,839                 |       |
| Accrued interest payable                                                                                                     |       | 2,135                                                   |       | 2,084                 |       |
| Gas purchases payable                                                                                                        |       | 329                                                     |       | 253                   |       |
| Total current liabilities                                                                                                    |       | 37,420                                                  |       | 18,017                |       |
|                                                                                                                         |       |                                                    |       |                  |       |
| **Long-term  liabilities:**                                                                                                  |       |                                                    |       |                  |       |
| Notes payable                                                                                                                |       | 2,128                                                   |       | 2,487                 |       |
| Credit facility                                                                                                              |       | 476,000                                                 |       | 425,750               |       |
| Asset retirement obligation                                                                                                  |       | 16,094                                                  |       | 8,594                 |       |
| Derivatives                                                                                                                  |       | 34,870                                                  |       | 10,357                |       |
| Other long-term liabilities                                                                                                  |       | 1,589                                                   |       | 149                   |       |
| Total long-term liabilities                                                                                                  |       | 530,681                                                 |       | 447,337               |       |
| Total liabilities                                                                                                            |       | 568,101                                                 |       | 465,354               |       |
| ** **                                                                                                                   |       |                                                    |       |                  |       |
| **Unitholders’  capital:**                                                                                              |       |                                                    |       |                  |       |
| 65,605,765 units and 33,617,187 units issued and  outstanding at June 30, 2007 and December 31, 2006, respectively |       | 990,702                                                 |       | 246,034               |       |
| 9,185,965 Class B units issued and outstanding  at December 31, 2006                                               |       | —                                                  |       | 188,590               |       |
| Accumulated income (loss)                                                                                                    |       | (68,643                                                 | )          | 16,330                |       |
|                                                                                                                         |       | 922,059                                                 |       | 450,954               |       |
| Total  liabilities and unitholders’ capital                                                                             |       | $                                                       | 1,490,160  |                  | $          | 916,308 |   |

 

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

2

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF OPERATIONS**

**(Unaudited)**
| ** **                                   | ** ** | **Three Months Ended June 30,**                  | ** ** | **Six Months Ended June 30,** | ** ** |
|----------------------------------------------|------------|----------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                   | ** ** | **2007**                                                             | ** ** | **2006**                                          | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                   | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                |       |                                                                 |       |                                              |       |   |   |   |   |
| Oil, gas and natural gas liquid sales        |       | $                                                                    | 49,217     |                                              | $          | 13,529 |   | $ | 88,421 |   | $ | 29,904 |   |
| Gain (loss) on oil and gas derivatives       |       | (17,707                                                              | )          | 12,895                                            |       | (78,148 | ) | 37,141 |   |
| Natural gas marketing revenues               |       | 1,139                                                                |       | 1,346                                             |       | 2,917 |   | 2,564 |   |
| Other revenues                               |       | 1,139                                                                |       | 204                                               |       | 3,229 |   | 493 |   |
|                                         |       | 33,788                                                               |       | 27,974                                            |       | 16,419 |   | 70,102 |   |
| **Expenses:**                                |       |                                                                 |       |                                              |       |   |   |   |   |
| Operating expenses                           |       | 14,714                                                               |       | 2,933                                             |       | 27,170 |   | 5,927 |   |
| Natural gas marketing expenses               |       | 879                                                                  |       | 1,189                                             |       | 2,226 |   | 2,172 |   |
| General and administrative expenses          |       | 12,537                                                               |       | 6,928                                             |       | 23,158 |   | 16,398 |   |
| Depreciation, depletion and amortization     |       | 12,938                                                               |       | 4,116                                             |       | 24,789 |   | 7,816 |   |
|                                         |       | 41,068                                                               |       | 15,166                                            |       | 77,343 |   | 32,313 |   |
|                                         |       | (7,280                                                               | )          | 12,808                                            |       | (60,924 | ) | 37,789 |   |
| **Other  income and (expenses):**            |       |                                                                 |       |                                              |       |   |   |   |   |
| Interest income                              |       | 156                                                                  |       | 92                                                |       | 302 |   | 238 |   |
| Interest expense, net of amounts capitalized |       | (9,952                                                               | )          | (2,696                                            | )          | (19,865 | ) | (5,335 | ) |
| Other expenses                               |       | (20                                                                  | )          | (158                                              | )          | (824 | ) | (550 | ) |
|                                         |       | (9,816                                                               | )          | (2,762                                            | )          | (20,387 | ) | (5,647 | ) |
| Income (loss)  before income taxes           |       | (17,096                                                              | )          | 10,046                                            |       | (81,311 | ) | 32,142 |   |
| Income tax benefit (provision)               |       | (30                                                                  | )          | 193                                               |       | (3,662 | ) | 74 |   |
| Net income (loss)                            |       | $                                                                    | (17,126    | )                                                 | $          | 10,239 |   | $ | (84,973 | ) | $ | 32,216 |   |
| ** **                                   |       |                                                                 |       |                                              |       |   |   |   |   |
| **Net  income (loss) per unit:**             |       |                                                                 |       |                                              |       |   |   |   |   |
| Units  – basic                          |       | $                                                                    | (0.29      | )                                                 | $          | 0.37 |   | $ | (1.62 | ) | $ | 1.19 |   |
| Units – diluted                         |       | $                                                                    | (0.29      | )                                                 | $          | 0.36 |   | $ | (1.62 | ) | $ | 1.18 |   |
|                                         |       |                                                                 |       |                                              |       |   |   |   |   |
| **Weighted  average units outstanding:**     |       |                                                                 |       |                                              |       |   |   |   |   |
| Units – basic                           |       | 59,293                                                               |       | 27,830                                            |       | 52,413 |   | 27,056 |   |
| Units – diluted                         |       | 59,293                                                               |       | 28,094                                            |       | 52,413 |   | 27,325 |   |
|                                         |       |                                                                 |       |                                              |       |   |   |   |   |
| Distributions declared  per unit             |       | $                                                                    | 0.52       |                                              | $          | 0.32 |   | $ | 1.04 |   | $ | 0.32 |   |

 

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

3

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL**

**(Unaudited)**
| ** **                                                              | ** ** | **Three Months Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|-------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                              | ** ** | **2007**                                            | ** ** | **2006**                                          | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                              | ** ** | **(in thousands)**                             | ** ** |
| **Unitholders’  capital:**                                         |       |                                                |       |                                              |       |   |   |   |   |
| Balance, beginning of period                                            |       | $                                                   | 761,360    |                                              | $          | 146,065 |   | $ | 434,624 |   | $ | 16,024 |   |
| Sale of units, net of expenses of $4,339                                |       | —                                              |       | —                                            |       | — |   | 225,139 |   |
| Sale of private placement units, net of expenses of  $4,608 and $11,468 |       | 255,392                                             |       | —                                            |       | 608,532 |   | — |   |
| Cancellation of member interests                                        |       | —                                              |       | —                                            |       | — |   | (100,778 | ) |
| Cancellation of units                                                   |       | —                                              |       | —                                            |       | (7,399 | ) | — |   |
| Distribution to members                                                 |       | (30,001                                             | )          | (8,826                                            | )          | (52,746 | ) | (8,826 | ) |
| Unit-based compensation expense                                         |       | 3,057                                               |       | 4,116                                             |       | 6,315 |   | 9,796 |   |
| Unit warrant expense                                                    |       | 894                                                 |       | —                                            |       | 1,376 |   | — |   |
| Balance, end of period                                                  |       | 990,702                                             |       | 141,355                                           |       | 990,702 |   | 141,355 |   |
| **Accumulated  income (loss):**                                         |       |                                                |       |                                              |       |   |   |   |   |
| Balance, beginning of period                                            |       | (51,517                                             | )          | (40,878                                           | )          | 16,330 |   | (62,855 | ) |
| Net income (loss)                                                       |       | (17,126                                             | )          | 10,239                                            |       | (84,973 | ) | 32,216 |   |
| Balance, end of period                                                  |       | (68,643                                             | )          | (30,639                                           | )          | (68,643 | ) | (30,639 | ) |
| **Treasury  units (at cost):**                                          |       |                                                |       |                                              |       |   |   |   |   |
| Balance, beginning of period                                            |       | —                                              |       | —                                            |       | — |   | — |   |
| Purchase of units                                                       |       | —                                              |       | —                                            |       | (7,399 | ) | — |   |
| Sale of units                                                           |       | —                                              |       | —                                            |       | — |   | 13,671 |   |
| Redemption of member interests                                          |       | —                                              |       | —                                            |       | — |   | (114,449 | ) |
| Cancellation of member interests                                        |       | —                                              |       | —                                            |       | — |   | 100,778 |   |
| Cancellation of units                                                   |       | —                                              |       | —                                            |       | 7,399 |   | — |   |
| Balance, end of period                                                  |       | —                                              |       | —                                            |       | — |   | — |   |
| Total  unitholders’ capital                                        |       | $                                                   | 922,059    |                                              | $          | 110,716 |   | $ | 922,059 |   | $ | 110,716 |   |

 

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

4

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

**CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS**

**(Unaudited)**
| ** **                                                                                       | ** ** | **Six Months Ended June 30,** | ** ** |
|--------------------------------------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                                                       | ** ** | **2007**                                          | ** ** | **2006** | ** ** |
| ** **                                                                                       | ** ** | **(in thousands)**                           | ** ** |
| **Cash  flow from operating activities:**                                                        |       |                                              |       |   |   |
| Net income (loss)                                                                                |       | $                                                 | (84,973    | ) | $ | 32,216 |   |
| **Adjustments to reconcile net income to net cash  provided by (used in) operating activities:** |       |                                              |       |   |   |
| Depreciation, depletion and amortization                                                         |       | 24,789                                            |       | 7,816 |   |
| Amortization and write-off of deferred financing  fees and other                                 |       | 904                                               |       | 812 |   |
| Gain on sale of assets                                                                           |       | (885                                              | )          | — |   |
| Accretion of asset retirement obligation                                                         |       | 334                                               |       | 119 |   |
| Unit-based compensation and unit warrant expense                                                 |       | 7,691                                             |       | 9,796 |   |
| Deferred income tax                                                                              |       | 3,360                                             |       | (307 | ) |
| **Mark-to-market  on derivatives:**                                                              |       |                                              |       |   |   |
| Total (gains) losses                                                                             |       | 77,951                                            |       | (37,888 | ) |
| Realized gains                                                                                   |       | 13,504                                            |       | 5,592 |   |
| **Premiums  paid for derivatives**                                                               |       | (52,992                                           | )          | (5,803 | ) |
| **Changes  in assets and liabilities:**                                                          |       |                                              |       |   |   |
| (Increase) decrease in accounts receivable                                                       |       | (21,654                                           | )          | 7,993 |   |
| Decrease in inventory and other assets                                                           |       | 528                                               |       | 3,809 |   |
| Decrease in derivative receivables                                                               |       | 3,766                                             |       | — |   |
| Increase (decrease) in accounts payable and accrued  expenses                                    |       | 3,731                                             |       | (5,791 | ) |
| Increase in accrued interest payable                                                             |       | 51                                                |       | 725 |   |
| Increase (decrease) in revenue payable                                                           |       | 2,993                                             |       | (4,889 | ) |
| Increase (decrease) in gas purchases payable                                                     |       | 76                                                |       | (331 | ) |
| Increase in other liabilities                                                                    |       | 1,439                                             |       | 223 |   |
| Net cash provided by (used in) operating activities                                              |       | (19,387                                           | )          | 14,092 |   |
| **Cash  flow from investing activities:**                                                        |       |                                              |       |   |   |
| Acquisition of oil and gas properties                                                            |       | (539,304                                          | )          | (44,679 | ) |
| Development of oil and gas properties                                                            |       | (43,478                                           | )          | (19,429 | ) |
| Purchases of property and equipment                                                              |       | (7,486                                            | )          | (1,668 | ) |
| Proceeds from sale of assets                                                                     |       | 2,934                                             |       | 25 |   |
| Net cash used in investing activities                                                            |       | (587,334                                          | )          | (65,751 | ) |
| **Cash  flow from financing activities:**                                                        |       |                                              |       |   |   |
| Proceeds from sale of units                                                                      |       | 620,000                                           |       | 243,149 |   |
| Redemption and cancellation of units                                                             |       | (7,399                                            | )          | (114,449 | ) |
| Principal payments on notes payable                                                              |       | (442                                              | )          | (60,516 | ) |
| Proceeds from credit facility                                                                    |       | 308,000                                           |       | 48,303 |   |
| Payments on credit facility                                                                      |       | (257,750                                          | )          | (62,000 | ) |
| Distribution to members                                                                          |       | (52,746                                           | )          | (8,826 | ) |
| Offering costs                                                                                   |       | (6,917                                            | )          | (844 | ) |
| Financing fees                                                                                   |       | (1,662                                            | )          | (564 | ) |
| Net cash provided by financing activities                                                        |       | 601,084                                           |       | 44,253 |   |
| Net decrease in cash                                                                             |       | (5,637                                            | )          | (7,406 | ) |
| **Cash  and cash equivalents:**                                                                  |       |                                              |       |   |   |
| Beginning                                                                                        |       | 6,595                                             |       | 11,041 |   |
| Ending                                                                                           |       | $                                                 | 958        |   | $ | 3,635 |   |

 

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

5

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

**CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS –SUPPLEMENTAL DISCLOSURES**

**(Unaudited)**
| ** **                                                                                       | ** ** | **Six Months Ended June 30,** | ** ** |
|--------------------------------------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                                                       | ** ** | **2007**                                          | ** ** | **2006** | ** ** |
| ** **                                                                                       | ** ** | **(in thousands)**                           | ** ** |
| **Supplemental  disclosure of cash flow information:**                                           |       |                                              |       |   |   |
| Cash payments for interest                                                                       |       | $                                                 | 19,656     |   | $ | 4,957 |   |
| **Supplemental  disclosures of non-cash investing and financing activities:**                    |       |                                              |       |   |   |
| Acquisitions of vehicles and equipment through  issuance of notes payable                        |       | $                                                 | 237        |   | $ | 2,097 |   |
| In connection with the purchase of oil and gas  properties, liabilities were assumed as follows: |       |                                              |       |   |   |
| Fair value of assets acquired                                                                    |       | $                                                 | 545,789    |   | $ | 45,173 |   |
| Cash paid                                                                                        |       | (539,304)                                         |       | (44,679) |   |
| Liabilities  assumed                                                                             |       | $                                                 | 6,485      |   | $ | 494 |   |

 

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

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**LINN ENERGY, LLC**

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS**

**(Unaudited)**

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

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

The condensedconsolidated financial statements at June 30, 2007, and for the three andsix months ended June 30, 2007 and 2006, are unaudited, but in the opinionof management 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 United States generally accepted accounting principles (“GAAP”)have been 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 endedDecember 31, 2006.  Certain amountsin the condensed consolidated financial statements and notes thereto have beenreclassified to conform to the 2007 financial statement presentation.

The condensedconsolidated financial statements include the accounts of the Company and itswholly-owned subsidiaries.  Allsignificant intercompany transactions and balances have been eliminated uponconsolidation.

Management of the Companyhas made a number of estimates and assumptions relating to the reporting ofassets and liabilities and revenues and expenses and the disclosure ofcontingent assets and liabilities to prepare these condensed consolidatedfinancial statements in conformity with GAAP. Actual results could differ from those estimates.  The estimates that are particularlysignificant to the financial statements include estimates of oil, gas andnatural gas liquid (“NGL”) reserves, future cash flows from oil and gasproperties, depreciation, depletion and amortization, asset retirementobligations, the fair value of derivatives and unit-based compensation expense.

As of June 30, 2007,there have been no significant changes with regard to the critical accountingpolicies disclosed in the Company’s Annual Report on Form 10-K forthe year ended December 31, 2006. The policies disclosed included the accounting for oil and gasproperties, reserve quantities, revenue recognition, purchase accounting andderivative instruments.  Several of ourmore significant accounting policies are summarized below.

***Oiland Gas Properties***

TheCompany accounts for oil and gas properties by the successful effortsmethod.  Leasehold acquisition costs arecapitalized.  If proved reserves arefound on an undeveloped property, leasehold costs are transferred to provedproperties.  Under this method ofaccounting, costs relating to the development of proved areas are capitalizedwhen incurred.  Geological, geophysical,and exploratory dry hole costs on oil and gas properties relating tounsuccessful exploratory wells are charged to expense as incurred.

7

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Depreciationand depletion of producing oil and gas properties is recorded based on units ofproduction.  Unit rates are computed forunamortized drilling and development costs using proved developed reserves andfor unamortized leasehold costs using all proved reserves.  Statement of Financial Accounting Standards (“SFAS”)No. 19, as amended, “Financial Accounting and Reporting by Oil and Gas ProducingCompanies” (“SFAS 19”), requires that acquisition costs of provedproperties be amortized on the basis of all proved reserves, developed andundeveloped, and that capitalized development costs (wells and relatedequipment and facilities) be amortized on the basis of proved developedreserves.

***DerivativeInstruments and Hedging Activities***

TheCompany uses derivative financial instruments to achieve a more predictablecash flow from its oil, gas and NGL production by reducing its exposure toprice fluctuations.  As of June 30,2007, these transactions were in the form of swaps and puts.  Additionally, the Company uses derivativefinancial instruments in the form of interest rate swaps to mitigate itsinterest rate exposure.  The Companyaccounts for its derivatives at fair value as an asset or liability and thechange in the fair value of derivatives is included in income.  The Company accounts for these activitiespursuant to SFAS No. 133, “*Accountingfor Derivative Instruments and Hedging Activities,”* as amended, (“SFAS 133”).  This statement establishes accounting andreporting standards requiring that derivative instruments (including certainderivative instruments embedded in other contracts) be recorded at fair valueand included in the balance sheets as assets or liabilities.  None of the Company’s commodity or interestrate derivatives are designated as hedges under SFAS 133 and therefore thechange in the fair value of the derivatives is included in the condensedconsolidated statements of operations. See Note 9 and Note 10 for additional discussion related toderivative financial instruments.

***Unit-BasedCompensation***

Underthe provisions of the Linn Energy, LLC Long-Term Incentive Plan, which isadministered by the Compensation Committee of the Board of Directors, theCompany has awarded unit grants, unit options, restricted units, and phantomunits to employees and non-employee directors. The unit options and restricted units vest ratably over one to three yearsfrom the grant date of the award, unless other contractual arrangements aremade.  The contractual life of unitoptions is ten years.  See Note 12for details regarding unit-based compensation granted during the six monthsended June 30, 2007.

TheCompany accounts for unit-based compensation under the provisions ofSFAS No. 123 (revised 2004),*“ShareBased Payment”* (“SFAS 123R”). SFAS 123R requires the recognition of compensation expense, over therequisite service period, in an amount equal to the fair value of unit-basedpayments granted.

***RecentlyIssued Accounting Standards***

InJune 2007, the Financial Accounting Standards Board (“FASB”) ratified theconsensus in Emerging Issues Task Force Issue 06-11 (“EITF 06-11”).  EITF 06-11 is effective for fiscal yearsbeginning after December 15, 2007 and requires, among other things, recognitionas an increase to additional paid-in capital the realized income tax benefitfrom dividends or dividend equivalents that are paid to employees and chargedto retained earnings.  The Company is inthe process of evaluating the impact of EITF 06-11 on its results of operationsand financial position, but does not expect it will be material.

InApril 2007, the FASB issued Staff Position No. 39-1, “Amendment of FASBInterpretation No. 39” (“FSP No. FIN 39-1”).  The terms “conditional contracts” and “exchangecontracts” have been replaced with the more general term “derivative contracts.”  In addition, FSP No. FIN 39-1permits the offsetting of recognized fair values for the right to reclaim cashcollateral or the obligation to return cash collateral against fair values ofderivatives under certain circumstances, such as under master nettingarrangements.  Additional disclosure isalso required regarding a Company’s accounting policy with respect tooffsetting fair value amounts.  Theguidance in FSP No. FIN 39-1 is effective for fiscal years beginning afterNovember 15, 2007, with early application allowed.  The effects of initial adoption should berecognized as a change in accounting principle through retrospectiveapplication for all periods presented. The Company 

8

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doesnot believe that the adoption of FSP No. FIN 39-1 will have amaterial impact on its results of operations or financial position.

InFebruary 2007, the FASB issued SFAS No. 159, “The Fair Value Option forFinancial Assets and Financial Liabilities, including an amendment of FASBStatement No. 115” (“SFAS 159”), which permits companies to choose, atspecified dates, to measure certain eligible financial instruments at fairvalue.  The objective of SFAS 159 isto reduce volatility in preparer reporting that may be caused as a result ofmeasuring related financial assets and liabilities differently and to expandthe use of fair value measurements.  Theprovisions of SFAS 159 apply only to entities that elect to use the fairvalue option and to all entities with available-for-sale and tradingsecurities.  Additional disclosures arealso required for instruments for which the fair value option is elected.  SFAS 159 is effective for fiscal yearsbeginning after November 15, 2007. No retrospective application is allowed, except for companies thatchoose to adopt early.  At the effectivedate, companies may elect the fair value option for eligible items that existat that date, and the effect of the first remeasurement to fair value must bereported as a cumulative-effect adjustment to the opening balance of retainedearnings.  The Company is currentlyevaluating what impact, if adopted, SFAS 159 may have on its results ofoperations or financial position.

**(2)****           Acquisitions and Dispositions**

On February 1, 2007, effective January 1,2007, the Company completed the acquisition of certain oil and gas propertiesand related assets in the Texas Panhandle from Stallion Energy LLC, acting asgeneral partner for Cavallo Energy, LP, for $415.0 million, subject tocustomary closing adjustments (“Panhandle I”).  The Panhandle I acquisition was financedwith a combination of a private placement of our units (see Note 3) andborrowings under the Company’s senior secured revolving credit facility (seeNote 6).

On June 12, 2007, effective April 1, 2007,the Company completed the acquisition of certain oil and gas properties in theTexas Panhandle for $90.5 million, subject to customary closing adjustments (“Panhandle II”).  The acquisition was financed with borrowingsunder the Company’s senior secured revolving credit facility.

The following table presents the preliminary purchaseprices for the Panhandle I and Panhandle II acquisitions based onpreliminary estimates of fair value:
|                                    | ** ** | **Panhandle I**    | ** ** | **Panhandle II** | ** ** |
|------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                         | ** ** | **(in thousands)** | ** ** |
|                               |       |                    |       |                  |       |
| Cash                               |       | $                       | 411,287    |                  | $          | 90,179 |   |
| Estimated  transaction costs       |       | 2,996                   |       | 366                   |       |
| Estimated  closing adjustments     |       | —                  |       | (1,440                | )          |
|                               |       | 414,283                 |       | 89,105                |       |
| Fair value of  liabilities assumed |       | 1,706                   |       | 1,034                 |       |
| Total purchase  price              |       | $                       | 415,989    |                  | $          | 90,139 |   |

 

9

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The following tablepresents the preliminary allocation of the purchase prices based on preliminaryestimates of fair value:
|                         | ** ** | **Panhandle I**    | ** ** | **Panhandle II** | ** ** |
|-------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **              | ** ** | **(in thousands)** | ** ** |
|                    |       |                    |       |                  |       |
| Oil and gas  properties |       | $                       | 415,251    |                  | $          | 89,495 |   |
| Vehicles and  buildings |       | 738                     |       | —                |       |
| Receivables, net        |       | —                  |       | 644                   |       |
|                    |       | $                       | 415,989    |                  | $          | 90,139 |   |

 

The preliminary purchaseprice allocations are based on discounted cash flows, independent appraisals offixed assets, quoted market prices and estimates by management.  The most significant assumptions are relatedto the estimated fair values assigned to proved oil and gas properties.  To estimate the fair values of theseproperties, we utilized estimates of oil, gas and NGL reserves prepared by anindependent engineering firm.  Weestimated future prices to apply to the estimated reserve quantities acquired,and estimated future operating and development costs, to arrive at estimates offuture net revenues.  For estimatedproved reserves, the future net revenues were discounted using a market-basedweighted average cost of capital rate determined appropriate at the time of theacquisition.  The market-based weightedaverage cost of capital rate was subjected to additional project-specific riskfactors.  There were no fair valuesassigned to unproved properties with the Texas Panhandle acquisitions.  As noted, the purchase price allocations arepreliminary; they are subject to final closing adjustments and will be finalizedwithin one year of the acquisition dates.

The following unauditedpro forma financial information presents a summary of Linn’s consolidatedresults of operations for the three and six months ended June 30, 2007 and2006, assuming the Panhandle I and Panhandle II acquisitions had beencompleted as of January 1, 2006, including adjustments to reflect theallocation of the purchase prices to the acquired net assets.  The pro forma financial information alsoassumes the Company’s February 2007 private placement of units (seeNote 3) was completed on January 1, 2006, since the private placementwas contingent on completion of the Panhandle I acquisition.  In addition, the pro forma financialinformation assumes that our California acquisitions of certain affiliatedentities of Blacksand Energy, LLC and certain Oklahoma assets of theKaiser-Francis Oil Company were completed as of January 1, 2006.  The California and Oklahoma acquisitions werecompleted in 2006 and the revenues and expenses are included in the consolidatedresults of the Company effective August 1, 2006 and September 1,2006, respectively.  The revenues andexpenses of the Panhandle I and Panhandle II assets are included inthe consolidated results of the Company as of February 1, 2007 andJune 12, 2007, respectively.  Thepro forma financial information is not necessarily indicative of the results ofoperations if the acquisitions had been effective as of these dates.

10

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|                                    | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                         | ** ** | **2007**                                        | ** ** | **2006**                                      | ** ** | **2007** | ** ** | **2006** | ** ** |
|                               |       |                                            |       |                                          |       |   |   |   |   |
| Total revenues                     |       | $                                               | 36,767     |                                          | $          | 68,179 |   | $ | 27,312 |   | $ | 171,077 |   |
| Total operating  expenses          |       | $                                               | 43,984     |                                          | $          | 34,921 |   | $ | 86,539 |   | $ | 70,234 |   |
| Net income  (loss)                 |       | $                                               | (18,268    | )                                             | $          | 19,652 |   | $ | (86,148 | ) | $ | 73,197 |   |
|                               |       |                                            |       |                                          |       |   |   |   |   |
| Net income (loss)  per unit:       |       |                                            |       |                                          |       |   |   |   |   |
| Units – basic                 |       | $                                               | (0.31      | )                                             | $          | 0.47 |   | $ | (1.64 | ) | $ | 1.78 |   |
| Units – diluted               |       | $                                               | (0.31      | )                                             | $          | 0.47 |   | $ | (1.64 | ) | $ | 1.77 |   |
|                               |       |                                            |       |                                          |       |   |   |   |   |
| Class C units – basic    |       | $                                               | —     |                                          | $          | 0.47 |   | $ | — |   | $ | 1.78 |   |
| Class C  units – diluted |       | $                                               | —     |                                          | $          | 0.47 |   | $ | — |   | $ | 1.77 |   |

 

The 2006 pro formaresults of operations present net income per unit allocated to the units andClass C units.  In April 2007,unitholders approved the one-for-one conversion of each of the Class Cunits into units (see Note 3). Therefore, pro forma net income per unit assumes that the units andClass C units share equally in the pro forma net income of the Company.

In January 2007, the Company completed theacquisitions of certain gas properties located in the Appalachian Basin of WestVirginia for an aggregate price of $39.0 million, subject to customary closingadjustments.

In March 2007, the Company sold certain of its oil andgas properties located in New York for cash of approximately $2.5 millionand recorded a gain of approximately $0.9 million.  The gain is included in “other revenues” onthe condensed consolidated statements of operations.

On June 29, 2007, the Company entered into adefinitive purchase agreement with Dominion Resources, Inc. and certainaffiliates (“Dominion”) to acquire certain oil and gas properties in theMid-Continent, in Oklahoma, Kansas and the Texas Panhandle (the “Mid-ContinentAcquisition”) for $2.05 billion, subject to customary closingadjustments.  The Company anticipatesthat the Mid-Continent Acquisition will close during the third quarter of 2007,subject to customary closing conditions, including the Company’s receipt offinancing.  There can be no assurancethat all of the conditions to closing will be satisfied.  On June 29, 2007, the Company executed aunit purchase agreement for a private placement of $1.5 billion of unitsand Class D units to a group of institutional investors (seeNote 3).  In addition, onJune 29, 2007, the Company received a commitment from two lenders underits credit facility (see Note 6) to provide funding of up to$1.9 billion contingent on closing of the Mid-Continent Acquisition.  The Company intends to fund the Mid-ContinentAcquisition with the net proceeds from the private placement, together with borrowingsunder the credit facility.

On August 2, 2007, the Company entered into adefinitive purchase agreement to acquire certain oil and gas properties in theTexas Panhandle (the “Panhandle III Acquisition”) for $22.5 million, subject tocustomary closing adjustments.  TheCompany anticipates that the Panhandle III Acquisition will close during thethird quarter of 2007, subject to customary closing conditions.

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

***Pending Private Placement***

On June 29, 2007, the Company executed a unitpurchase agreement for a private placement of $1.5 billion of units to agroup of institutional investors, consisting of 34,997,005 Class D unitsat a price of $30.97 per unit and 12,999,989 units at a price of $32.00 perunit (“Pending Private Placement”). Proceeds, net of expenses, will be used to fund the Mid-ContinentAcquisition (see Note 2).  ThePending Private Placement is expected to coincide with the closing of theMid-Continent Acquisition and is subject to customary closing conditions, includingthe closing of the Mid-Continent Acquisition. There can be no assurance that all of the conditions to closing will besatisfied.

The Class D units will represent a class ofequity securities that is entitled to a special quarterly distribution equal to115% of the distribution received by the holders of units, has no voting rightsother than as required by law and is subordinated to the units on dissolutionand liquidation.  The Class D unitsmay convert into units if the conversion is approved by a vote of the Company’sunitholders.  The Company has agreed tohold a meeting of its unitholders to consider this proposal as soon asreasonably practicable, but no later than 120 days from the closingdate.  In connection with the PendingPrivate Placement, the Company also agreed to file a registration statementwith the SEC covering the units and the Class D units, and that theregistration statement would be declared effective by the SEC no later than 165days following the closing.

***June 2007 Private Placement***

In June 2007, the Company closed its private placementof $260.0 million of units to a group of institutional investors, consisting of7,761,194 units at a price of $33.50 per unit (the “June 2007 Private Placement”).  Proceeds, net of expenses, were $255.4million and were used to repay indebtedness under the Company’s senior securedrevolving credit facility (see Note 6). In connection with the June 2007 Private Placement, the Company alsoagreed to file a registration statement with the SEC covering the units, andthat the registration statement would be declared effective by the SEC no laterthan November 13, 2007.

***February 2007 Private Placement***

In February 2007, theCompany entered into a Class C Unit and Unit Purchase Agreement with a group of institutional investorswhereby it privately placed 7,465,946 Class C units at a price of $25.06per unit, and 6,650,144 units at a price of $26.00 per unit, for aggregategross proceeds of $360.0 million (the “February 2007 Private Placement”).  Proceeds, net of expenses, were $353.1million.  The proceeds from the February2007 Private Placement were used to finance the Panhandle I acquisitionand the acquisitions of certain gas properties in West Virginia (seeNote 2).

In April 2007, at aspecial meeting of Linn unitholders, unitholders approved the one-for-oneconversion of the Class C units into units.  In connection with the February 2007 PrivatePlacement, the Company agreed to file a registration statement with the SECcovering the units and the units underlying the Class C units, and thatthe registration statement would be declared effective by the SEC no later than165 days following the closing.  In June2007, this deadline was extended to December 31, 2007.

***October 2006 Private Placement***

In connection with itsOctober 2006 private placement of Class B units (the “October 2006 PrivatePlacement”), the Company also agreed to file a registration statement with theSEC covering the units and the units underlying the Class B units, and that theregistration statement would be declared effective by the SEC no later than 165days following the closing.  In June2007, this deadline was extended to December 31, 2007.

12

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***Liquidated Damages***

The Company could berequired to pay purchasers liquidated damages specified in agreements pursuantto the October 2006, February 2007 and June 2007 Private Placements and thePending Private Placement in the event the registration effectiveness deadlinesare not met.  The potential paymentsunder the agreements are 0.25% of the gross proceeds for each 30 day periodthat the registration deadlines are not met, up through 90 days.  Subsequent to 90 days, the potential paymentswould increase for each 30 day period, up to a maximum of 1.0% of the grossproceeds of each offering.  The Companydoes not believe it is probable that it will be required to make such payments;therefore, has not recorded a liability at this time.  The Company will continue to monitor andassess its exposure in this matter; however, the Company does not currentlyexpect payments, if any, under these agreements to be material to the Company’sfinancial position or results of operations.

***Cancellation of Units***

In January 2007, the Companypurchased 226,561 restricted units from an employee for $7.4 million (marketprice on the day of purchase) in conjunction with the vesting of restrictedunit awards.  The proceeds were used tofund the employee’s payroll taxes on the award and the Company cancelled theunits.

***Initial Public Offering***

In the first quarter of 2006, theCompany completed its initial public offering (“IPO”) of 12,450,000 unitsrepresenting limited liability company interests in the Company at $21.00 perunit, for net proceeds, after underwriting discounts of $18.3 million andoffering expenses of $4.3 million, of $238.8 million, of which $122.0 millionwas used to reduce indebtedness, $114.4 million was used to redeem a portion ofthe membership interests in the Company and units held by certain affiliatedand non-affiliated holders and approximately $2.0 million was used to paybonuses to certain executive officers of the Company.

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

Aggregate capitalized costsrelated to oil, gas and NGL production activities with applicable accumulateddepreciation, depletion and amortization are presented below:
|                                                            | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2007**                | ** ** | **2006**              | ** ** |
| ** **                                                 | ** ** | **(in thousands)** | ** ** |
|                                                       |       |                    |       |                  |       |
| Unproved  properties                                       |       | $                       | 8,216      |                  | $          | 8,624 |   |
| Proved  properties:                                        |       |                    |       |                  |       |
| Leasehold, equipment and drilling                          |       | 1,278,403               |       | 737,202               |       |
| Gas compression plant and pipelines                        |       | 84,205                  |       | 20,812                |       |
|                                                       |       | 1,370,824               |       | 766,638               |       |
| Less accumulated  depletion, depreciation and amortization |       | (56,311                 | )          | (33,349               | )          |
| Net capitalized costs                                      |       | $                       | 1,314,513  |                  | $          | 733,289 |   |

 

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

Property and equipmentconsists of the following:
|                                       | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2007**                | ** ** | **2006**              | ** ** |
| ** **                            | ** ** | **(in thousands)** | ** ** |
|                                  |       |                    |       |                  |       |
| Land                                  |       | $                       | 320        |                  | $          | 308 |   |
| Buildings and  leasehold improvements |       | 4,798                   |       | 2,759                 |       |
| Vehicles                              |       | 4,581                   |       | 3,097                 |       |
| Aircraft                              |       | 5,890                   |       | 5,890                 |       |
| Drilling  equipment                   |       | 11,707                  |       | 8,611                 |       |
| Furniture and  equipment              |       | 3,243                   |       | 1,966                 |       |
|                                  |       | 30,539                  |       | 22,631                |       |
| Less accumulated  depreciation        |       | (3,387                  | )          | (1,877                | )          |
|                                  |       | $                       | 27,152     |                  | $          | 20,754 |   |

 

Depreciation expense forthe three and six months ended June 30, 2007, was approximately $0.8million and $1.5 million, respectively. Depreciation expense for the three and six months ended June 30,2006, was approximately $0.2 million and $0.4 million, respectively.

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

At June 30, 2007,the Company had an $800.0 million senior secured revolving credit facility witha maturity of August 2010, and a borrowing base of $765.0 million (“CreditFacility”).  On June 29, 2007, theCompany received a commitment from two lenders under its Credit Facility toprovide funding of up to $1.9 billion contingent on closing of theMid-Continent Acquisition (see Note 2). In July 2007, the Company incurred approximately $4.8 million incommitment fees that will be amortized over the life of this debt agreement.

The borrowing base underthe Credit Facility will be redetermined semi-annually by the lenders in theirsole discretion, based on, among other things, reserve reports as prepared byreserve engineers taking into account the oil, gas and NGL prices at suchtime.  Our obligations under the CreditFacility are secured by mortgages on our oil and gas properties as well as apledge of all ownership interests in our operating subsidiaries.  We are required to maintain the mortgages onproperties representing at least 80% of our oil and gas properties.  Additionally, the obligations under theCredit Facility are guaranteed by all of our operating subsidiaries and may beguaranteed by any future subsidiaries.

At our election, intereston borrowings under the Credit Facility is determined by reference to LIBORplus an applicable margin between 1.00% and 1.75% per annum; or a domestic bankrate plus an applicable margin between 0.00% and 0.25% per annum.  Interest is payable quarterly for domesticbank rate loans and at the applicable maturity date for LIBOR loans.

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

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As of June 30, 2007and December 31, 2006, the Credit Facility consisted of the following:
|                         | ** ** | **June 30,**       | ** ** | **December 31,** | ** ** |
|-------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **              | ** ** | **2007**                | ** ** | **2006**              | ** ** |
| ** **              | ** ** | **(in thousands)** | ** ** |
|                    |       |                    |       |                  |       |
| Total (1)               |       | $                       | 476,000    |                  | $          | 425,750 |   |
| Less current maturities |       | —                  |       | —                |       |
|                    |       | $                       | 476,000    |                  | $          | 425,750 |   |

 

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(1)     Variable rate of 6.625%and 7.125% at June 30, 2007 and December 31, 2006, respectively.

At June 30, 2007,the Company also had $5.0 million outstanding letters of credit, which reduceits borrowing availability under the Credit Facility.  At June 30, 2007, available borrowingunder the Credit Facility was $284.0 million.

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

The Company has thefollowing long-term notes payable outstanding:

|                                                                                                                                                                                                                                                                                                                                                                                            | ** ** | **June 30,  2007** | ** ** | **December 31,  2006** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                                                                                                                                                                                                                                 | ** ** | **(in thousands)** | ** ** |
| Note payable to a bank  with an interest rate of 6.14%, payable in monthly installments of  approximately $3, including interest, through September 2024. The note is  secured by an office building.                                                                                                                                                                                      |       | $                       | 366        |                        | $          | 372 |   |
| Various notes for the  purchase of vehicles and equipment, payable in monthly installments totaling  approximately $96 and $88, as of June 30, 2007 and December 31,  2006, respectively, including interest. The interest rates range from  3.90%-9.11%. The notes are secured by the vehicles and equipment purchased  and expire at various dates from 2007 through 2011. (1) |       | 2,761                   |       | 2,988                       |       |
|                                                                                                                                                                                                                                                                                                                                                                                       |       | 3,127                   |       | 3,360                       |       |
| Less current maturities                                                                                                                                                                                                                                                                                                                                                                    |       | (999                    | )          | (873                        | )          |
|                                                                                                                                                                                                                                                                                                                                                                                       |       | $                       | 2,128      |                        | $          | 2,487 |   |

 

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(1)                    AtJune 30, 2007 and December 31, 2006, includes approximately $1.0million of notes payable on which interest was imputed at 7.0%.

15

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As of June 30, 2007,maturities on the aforementioned long-term notes payable were as follows:
|            | ** ** | **(in thousands)** | ** ** |
|------------|------------|-------------------------|------------|
|       |       |                    |       |
| 2007       |       | $                       | 480        |   |
| 2008       |       | 946                     |       |
| 2009       |       | 728                     |       |
| 2010       |       | 471                     |       |
| 2011       |       | 201                     |       |
| Thereafter |       | 301                     |       |
|       |       | $                       | 3,127      |   |

 

**(8)****           Business and Credit Concentrations**

***Cash***

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

***Revenue and Trade Receivables***

The Company has aconcentration of customers who are engaged in oil and gas production within theUnited States.  This concentration ofcustomers 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’s customers consist primarily of major oil and gas purchasersand the Company generally does not require collateral.

A majority of the Company’slargest customers are oil and gas producers, suppliers and operators.  For the three and six months endedJune 30, 2007, the Company’s three largest customers representedapproximately 28%, 22% and 13%, and 32%, 18% and 12%, respectively, of theCompany’s sales.  For the three and sixmonths ended June 30, 2006, the Company’s two largest customersrepresented approximately 65% and 9%, and 68% and 10%, respectively, of the Company’ssales.

At June 30, 2007,three customers’ trade accounts receivable from oil, gas and NGL salesaccounted for more than 10% of the Company’s total trade accountsreceivable.  At June 30, 2007, tradeaccounts receivable from these customers represented approximately 24%, 18% and16% of the Company’s receivables.  AtDecember 31, 2006, three customers’ trade accounts receivable from oil andgas sales accounted for more than 10% of the Company’s total trade accountsreceivable.  As of December 31, 2006,trade accounts receivable from these customers represented approximately 41%,22% and 16% of the Company’s receivables.

**(9)****           Commitments and Contingencies**

The Company would beexposed to oil, gas and NGL price fluctuations on underlying sale contracts shouldthe counterparties to the Company’s derivative instruments or thecounterparties to the Company’s oil, gas and NGL marketing contracts notperform.  Such non-performance is notanticipated.  There were no counterpartydefault losses during the three or six months ended June 30, 2007 or 2006.

In June 2007, the Companyentered into an agreement and paid $0.4 million to cancel future leaseobligations totaling $1.1 million related to an office facility inPennsylvania.

16

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From time to time theCompany is a party to various legal proceedings or is subject to industryrulings that could bring rise to claims in the ordinary course ofbusiness.  The Company is not currently aparty to any litigation or pending claims that it believes would have amaterially adverse effect on the Company’s business, financial condition,results of operations or liquidity.

In July 2007, the Companyentered into hedging contracts to reduce oil and gas price risk exposuresrelated to its pending Mid-Continent Acquisition (see Note 2).  The contracts cover 40 Bcf of gas and 800,000Bbls of oil per year for 2008 through 2012 and 7.8 Bcf of gas and 157,000 Bblsof oil for the fourth quarter of 2007. The contracts include deferred premium puts entered into in July 2007,for which the Company will pay the counterparty approximately $132.2 million inOctober 2007.  In addition, the contractsinclude a deal-contingent option to enter into oil and gas swaps uponconsummation of the Mid-Continent Acquisition for which the Company expects topay commitment fees and premiums totaling approximately $71.9 million to thecounterparty.  The Company’s commitmentto enter into the swaps is contingent on the closing of the Mid-ContinentAcquisition.

**(10)****        Derivatives**

The Company sells oil, gas andNGL in the normal course of its business and utilizes derivative instruments tominimize the variability in forecasted cash flows due to price movements inoil, gas and NGL.  The Company entersinto derivative instruments such as swap contracts and put options to hedge aportion of its forecasted oil, gas and NGL sales.  Oil derivatives are used to hedge oil and NGLsales.

Settled derivatives on gasproduction for the three and six months ended June 30, 2007,included a volume of 4,675 MMBtu and 9,369 MMBtu at an average contract priceof $8.43 and $8.43, respectively.  Settled derivatives on oil and NGL production forthe three and six months ended June 30, 2007 included a volume of 500 MBbls and 892 MBbls at anaverage contract price of $68.71 and $69.16,respectively.  The gas derivatives are settled based uponthe closing NYMEX or Henry Hub future price of gas on the settlement date,which occurs on the third day preceding the production month.  The oil transactions are settled based uponthe average month’s daily NYMEX price of light oil and settlement occurs on thefinal day of the production month.

The following tables summarizeopen positions as of June 30, 2007 and represent, as of such date, ourderivatives in place through December 31, 2011, on annual productionvolumes:
|                          | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** |
|--------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas Positions**        |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price Swaps:       |       |           | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume  (MMMBtu)  |       | 3,650          |       | 13,264         |       | 14,605         |       | 12,720         |       | 12,000         |       |
| Average Price  ($/MMBtu) |       | $              | 8.76       |           | $          | 8.52           |       | $              | 8.01       |           | $          | 7.57 |   | $ | 7.48 |   |
| Puts:                    |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)  |       | 4,029          |       | 7,053          |       | 6,960          |       | 6,960          |       | 6,960          |       |
| Average Price  ($/MMBtu) |       | $              | 8.18       |           | $          | 8.07           |       | $              | 7.50       |           | $          | 7.50 |   | $ | 7.50 |   |
| Total:                   |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)  |       | 7,679          |       | 20,317         |       | 21,565         |       | 19,680         |       | 18,960         |       |
| Average Price ($/MMBtu)  |       | $              | 8.45       |           | $          | 8.36           |       | $              | 7.85       |           | $          | 7.55 |   | $ | 7.49 |   |

 

17

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|                        | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** |
|------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Oil  Positions**     |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price  Swaps:    |       |           | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume (MBbls)  |       | 250            |       | 560            |       | 580            |       | 550            |       | 525            |       |
| Average Price ($/Bbl)  |       | $              | 75.83      |           | $          | 74.31          |       | $              | 73.87      |           | $          | 74.54 |   | $ | 61.58 |   |
| Puts:                  |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)  |       | 750            |       | 1,550          |       | 1,550          |       | 1,700          |       | 1,750          |       |
| Average Price ($/Bbl)  |       | $              | 66.33      |           | $          | 66.29          |       | $              | 66.29      |           | $          | 66.18 |   | $ | 65.00 |   |
| Total**:**             |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)  |       | 1,000          |       | 2,110          |       | 2,130          |       | 2,250          |       | 2,275          |       |
| Average Price  ($/Bbl) |       | $              | 68.71      |           | $          | 68.42          |       | $              | 68.35      |           | $          | 68.22 |   | $ | 64.21 |   |

 

The oil and gasderivatives are not designated as cash flow hedges under SFAS 133, and,accordingly, the changes in fair value are recorded in current period earnings.

The following tablepresents the outstanding notional amounts and maximum number of monthsoutstanding of our derivatives:
|                                                      | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
|------------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                           | ** ** | **2007**          | ** ** | **2006**              | ** ** |
| ** **                                           | ** ** | ** **        | ** ** | ** **            | ** ** |
| Outstanding  notional amounts of gas hedges (MMMBtu) |       | 88,201            |       | 31,503                |       |
| Maximum number  of months gas hedges outstanding     |       | 54                |       | 35                    |       |
| Outstanding  notional amounts of oil hedges (MBbls)  |       | 9,765             |       | 8,700                 |       |
| Maximum number of  months oil hedges outstanding     |       | 55                |       | 60                    |       |

 

By using derivativeinstruments to hedge exposures to changes in commodity prices, the Companyexposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under theterms of the derivative contract.  Whenthe fair value of a derivative contract is positive, the counterparty owes theCompany, which creates credit risk.  TheCompany minimizes the credit risk in derivative instruments by entering intotransactions with high-quality counterparties.

In July 2007, the Companyentered into additional hedging contracts to reduce oil and gas price riskexposures related to its pending Mid-Continent Acquisition (see Note 9).

**(11)****        Earnings Per Unit**

Basic earnings per unitis computed by dividing net earnings attributable to unitholders by theweighted average number of units outstanding during each period.  Diluted earnings per unit is computed byadjusting the average number of units outstanding for the dilutive effect, ifany, of unit equivalents.  The Companyuses the treasury stock method to determine the dilutive effect in accordancewith SFAS No. 128, “*Earnings Per Share*.”

18

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The followingreconciliation presents the impact on the unit amounts of potential unitequivalents and the earnings per unit amounts:
|                                          | ** ** | **Three Months Ended  June 30,**                      | ** ** | **Six Months Ended  June 30,** | ** ** |
|------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                               | ** ** | **2007**                                                             | ** ** | **2006**                                      | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                               | ** ** | **(in thousands, except per unit amounts)** | ** ** |
|                                     |       |                                                                 | ** ** | ** **                                    |       |   | ** ** | ** ** | ** ** |
| Net income (loss)                        |       | $                                                                    | (17,126    | )                                             | $          | 10,239 |   | $ | (84,973 | ) | $ | 32,216 |   |
| ** **                               |       |                                                                 |       |                                          |       |   |   |   |   |
| **Weighted average units  outstanding:** |       |                                                                 |       |                                          |       |   |   |   |   |
| Basic units  outstanding                 |       | 59,293                                                               |       | 27,830                                        |       | 52,413 |   | 27,056 |   |
| Dilutive effect  of unit equivalents (1) |       | —                                                               |       | 264                                           |       | — |   | 269 |   |
| Diluted units  outstanding               |       | 59,293                                                               |       | 28,094                                        |       | 52,413 |   | 27,325 |   |
|                                     |       |                                                                 |       |                                          |       |   |   |   |   |
| **Net income (loss) per unit:**          |       |                                                                 |       |                                          |       |   |   |   |   |
| Units – basic                       |       | $                                                                    | (0.29      | )                                             | $          | 0.37 |   | $ | (1.62 | ) | $ | 1.19 |   |
| Units – diluted                     |       | $                                                                    | (0.29      | )                                             | $          | 0.36 |   | $ | (1.62 | ) | $ | 1.18 |   |

 

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(1)             Excludes the effectof average anti-dilutive common stock equivalents related to out-of-the-moneyunit options and warrants, and unvested restricted units of 514,406 and 398,755for the three and six months ended June 30, 2007, respectively.  Excludes the effect of average anti-dilutivecommon stock equivalents related to out-of-the-money unit options and unvestedrestricted units of 8,041 and 21,383 for the three and six months endedJune 30, 2006, respectively.  Allequivalent units are anti-dilutive for the three and six months endedJune 30, 2007 as the Company reported a net loss from operations.

**(12)****                         Unit-Based Compensation**

***Employee Grants***

During the six monthsended June 30, 2007, the Company granted an aggregate 400,500 restrictedunits to employees as part of its annual review of employee compensation and118,500 restricted units to new employees of the Company with an aggregate fairvalue of approximately $17.0 million.  Inaddition, during the six months ended June 30, 2007, the Company granted108,000 unit options to new employees of the Company with a fair value ofapproximately $0.6 million.  The majorityof these restricted units and options vest ratably over three years.

For the three and sixmonths ended June 30, 2007, the Company recorded unit-based compensationexpense of approximately $3.1 million and $6.3 million, respectively, as acharge against income before income taxes and it is included in general andadministrative expenses on the condensed consolidated statements ofoperations.  For the three and six monthsended June 30, 2006, the Company recorded unit-based compensation expenseof approximately $4.2 million and $9.9 million, respectively.

***Non-Employee Grants***

In February 2007, theCompany granted an aggregate 150,000 unit warrants to certain individuals inconnection with a transition services agreement entered into with thePanhandle I acquisition (see Note 2). The unit warrants have an exercise price of $25.50 per unit warrant, maybe exercised in whole or in-part on or after December 13, 2007, and expireten years from issuance.  In accordancewith SFAS 123R, the Company computed the fair value of the unit warrants usingthe Black-Scholes model.  AtJune 30, 2007, the aggregate fair value of the unit warrants wasapproximately $1.4 million and the expense was recognized over the five monthterm of the agreement through June 30, 2007.  For the three and six months endedJune 30,

19

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2007, the Companyrecorded general and administrative expenses of approximately $0.9 million and$1.4 million, respectively, as a charge against income before income taxes.

**(13)****                         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 passed through to the Company’s 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 provisions ofSFAS No. 109 *“Accounting for IncomeTaxes”* (“SFAS 109”), which uses the asset and liabilitymethod.  Deferred tax assets andliabilities are recognized for the future tax consequences attributable todifferences between the financial statement carrying amounts of existing assetsand liabilities and their respective tax basis and operating loss and taxcredit carryforwards.  Deferred taxassets and liabilities are measured using enacted tax rates expected to applyto taxable income in the years in which those temporary differences areexpected to be recovered or settled.  Theeffect on deferred tax assets and liabilities of a change in tax rates isrecognized in income in the period that includes the enactment date.  At June 30, 2007, deferred taxliabilities of approximately $0.8 million are recorded on the condensedconsolidated balance sheets and deferred tax assets of $4.5 million, net of avaluation allowance of $3.7 million are also recorded.  At December 31, 2006, deferred tax liabilitiesof approximately $0.7 million are recorded on the condensed consolidatedbalance sheets and deferred tax assets of $6.3 million, net of a valuationallowance of $2.3 million are also recorded.

TheCompany adopted Financial Interpretation No. 48, *“Accountingfor Uncertainty in Income Taxes — an interpretation of FASB StatementNo. 109”* (“FIN 48”) on January 1, 2007.  FIN 48 requires that the Companyrecognize only the impact of income tax positions that, based on their merits,are more likely than not to be sustained upon audit by a taxing authority.  It also requires expanded financial statementdisclosure of such positions.

Inevaluating its current tax positions in order to identify any materialuncertain tax positions, the Company developed a policy in identifyinguncertain tax positions that considers support for each tax position, industrystandards, tax return disclosures and schedules and the significance of eachposition.  As of June 30, 2007, theCompany had no material uncertain tax positions.

**(14)****                         Related****Party Transactions**

During the three and sixmonths ended June 30, 2006, the Company made payments of approximately$0.2 million to a company owned by one of our senior executives.  The payments reflect reimbursement formaintenance and hourly usage fees for business use of an aircraft that waspartially owned by the senior executive. These costs are included in general and administrative expenses on thecondensed consolidated statements of operations.  The fees and expenses associated with thereimbursements were consummated on terms equivalent to those that prevail inarm’s-length transactions.  In the thirdquarter of 2006, the Company purchased an ownership interest in an airplane forcorporate travel from a third party; therefore, these reimbursements ended.  Simultaneous with this transaction, the seniorexecutive was able to fully liquidate the investment in the aircraft owned byhis company.

20

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

**Executive Summary**

We are anindependent oil and gas company focused on providing stability and growth indistributions to our unitholders through continued successful drilling, acquisitions, increasing production ofexisting wells and pursuing operational and administrativeefficiencies.  Our properties and our oil, gas and NGL reserves are currently locatedin three core areas:

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

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

·                  Mid-Continent, which includes the Sooner Trend ofnorth central Oklahoma and the Texas portion of the Hugoton-Panhandle Field.

***Acquisitions***

The following table provides a summary of our significant oil and gasproperty acquisitions through the date of this report:
| Year       | ** ** | **# of  Acquisitions** | ** ** | **Gross  Wells** | ** ** | **Location**                                        | ** ** | **Aggregate  Contract  Price** | ** ** |
|------------|------------|-----------------------------|------------|------------------|------------|-----------------------------------------------------|------------|--------------------------------|------------|
| ** ** | ** ** | ** **                  | ** ** | ** **       | ** ** | ** **                                          | ** ** | **(in millions)**         | ** ** |
|       |       |                        |       |             |       |                                                |       |                           |       |
| 2003       |       | 4                           |       | 498              |       | West Virginia,  Virginia, New York and Pennsylvania |       | $                              | 52.0       |   |
| 2004       |       | 2                           |       | 698              |       | Pennsylvania                                        |       | 25.9                           |       |
| 2005       |       | 3                           |       | 718              |       | West Virginia and  Virginia                         |       | 124.5                          |       |
| 2006       |       | 5                           |       | 1,430            |       | West Virginia,  California and Oklahoma             |       | 451.7                          |       |
| 2007       |       | 4                           |       | 1,416            |       | West Virginia and Texas                             |       | 544.4                          |       |
| Completed  |       | 18                          |       | 4,760            |       |                                                |       | 1,198.5                        |       |
| Pending*   |       | 2                           |       | 2,624            |       | Texas, Oklahoma and  Kansas                         |       | 2,072.5                        |       |
|       |       | 20                          |       | 7,384            |       |                                                |       | $                              | 3,271.0    |   |

 

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*                    Includes the pending Mid-Continent Acquisition andPanhandle III Acquisition.  TheCompany anticipates that these acquisitions will close during the third quarterof 2007, subject to customary closing conditions.  See Note 2 in Notes to Condensed ConsolidatedFinancial Statements for details about these pending acquisitions andacquisitions completed during the six months ended June 30, 2007.

From inception through June 30, 2007, we have completed 18significant acquisitions of oil and gas properties and related gathering andpipeline assets for an aggregate purchase price of approximately $1.2 billion,with total proved reserves ofapproximately 815.5 Bcfe, or an acquisition cost of approximately $1.47 perMcfe.  Including preliminary estimatesfor the pending Mid-Continent Acquisition and Panhandle III Acquisition, ouracquisitions would include proved reserves of approximately 1,588.8 Bcfe at anaggregate purchase price of approximately $3.3 billion, or an acquisition costof approximately $2.06 per Mcfe.

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

***Hedging Program***

Our revenues are highly sensitive to changes in oil, gas and NGL pricesand levels of production.  We typicallyseek to hedge a significant portion of our anticipated future productionvolumes to reduce commodity price volatility risk.  Managing this volatility, which we believe islikely to continue in the future, provides a longer-term stability

21

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of cashflows.  Currently,we use fixed price swaps and puts to reduce our exposure to the volatility inoil, gas and NGL prices.  As ofthe date of this report, we have hedged a significant portion of our expectedproduction through 2012 using derivatives, which allows us to mitigate, but noteliminate, commodity price risk.  See Item 3. “Quantitative and QualitativeDisclosures About Market Risk” for details about our derivatives in placethrough December 31, 2012.

***Drilling and Operations***

We concentrate our drilling activity on lower risk, developmentproperties.  The number, types, andlocation of wells we drill varies depending on our capital budget, the cost ofeach well, anticipated production and the estimated recoverable reservesattributable to each well.  Historically,until 2007, most of our drilling has been in the Appalachian Basin.  With our February 2007 Panhandle I and June2007 Panhandle II acquisitions, our drilling program has been expanded to theTexas Panhandle and the Sooner Trend of Oklahoma.  Our expected increase in levels of productionas a result of the anticipated drilling of over 250 wells during 2007 isdependent on our ability to quickly and efficiently bring the newly drilledwells online, pipeline capacity and favorable weather conditions.  Any delays in drilling, completion orconnection to gathering lines of our new wells will negatively impact the rateof increase in our production, which may have an adverse effect on our revenuesand as a result, cash available for distribution.

Higher oil, gasand NGL prices have led to higher demand for operating personnel and fieldsupplies and services and have caused increases in the costs of those goods andservices.  In the Appalachian Basin,during 2006, the Company took delivery of its first two drilling rigs, with anadditional rig delivered on March 30, 2007, which has reduced our relianceon contract rigs in that core area.  TheCompany’s drilling subsidiary performs certain services, including preparingand clearing well sites, providing drilling engineers, roustabouts and otherpersonnel, for the Company’s drilling program and for third parties.  We focus our efforts on increasing oil, gasand NGL reserves and production while controlling costs at a level that isappropriate for long-term operations. Our future cash flow from operations is dependent on our ability tomanage our overall cost structure.

We face thechallenge of natural production declines. As initial reservoir pressures are depleted, oil, gas or NGL productionfrom a given well decreases.  We attemptto overcome this natural decline by drilling to find additional reserves andacquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reservesin excess of production.  We willmaintain our focus on adding reserves through drilling and acquisitions as wellas managing the costs necessary to produce such reserves.  Our ability to add reserves through drillingis dependent on our capital resources and can be limited by many factors,including our ability to timely obtain drilling permits and regulatoryapprovals.

Our revenue, cashflow from operations and future growth depend substantially on factors beyondour control, such as economic, political and regulatory developments andcompetition from other producers.  Oil,gas and NGL prices historically have been volatile and may fluctuate widely inthe future.  Sustained periods of lowprices for oil, gas or NGL could materially and adversely affect our financialposition, our results of operations, the quantities of productive reserves thatwe can economically produce and our access to capital.  See “Cautionary Statement” below in thisItem 2. for additional information about risks related to our Company.

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**Results of Operations - Three MonthsEnded June 30, 2007 Compared to Three Months Ended June 30, 2006**
| ** **                                   | ** ** | **Three Months Ended  June 30,** | ** ** | ** ** | ** ** |
|----------------------------------------------|------------|-------------------------------------------------|------------|------------|------------|
| ** **                                   | ** ** | **2007**                                        | ** ** | **2006**   | ** ** | **Variance** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                         | ** ** |
| **Revenues:**                                |       |                                            |       |       |       |   |   |
| Gas sales                                    |       | $                                               | 25,462     |       | $          | 13,126 |   | $ | 12,336 |   |
| Oil sales                                    |       | 13,316                                          |       | 403        |       | 12,913 |   |
| Natural gas  liquid sales                    |       | 10,439                                          |       | —     |       | 10,439 |   |
| Total oil, gas  and natural gas liquid sales |       | 49,217                                          |       | 13,529     |       | 35,688 |   |
| Gain (loss) on  oil and gas derivatives      |       | (17,707                                         | )          | 12,895     |       | (30,602 | ) |
| Natural gas  marketing revenues              |       | 1,139                                           |       | 1,346      |       | (207 | ) |
| Other revenues                               |       | 1,139                                           |       | 204        |       | 935 |   |
| Total revenues                               |       | $                                               | 33,788     |       | $          | 27,974 |   | $ | 5,814 |   |
| **Expenses:**                                | ** ** | ** **                                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  expenses                          |       | $                                               | 14,714     |       | $          | 2,933 |   | $ | 11,781 |   |
| Natural gas  marketing expenses              |       | 879                                             |       | 1,189      |       | (310 | ) |
| General and  administrative expenses         |       | 12,537                                          |       | 6,928      |       | 5,609 |   |
| Depreciation,  depletion and amortization    |       | 12,938                                          |       | 4,116      |       | 8,822 |   |
| Total expenses                               |       | $                                               | 41,068     |       | $          | 15,166 |   | $ | 25,902 |   |
|                                         |       |                                            |       |       |       |   |   |
| **Other income and (expenses)**              |       | $                                               | (9,816     | )          | $          | (2,762 | ) | $ | (7,054 | ) |

 
| ** **                                                 | ** ** | **Three Months Ended  June 30,** | ** ** | **Percentage  Increase** | ** ** |
|------------------------------------------------------------|------------|-------------------------------------------------|------------|--------------------------|------------|
| ** **                                                 | ** ** | **2007**                                        | ** ** | **2006**                 | ** ** | **(Decrease)** | ** ** |
| **Production:**                                            | ** ** | ** **                                      | ** ** | ** **               | ** ** | ** ** | ** ** |
| Gas production  (MMcf)                                     |       | 3,518                                           |       | 1,914                    |       | 83.8 | % |
| Oil production  (MBbls)                                    |       | 251                                             |       | 7                        |       | * |   |
| Natural gas  liquid production (MBbls)                     |       | 203                                             |       | —                   |       | — |   |
| Total production  (MMcfe)                                  |       | 6,245                                           |       | 1,956                    |       | 219.3 | % |
| Average daily  production (MMcfe/d)                        |       | 68.6                                            |       | 21.5                     |       | 219.1 | % |
| ** **                                                 | ** ** | ** **                                      | ** ** | ** **               | ** ** | ** ** | ** ** |
| **Weighted average realized  prices: (1)**                 | ** ** | ** **                                      | ** ** | ** **               | ** ** | ** ** | ** ** |
| Gas (Mcf)                                                  |       | $                                               | 8.68       |                     | $          | 9.91 |   | (12.4 | )% |
| Oil (Bbl) (2)                                              |       | $                                               | 60.50      |                     | $          | 58.03 |   | 4.3 | % |
| Natural gas  liquid (Bbl)                                  |       | $                                               | 52.63      |                     | $          | — |   | — |   |
| Total (Mcfe)                                               |       | $                                               | 9.03       |                     | $          | 9.90 |   | (8.8 | )% |
| ** **                                                 | ** ** | ** **                                      | ** ** | ** **               | ** ** | ** ** | ** ** |
| **Average unit costs per Mcfe of  production (non-GAAP):** | ** ** | ** **                                      | ** ** | ** **               | ** ** | ** ** | ** ** |
| Operating  expenses                                        |       | $                                               | 2.36       |                     | $          | 1.50 |   | 57.3 | % |
| General and  administrative expenses (3)                   |       | $                                               | 1.37       |                     | $          | 1.40 |   | (2.1 | )% |
| Depreciation, depletion  and amortization                  |       | $                                               | 2.07       |                     | $          | 2.10 |   | (1.4 | )% |

----

(1)      Includes the effect of realized gains of $7.2 million and $5.8 millionon derivatives for the three months ended June 30, 2007 and 2006,respectively.

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

(3)      This is a non-GAAPperformance measure used by our management and is a quantitative measure usedin the oil and gas industry.  The measurefor the three months ended June 30, 2007 and 2006 excludes approximately$4.0 million and $4.2 million, respectively, of unit-based compensation expenseand unit warrant expense.  General andadministrative expenses including these amounts were $2.01 per Mcfe and $3.54per Mcfe for the three months ended June 30, 2007 and 2006, respectively.

*           Not meaningful.

23

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***Revenue***

Gas, oil and NGL sales increased 264%, to approximately $49.2million for the three months ended June 30, 2007, from $13.5 million forthe three months ended June 30, 2006.

The increase in revenue from gas, oil and NGL sales was primarilyattributable to increased production. Total production increased to 6,245 MMcfe during the three months endedJune 30, 2007, from 1,956 MMcfe during the three months endedJune 30, 2006.  Gas productionincreased to 3,518 MMcf during the three months ended June 30, 2007, from1,914 MMcf during the three months ended June 30, 2006.  The increase in gas production was due to thedrilling of new wells and production added by the acquisitions of oil and gasproperties during 2007 and 2006.  TheCompany drilled 72 wells during the three months ended June 30, 2007,compared to 55 wells during the three months ended June 30, 2006.  Oil production increased to 251 MBbls duringthe three months ended June 30, 2007, from 7 MBbls during the during thethree months ended June 30, 2006, due to the California, Panhandle I and Panhandle II acquisitions in August2006, February 2007 and June 2007, respectively.  The acquisitions in the Texas Panhandle alsoincreased NGL production to 203 MBbls during the three months endedJune 30, 2007, from zero during the comparative period of the prior year.

***Hedging Activities***

During the three months endedJune 30, 2007, we entered into commodity pricing derivative contracts forapproximately 133% of our gas production and 110% of our oil and NGLproduction, which resulted in realized gains of $7.2 million (revenues greaterthan we would have achieved at unhedged prices).  The calculation of the percentage hedged forthe three months ended June 30, 2007 includes an adjustment to reflect Panhandle I production, which was hedged, but was notincluded in the Company’s reported production. It was instead recorded as a purchase price adjustment (see Note 2in Notes to Condensed Consolidated Financial Statements).  During the three months ended June 30,2006, we entered into commodity pricing derivative contracts for approximately95% of our gas production, which resulted in realized gains of $5.8million.  Unrealized losses onderivatives in the amount of $24.9 million for the three months endedJune 30, 2007, and unrealized gains of $7.1 million for the three monthsended June 30, 2006, were also recorded. Unrealized gains and losses result from changes in market valuations ofderivatives as future commodity price expectations change compared to thecontract price on the derivative.  Duringthe quarter, short-term oil and gas prices increased, which reduced the marketvalue of the derivatives.  Such marketvalue adjustment, if realized in the future, would be offset by higher actualprices for our production.

***Expenses***

Operating expenses include leaseoperating expenses, labor, field office expenses, vehicle expenses,supervision, transportation, minor maintenance, tools and supplies andseverance and ad valorem taxes. Severance taxes are a function of volumes and revenues generated fromproduction.  Ad valorem taxes vary bystate/county and are based on the value of our reserves.  We assess our operating expenses bymonitoring the expenses in relation to the amount of production and the numberof wells operated.  Operating expensesincreased to $14.7 million for the three months ended June 30, 2007, from$2.9 million for the three months ended June 30, 2006, due to the increasein the number of producing wells as a result of the acquisitions completed in2007 and in 2006 and the drilling of 72 wells in the three months endedJune 30, 2007, and 472 wells from inception through June 30, 2007.

In addition, our averageoperating expenses per equivalent unit of production increased to $2.36 for thethree months ended June 30, 2007, compared to $1.50 for the three monthsended June 30, 2006, due to increased material and labor costs and thechanging mix of production beginning in the third quarter of 2006 to includeoil and NGL, which have higher operating costs than our gas wells.  Finally, we have incurred costs in 2007 forworkover and maintenance of our wells to enhance future production and/oroffset decline.

Generaland administrative expenses include the costs of our employees and executiveofficers, related benefits, office leases, professional fees and other costsnot directly associated with field operations. General and administrative expenses increased to approximately $12.5 millionfor the three months ended June 30, 2007, from $6.9 million for the threemonths ended June 30, 2006.  Theincrease in general and administrative expenses was primarily due to costsincurred to support our rapid growth through acquisitions and position theCompany for future growth.  Inconjunction with expansion and development of our operations team, to dateduring 2007, we have hired

24

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approximately 40employees and as a result, salaries and benefits expense increasedapproximately $1.7 million over the comparable quarter of 2006.  We also incurred approximately $1.3 millionin expenses for services performed by third-parties pursuant to a transitionservices agreement associated with the Panhandle I properties (seeNote 2 in Notes to Condensed Consolidated Financial Statements).  This services agreement terminated effectiveJune 30, 2007.  Costs to perform thenecessary functions associated with being a large, growing, public company were$2.1 million during the second quarter of 2007, compared to $1.2 million duringthe second quarter of 2006.  These costsinclude expenses for recruitment of key management team members, acquisitionrelated data conversion and integration, public partnership tax reporting,audit fees, legal fees, proxy and printing costs and other professional fees,including costs related to our compliance with Section 404 of theSarbanes-Oxley Act of 2002 (“Sarbanes-Oxley Act”).  The Company is currently in the process ofimplementing and testing procedures and controls in order to comply with theSarbanes-Oxley Act at December 31, 2007, and as such, expects these costs tocontinue throughout the remainder of the year. In addition, acquisition costs that are not eligible for capitalization,including internal and indirect costs for completed acquisitions, as well asdirect costs associated with acquisition efforts that have not reachedfruition, contributed to the increase. The increase in general and administrative expenses was partially offsetby lower employee unit-based compensation expense, which decreased to $2.3 million (exclusive of amountsassociated with the 40 new employees) during the three months endedJune 30, 2007, from $4.2 millionduring the comparative quarter of 2006. Unit-based compensation expense incurred during the three months endedJune 30, 2006 is higher compared to that incurred in the comparative period of2007, primarily due to expense associated with unit awards granted inconjunction with the Company’s IPO in January 2006.  General and administrative expenses arepresented net of approximately $0.1 millionand $0.4 million during the three monthsended June 30, 2007 and 2006, respectively, which represent expensereimbursements from other working interest owners.

Depreciation, depletion and amortization increased to approximately $12.9 million for the three monthsended June 30, 2007, from $4.1 million for the three months endedJune 30, 2006.  Of thisincrease, approximately $5.8 millionwas as a result of depletion related to the California and Oklahomaacquisitions in the third quarter of 2006 and the Texas acquisitions in thefirst and second quarters of 2007. Although total depreciation, depletion and amortization increased in thesecond quarter of 2007 due to higher total production levels, the reserves inour recently acquired Texas, Oklahoma and California properties have lowerdepletion rates than our reserves in the Appalachian Basin.  During the threemonths ended June 30, 2007 and 2006, the Company capitalizedapproximately $2.8 million and $0.6 million, respectively, of costs forspecific activities related to drilling its wells, which included sitepreparation, drilling labor, meter installation, pipeline connection and sitereclamation.  Capitalized drilling costsincreased in the three months ended June 30, 2007 due to the Company’spurchase and placement of two drilling rigs into service during the thirdquarter of 2006 and one additional drilling rig in the first quarter of 2007.  Company personnel also perform activitiesusing leased equipment, and did so prior to the purchase of its own rigs.

Other income and (expenses) increased to a net expenseof $9.8 million for the three months ended June 30, 2007,compared to a net expense of $2.8 millionfor the three months ended June 30,2006, primarily due to increased interest expense from increased debtlevels associated with acquisitions and drilling.  Cash payments for interest increased to $10.3 million for the three months ended June 30, 2007,compared to $1.6 million for the three months ended June 30, 2006.  Our interest rate swaps were not designatedas hedges under SFAS 133, even though they reduce our exposure to changesin interest rates.  Therefore, thechanges in fair values of these instruments were recorded as gains ofapproximately $0.3 million and $0.3million for the three months endedJune 30, 2007 and 2006, respectively.  These amounts are non-cash gains.

Income tax was an expense of approximately $30,000 for the three months ended June 30, 2007, compared to a benefit ofapproximately $0.2 million for the three months ended June 30, 2006.  TheCompany’s taxable subsidiaries generated net operating losses for the yearended December 31, 2006.  Managementhas subsequently recovered expenses through an intercompany charge for servicesfrom Linn Operating, Inc. to Linn Energy, LLC, which resulted in acorresponding tax expense in the three months ended June 30, 2007.

25

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**Results of Operations - Six Months EndedJune 30, 2007 Compared to Six Months Ended June 30, 2006**
| ** **                                  | ** ** | **Six Months Ended** | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|--------------------------------|------------|------------|------------|
| ** **                                  | ** ** | **June 30,**              | ** ** | ** ** | ** ** |
| ** **                                  | ** ** | **2007**                       | ** ** | **2006**   | ** ** | **Variance** | ** ** |
| ** **                                  | ** ** | **(in thousands)**        | ** ** |
| **Revenues:**                               | ** ** | ** **                     | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas sales                                   |       | $                              | 48,822     |       | $          | 29,133 |   | $ | 19,689 |   |
| Oil sales                                   |       | 23,074                         |       | 771        |       | 22,303 |   |
| Natural gas liquid sales                    |       | 16,525                         |       | —     |       | 16,525 |   |
| Total oil, gas and natural gas liquid sales |       | 88,421                         |       | 29,904     |       | 58,517 |   |
| Gain (loss) on oil and gas derivatives      |       | (78,148                        | )          | 37,141     |       | (115,289 | ) |
| Natural gas marketing revenues              |       | 2,917                          |       | 2,564      |       | 353 |   |
| Other revenues                              |       | 3,229                          |       | 493        |       | 2,736 |   |
| Total revenues                              |       | $                              | 16,419     |       | $          | 70,102 |   | $ | (53,683 | ) |
| **Expenses:**                               | ** ** | ** **                     | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating expenses                          |       | $                              | 27,170     |       | $          | 5,927 |   | $ | 21,243 |   |
| Natural gas marketing expenses              |       | 2,226                          |       | 2,172      |       | 54 |   |
| General and administrative expenses         |       | 23,158                         |       | 16,398     |       | 6,760 |   |
| Depreciation, depletion and amortization    |       | 24,789                         |       | 7,816      |       | 16,973 |   |
| Total expenses                              |       | $                              | 77,343     |       | $          | 32,313 |   | $ | 45,030 |   |
| **Other  income and (expenses)**            |       | $                              | (20,387    | )          | $          | (5,647 | ) | $ | (14,740 | ) |

 
| ** **                                                 | ** ** | **Six Months Ended  June 30,** | ** ** | **Percentage  Increase** | ** ** |
|------------------------------------------------------------|------------|-----------------------------------------------|------------|--------------------------|------------|
| ** **                                                 | ** ** | **2007**                                      | ** ** | **2006**                 | ** ** | **(Decrease)** | ** ** |
| **Production:**                                            | ** ** | ** **                                    | ** ** | ** **               | ** ** | ** ** | ** ** |
| Gas production (MMcf)                                      |       | 6,892                                         |       | 3,712                    |       | 85.7 | % |
| Oil production (MBbls)                                     |       | 466                                           |       | 13                       |       | * |   |
| Natural gas liquid production (MBbls)                      |       | 330                                           |       | —                   |       | — |   |
| Total production (MMcfe)                                   |       | 11,669                                        |       | 3,792                    |       | 207.7 | % |
| Average daily production (MMcfe/d)                         |       | 64.5                                          |       | 21.0                     |       | 207.1 | % |
| ** **                                                 | ** ** | ** **                                    | ** ** | ** **               | ** ** | ** ** | ** ** |
| **Weighted  average realized prices:**(1)                  | ** ** | ** **                                    | ** ** | ** **               | ** ** | ** ** | ** ** |
| Gas (Mcf)                                                  |       | $                                             | 8.54       |                     | $          | 10.32 |   | (17.2 | )% |
| Oil (Bbl) (2)                                              |       | $                                             | 60.21      |                     | $          | 58.23 |   | 3.4 | % |
| Natural gas liquid (Bbl)                                   |       | $                                             | 53.81      |                     | $          | — |   | — |   |
| Total (Mcfe)                                               |       | $                                             | 8.97       |                     | $          | 10.30 |   | (12.9 | )% |
| ** **                                                 | ** ** | ** **                                    | ** ** | ** **               | ** ** | ** ** | ** ** |
| **Average  unit costs per Mcfe of production (non-GAAP):** | ** ** | ** **                                    | ** ** | ** **               | ** ** | ** ** | ** ** |
| Operating expenses                                         |       | $                                             | 2.33       |                     | $          | 1.56 |   | 49.4 | % |
| General and administrative expenses (3)                    |       | $                                             | 1.33       |                     | $          | 1.18 |   | 12.7 | % |
| Depreciation,  depletion and amortization                  |       | $                                             | 2.12       |                     | $          | 2.06 |   | 2.9 | % |

----

(1)    Includes the effect of realized gains of $16.3 million and $9.2 millionon derivatives for the six months ended June 30, 2007 and 2006,respectively.

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

(3)    This is a non-GAAPperformance measure used by our management and is a quantitative measure usedin the oil and gas industry.  The measurefor the six months ended June 30, 2007 and 2006 excludes approximately $7.7million and $9.9 million, respectively, of unit-based compensation expense andunit warrant expense.  The measure forthe six months ended June 30, 2006 excludes approximately $2.0 million ofbonuses paid to certain executive officers in connection with our IPO.  General and administrative expenses includingthese amounts were $1.98 per Mcfe and $4.32 per Mcfe for the six months endedJune 30, 2007 and 2006, respectively.

*           Not meaningful.

26

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***Revenue***

Gas, oil and NGL sales increased 196%, to approximately $88.4million for the six months ended June 30, 2007, from $29.9 million for thesix months ended June 30, 2006.

The increase in revenue from gas, oil and NGL sales was primarilyattributable to increased production. Total production increased to 11,669 MMcfe during the six months endedJune 30, 2007, from 3,792 MMcfe during the six months ended June 30,2006.  Gas production increased to 6,892MMcf during the six months ended June 30, 2007, from 3,712 MMcf during thesix months ended June 30, 2006.  Theincrease in gas production was due to the drilling of new wells and productionadded by the acquisitions of oil and gas properties during 2007 and 2006.  The Company drilled 113 wells during the sixmonths ended June 30, 2007, compared to 84 wells during the six months endedJune 30, 2006.  Oil productionincreased to 466 MBbls during the six months ended June 30, 2007, from 13MBbls during the during the six months ended June 30, 2006, due to theCalifornia, Panhandle I andPanhandle II acquisitions in August 2006, February 2007 and June 2007,respectively.  The acquisitions in theTexas Panhandle also increased NGL production to 330 MBbls during the sixmonths ended June 30, 2007, from zero during the comparative period of theprior year.

***Hedging Activities***

During the six months endedJune 30, 2007, we entered into commodity pricing derivative contracts forapproximately 124% of our gas production and 110% of our oil and NGLproduction, which resulted in realized gains of $16.3 million (revenues greaterthan we would have achieved at unhedged prices).  The calculation of the percentage hedged forthe six months ended June 30, 2007 includes an adjustment to reflect Panhandle I production, which was hedged, but was notincluded in the Company’s reported production. It was instead recorded as a purchase price adjustment (see Note 2in Notes to Condensed Consolidated Financial Statements).  During the six months ended June 30,2006, we entered into commodity pricing derivative contracts for approximately97% of our gas production, which resulted in realized gains of $9.2million.  Unrealized losses onderivatives in the amount of $94.4 million for the six months endedJune 30, 2007, and unrealized gains of $28.0 million for the six monthsended June 30, 2006, were also recorded. Unrealized gains and losses result from changes in market valuations ofderivatives as future commodity price expectations change compared to thecontract price on the derivative.  Duringthe six months ended June 30, 2007, short-term oil and gas prices increased,which reduced the market value of the derivatives.  Such market value adjustment, if realized inthe future, would be offset by higher actual prices for our production.

***Expenses***

Operating expenses include leaseoperating expenses, labor, field office expenses, vehicle expenses,supervision, transportation, minor maintenance, tools and supplies andseverance and ad valorem taxes. Severance taxes are a function of volumes and revenues generated fromproduction.  Ad valorem taxes vary bystate/county and are based on the value of our reserves.  We assess our operating expenses bymonitoring the expenses in relation to the amount of production and the numberof wells operated.  Operating expensesincreased to $27.2 million for the six months ended June 30, 2007, from$5.9 million for the six months ended June 30, 2006, due to the increasein the number of producing wells as a result of the acquisitions completed in2007 and in 2006 and the drilling of 113 wells in the six months ended June 30,2007, and 472 wells from inception through June 30, 2007.

In addition, our averageoperating expenses per equivalent unit of production increased to $2.33 for thesix months ended June 30, 2007, compared to $1.56 for the six months endedJune 30, 2006, due to increased material and labor costs and the changingmix of production beginning in the third quarter of 2006 to include oil andNGL, which have higher operating costs than our gas wells.  Finally, we have incurred costs in 2007 forworkover and maintenance of our wells to enhance future production and/oroffset decline.

General and administrativeexpenses include the costs of our employees and executive officers, relatedbenefits, office leases, professional fees and other costs not directlyassociated with field operations. General and administrative expenses increased to approximately $23.2million for the six months ended June 30, 2007, from $16.4 million for thesix months ended June 30, 2006.  Theincrease in general and administrative expenses was primarily due to costs

27

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incurred to support ourrapid growth through acquisitions and position the Company for futuregrowth.  In conjunction with expansionand development of our operations team, to date during 2007, we have hiredapproximately 40 employees and as a result, salaries and benefits expenseincreased approximately $2.9 million as compared to the six months ended June30, 2006.  We also incurred approximately$1.8 million in expenses for services performed by third-parties pursuant to atransition services agreement associated with the Panhandle I properties(see Note 2 in Notes to Condensed Consolidated Financial Statements).  This services agreement terminated effectiveJune 30, 2007.  Costs to perform thenecessary functions associated with being a large, growing, public company were$6.1 million during the six months ended June 30, 2007, compared to $2.1million during the six months ended June 30, 2006.  These costs include expenses for relocationof the Company headquarters from Pittsburgh, Pennsylvania to Houston, Texas,recruitment of key management team members, acquisition related data conversionand integration, public partnership tax reporting, audit fees, legal fees,proxy and printing costs and other professional fees, including costs relatedto our compliance with the Sarbanes-Oxley Act. The Company is currently in the process of implementing and testingprocedures and controls in order to comply with the Sarbanes-Oxley Act atDecember 31, 2007, and as such, expects these costs to continue throughout theremainder of the year.  In addition,acquisition costs that are not eligible for capitalization, including internaland indirect costs for completed acquisitions, as well as direct costsassociated with acquisition efforts that have not reached fruition, contributedto the increase.  The increase in generaland administrative expenses was partially offset by lower employee unit-basedcompensation expense, which decreased to $5.0million (exclusive of amounts associated with the 40 new employees)during the six months ended June 30, 2007, from $9.9 million during the comparative period of 2006.  Unit-based compensation expense incurredduring the six months ended June 30, 2006 is higher compared to that incurredin the comparative period of 2007, primarily due to expense associated withunit awards granted in conjunction with the Company’s IPO in January 2006.  In addition, IPO bonuses of $2.0 million werepaid to certain executive officers during the six months ended June 30,2006.  General and administrativeexpenses are presented net of approximately $0.2million and $0.6 million during the sixmonths ended June 30, 2007 and 2006, respectively, which representexpense reimbursements from other working interest owners.

Depreciation, depletion and amortization increased to approximately $24.8 million for the six monthsended June 30, 2007, from $7.8 million for the six months endedJune 30, 2006.  Of thisincrease, approximately $10.6 millionwas as a result of depletion related to the California and Oklahomaacquisitions in the third quarter of 2006 and the Texas acquisitions in thefirst and second quarters of 2007. Although total depreciation, depletion and amortization increased in thesix months ended June 30, 2007 due to higher total production levels, thereserves in our recently acquired Texas, Oklahoma and California propertieshave lower depletion rates than our reserves in the Appalachian Basin.  During the six months ended June 30, 2007 and 2006, the Companycapitalized approximately $4.7 millionand $1.1 million, respectively, ofcosts for specific activities related to drilling its wells, which includedsite preparation, drilling labor, meter installation, pipeline connection andsite reclamation.  Capitalized drillingcosts increased in the six months ended June 30, 2007 due to the Company’spurchase and placement of two drilling rigs into service during the thirdquarter of 2006 and one additional drilling rig in the first quarter of2007.  Company personnel also performactivities using leased equipment, and did so prior to the purchase of its ownrigs.

Other income and (expenses) increased to a net expenseof $20.4 million for the six months ended June 30, 2007, comparedto a net expense of $5.6 million forthe six months ended June 30, 2006,primarily due to increase interest expense from increased debt levelsassociated with acquisitions and drilling. Cash payments for interest increased to $19.7 million for the sixmonths ended June 30, 2007, compared to $5.0 million for the sixmonths ended June 30, 2006. Our interest rate swaps were not designated as hedges under SFAS 133,even though they reduce our exposure to changes in interest rates.  Therefore, the changes in fair values ofthese instruments were recorded as gains of approximately $0.1 million and $0.7 million for the six months ended June 30, 2007 and 2006,respectively.  These amounts are non-cashgains.

Income tax was an expense of approximately $3.7 million for the six months ended June 30, 2007, compared to abenefit of $74,000 for the six monthsended June 30, 2006.  The Company’s taxable subsidiaries generated netoperating losses for the year ended December 31, 2006.  Management has subsequently recoveredexpenses through an intercompany charge for services from Linn Operating, Inc.to Linn Energy, LLC, which resulted in a corresponding tax expense in the sixmonths ended June 30, 2007.

28

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**CriticalAccounting Policies and Estimates**

The preparation of financial statements in accordancewith GAAP requires management to select and apply accounting policies that bestprovide the framework to report its results of operations and financialposition.  The selection and applicationof those policies requires management to make difficult subjective or complexjudgments concerning reported amounts of revenue and expenses during thereporting period and the reported amounts of assets and liabilities at the dateof the financial statements.  As aresult, there exists the likelihood that materially different amounts would bereported under different conditions or using different assumptions.

As of June 30, 2007, there have been nosignificant changes with regard to the critical accounting policies disclosedin the Company’s Annual Report on Form 10-K for the year endedDecember 31, 2006.  The policiesdisclosed included the accounting for oil and gas properties, reservequantities, revenue recognition, purchase accounting and derivativeinstruments.

**Liquidity andCapital Resources**

We have utilized public andprivate equity, proceeds from bank borrowings and cash flow from operations forour capital resources and liquidity.  Todate, our primary use of capital has been for the acquisition and developmentof oil and gas properties.  As we pursuegrowth, we continually monitor the capital resources available to us to meetour future financial obligations and planned capital expenditures.  Our future success in growing reserves andproduction will be highly dependent on the capital resources available to usand our success in drilling for or acquiring additional reserves.  We actively review acquisition opportunitieson an ongoing basis.  If we were to makesignificant additional acquisitions for cash, we would need to borrowadditional amounts under our Credit Facility, if available, or obtainadditional debt or equity financing.  OurCredit Facility imposes certain restrictions on our ability to obtainadditional debt financing.  Based uponour current expectations, we believe our liquidity and capital resources willbe sufficient for the conduct of our business and operations.

***Statements of Cash Flows – Operating Activities***

At June 30, 2007, we hadcash and cash equivalents of approximately $1.0 million compared to $6.6million at December 31, 2006.

Cash used by operating activitiesfor the six months ended June 30, 2007 was $19.4 million, compared to cashprovided by operating activities of $14.1 million for the six months endedJune 30, 2006.  The decrease in cashprovided by operating activities was primarily due to premiums paid for derivativesof approximately $53.0 million.  Thesepremiums relate to oil and gas derivatives on our projected production throughDecember 31, 2011.

Our cash flow from operations issubject to many variables, the most significant of which is the volatility ofoil, gas and NGL prices.  Oil, gas andNGL prices are determined primarily by prevailing market conditions, which aredependent on regional and worldwide economic activity, weather and otherfactors beyond our control.  Our futurecash flow from operations will depend on our ability to maintain and increaseproduction through our drilling program and acquisitions, as well as the pricesreceived for our production.  We enterinto derivative arrangements to reduce the impact of commodity price volatilityon our operations.  Currently, we usefixed price swaps and puts to reduce our exposure to the volatility in oil, gasand NGL prices.  See Note 10 inNotes to Condensed Consolidated Financial Statements for details about ourderivatives in place through December 31, 2011.  See Item 3. “Quantitative andQualitative Disclosures About Market Risk,” for details about our derivativesin place through December 31, 2012.

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

Cash used in investing activitieswas $587.3 million for the six months ended June 30, 2007, compared to$65.8 million for the six months ended June 30, 2006.  The increase in cash used in investingactivities was primarily due to an increase in acquisition activity during thesix months ended June 30, 2007, compared to the same period of the prioryear.

29

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Thetotal cash used in investing activities for the six months ended June 30,2007 includes $484.5 million for the Panhandle I andPanhandle II acquisitions and $38.6 million for the acquisitions of certaingas properties in West Virginia.  See Note 2 in Notes to CondensedConsolidated Financial Statements for additional details.  Other acquisitions, including acquisitions ofadditional working interests in our current wells, were approximately $16.2 millionand property, plant and equipment purchases accounted for $7.5 million.  The total for the six months endedJune 30, 2007 also includes $43.5 million for the drilling and developmentof oil and gas properties.

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

Cash provided by financingactivities was $601.1 million for the six months ended June 30, 2007,compared to $44.3 million for the six months ended June 30, 2006.

The Company recorded gross proceeds of $620.0 millionfrom two private placements of its units during the six months endedJune 30, 2007 (see below).  Theproceeds, net of expenses of approximately $6.9million paid through June 30, 2007, were used to finance the Panhandle I acquisition and theacquisitions of certain gas properties in West Virginia and to repayindebtedness under the Company’s Credit Facility.  During the sixmonths ended June 30, 2007, total proceeds from borrowings underthe Credit Facility were $308.0 million and total payments on the CreditFacility were $257.8 million.

InJanuary 2007, the Company’s Board of Directors declared a distribution of $0.52per unit with respect to the fourth quarter of 2006.  The distribution totaled approximately $22.7million and was paid in February 2007.

In April 2007, the Company’s Board of Directorsdeclared a distribution of $0.52 per unit with respect to the first quarter of2007.  The distribution totaledapproximately $30.0 million and was paid in May 2007.

In July 2007, the Company’s Board of Directorsdeclared a distribution of $0.57 per unit with respect to the second quarter of2007, representing a 10% increase over the Company’s distribution for the firstquarter of 2007.  The distribution willbe paid in August 2007 to unitholders of record at the close of business onAugust 2, 2007.  As previouslyannounced, management currently intends to recommend to the Board of Directorsa further increase in the quarterly cash distribution to $0.63 per unit, or$2.52 per unit on an annualized basis, beginning in the fourth fiscal quarterof 2007, contingent on the Company’s pending Mid-Continent Acquisition.

***Pending PrivatePlacement***

OnJune 29, 2007, the Company executed a unit purchase agreement for aprivate placement of $1.5 billion of units to a group of institutionalinvestors, consisting of 34,997,005 Class D units at a price of $30.97 perunit and 12,999,989 units at a price of $32.00 per unit.  Proceeds, net of expenses, will be used tofund the Mid-Continent Acquisition (see Note 2 in Notes to CondensedConsolidated Financial Statements).  ThePending Private Placement is expected to coincide with the closing of theMid-Continent Acquisition and is subject to customary closing conditions,including the closing of the Mid-Continent Acquisition.  There can be no assurance that all of theconditions to closing will be satisfied.

TheClass D units will represent a class of equity securities that is entitledto a special quarterly distribution equal to 115% of the distribution receivedby the holders of units, has no voting rights other than as required by law andis subordinated to the units on dissolution and liquidation.  The Class D units may convert into unitsif the conversion is approved by a vote of the Company’s unitholders.  The Company has agreed to hold a meeting ofits unitholders to consider this proposal as soon as reasonably practicable,but no later than 120 days from the closing date.  In connection with the Pending PrivatePlacement, the Company also agreed to file a registration statement with theSEC covering the units and the Class D units, and that the registrationstatement would be declared effective by the SEC no later thanNovember 13, 2007.

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***June 2007 Private Placement***

In June2007, the Company closed its private placement of $260.0 million of units to agroup of institutional investors, consisting of 7,761,194 units at a price of$33.50 per unit.  Net proceeds were usedto repay indebtedness under the Company’s Credit Facility.  In connection with the June 2007 PrivatePlacement, the Company also agreed to file a registration statement with theSEC covering the units, and that the registration statement would be declared effectiveby the SEC no later than 165 days following the closing.

***February 2007 Private Placement***

In February 2007, theCompany entered into a Class C Unit and Unit Purchase Agreement with a group of institutional investorswhereby it privately placed 7,465,946 Class C units at a price of $25.06per unit, and 6,650,144 units at a price of $26.00 per unit, for aggregategross proceeds of $360.0 million.  Theproceeds from the February 2007 Private Placement were used to finance thePanhandle I acquisition and the acquisitions of certain gas properties inWest Virginia.  See Note 2 in Notes to Condensed Consolidated Financial Statements.

In April 2007, at aspecial meeting of Linn unitholders, unitholders approved the one-for-oneconversion of the Class C units into units.  In connection with the February 2007 PrivatePlacement, the Company agreed to file a registration statement with the SECcovering the units and the units underlying the Class C units, and thatthe registration statement would be declared effective by the SEC no later than165 days following the closing.  In June2007, this deadline was extended to December 31, 2007.

***October 2006 Private Placement***

In connection with itsOctober 2006 private placement of Class B units, the Company also agreed tofile a registration statement with the SEC covering the units and the unitsunderlying the Class B units, and that the registration statement would bedeclared effective by the SEC no later than 165 days following theclosing.  In June 2007, this deadline wasextended to December 31, 2007.

***Liquidated Damages***

The Company could berequired to pay purchasers liquidated damages specified in the agreementspursuant to the October 2006, February 2007 and June 2007 Private Placementsand the Pending Private Placement.  Thepotential payments under the agreements are 0.25% of the gross proceeds foreach 30 day period that the registration deadlines are not met, up through 90days.  Subsequent to 90 days, thepotential payments would increase for each 30 day period, up to a maximum of 1.0%of the gross proceeds of each offering. The Company does not believe it is probable that it will be required tomake such payments; therefore, has not recorded a liability at this time.  The Company will continue to monitor andassess its exposure in this matter; however, the Company does not currentlyexpect payments, if any, under these agreements to be material to the Company’sfinancial position or results of operations.

***Initial Public Offering***

In the first quarter of2006, the company completed its initial public offering of 12,450,000 unitsrepresenting limited liability company interests in the Company at $21.00 perunit, for net proceeds, after underwriting discounts of $18.3 million andoffering expenses of $4.3 million, of $238.8 million, of which $122.0 millionwas used to reduce indebtedness, $114.4 million was used to redeem a portion ofthe membership interests in the Company and units held by certain affiliatedand non-affiliated holders and approximately $2.0 million was used to pay bonusesto certain executive officers of the Company.

***Credit Facility***

AtJune 30, 2007 the Company had an $800.0 million senior secured revolvingcredit facility with a maturity of August 2010, and a borrowing base of $765.0million.  On June 29, 2007,the Company received a commitment from two lenders under its Credit Facility toprovide funding of up to $1.9 billion contingent on closing of theMid-Continent

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Acquisition.  See Note 2 in Notes to CondensedConsolidated Financial Statements for additional details about theMid-Continent Acquisition.  In July 2007,the Company incurred approximately $4.8 million in commitment fees that will beamortized over the life of this debt agreement.

Inconnection with amendments, in the first six months of 2007, the Company paidfees of approximately $1.7 million, which will be amortized over the remainingterm of the Credit Facility, and wrote-off deferred financing fees ofapproximately $0.5 million.  At July 31, 2007, we had $284.9 million available forborrowing under our Credit Facility.

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

Atour election, interest on borrowings under the Credit Facility is determined byreference to LIBOR plus an applicable margin between 1.00% and 1.75% per annum;or a domestic bank rate plus an applicable margin between 0.00% and 0.25% perannum.  Interest is 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 require the Company to maintaincertain financial ratios.  The Company isin compliance with all financial and other covenants of its Credit Facility.

***Off-BalanceSheet Arrangements***

At June 30, 2007,the Company did not have any off-balance sheet arrangements that have, or arereasonably likely to have, a material effect on our financial position orresults of operations.  See Note 9in Notes to Condensed Consolidated Financial Statements for discussion of theCompany’s oil and gas swaps entered into in July 2007.

***Contingencies***

The Company regularlyanalyzes current information and accrues for probable liabilities on thedisposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments,litigation or other sources are recorded when it is probable that a liabilityhas been incurred and the amount can be reasonably estimated.

***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 2006 Annual Report on Form 10-K.  As of June 30, 2007, there have been nosignificant changes to the Company’s contractual obligations fromDecember 31, 2006.

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**Non-GAAP Financial Measure**

***Adjusted EBITDA***

Wedefine Adjusted EBITDA as net income (loss) plus:

·                  Net operatingcash flow from acquisitions, effective date through closing date;

·                  Interestexpense; net of amounts capitalized;

·                  Depreciation,depletion and amortization;

·                  Write-off ofdeferred financing fees and other;

·                  (Gain) loss onsale of assets;

·                  Accretion ofasset retirement obligation;

·                  Unrealized(gain) loss on oil and gas derivatives;

·                  Unit-basedcompensation and unit warrant expense;

·                  IPO cashbonuses; and

·                  Incometax provision.

AdjustedEBITDA is a significant performance metric used by our management to indicate(prior to the establishment of any reserves by our Board of Directors) the cashdistributions we expect to pay our unitholders. Specifically, this financial measure indicates to investors whether ornot we are generating cash flow at a level that can sustain or support anincrease in our quarterly distribution rates. Adjusted EBITDA is also a quantitative standard used throughout theinvestment community with respect to publicly-traded partnerships and limitedliability companies.

Forthe second quarter of 2007 as compared to the second quarter of 2006, adjustedEBITDA increased 146%, from $14.9 million to $36.6 million.  For the six months ended June 30, 2007as compared to the comparable period of the prior year, adjusted EBITDAincreased 129%, from $30.6 million to $70.1 million.

Thefollowing table presents a reconciliation of our consolidated net income (loss)to Adjusted EBITDA:
| ** **                                                                      | ** ** | **Three Months Ended   June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|---------------------------------------------------------------------------------|------------|-------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                                      | ** ** | **2007**                                              | ** ** | **2006**                                      | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                                      | ** ** | **(in thousands)**                               | ** ** |
|                                                                            |       |                                                  |       |                                          |       |   |   |   |   |
| Net income  (loss)                                                              |       | $                                                     | (17,126    | )                                             | $          | 10,239 |   | $ | (84,973 | ) | $ | 32,216 |   |
| Plus:                                                                           |       |                                                  |       |                                          |       |   |   |   |   |
| Net operating cash flow from acquisitions, effective  date through closing date |       | 1,923                                                 |       | 712                                           |       | 4,693 |   | 712 |   |
| Interest expense, net of amounts capitalized                                    |       | 9,952                                                 |       | 2,696                                         |       | 19,865 |   | 5,335 |   |
| Depreciation, depletion and amortization                                        |       | 12,938                                                |       | 4,116                                         |       | 24,789 |   | 7,816 |   |
| Write-off of deferred financing fees and other                                  |       | (255                                                  | )          | 129                                           |       | 549 |   | 503 |   |
| (Gain) loss on sale of assets                                                   |       | 60                                                    |       | 29                                            |       | (885 | ) | 47 |   |
| Accretion of asset retirement obligation                                        |       | 224                                                   |       | 61                                            |       | 334 |   | 119 |   |
| Unrealized (gain) loss on oil and gas derivatives                               |       | 24,887                                                |       | (7,055                                        | )          | 94,401 |   | (27,978 | ) |
| Unit-based compensation and unit warrant expense                                |       | 3,951                                                 |       | 4,196                                         |       | 7,691 |   | 9,876 |   |
| IPO cash bonuses                                                                |       | —                                                |       | —                                        |       | — |   | 2,039 |   |
| Income tax (benefit) provision (1)                                              |       | 30                                                    |       | (193                                          | )          | 3,662 |   | (74 | ) |
| Adjusted EBITDA                                                                 |       | $                                                     | 36,584     |                                          | $          | 14,930 |   | $ | 70,126 |   | $ | 30,611 |   |

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(1)             TheCompany’s taxable subsidiaries generated net operating losses for the yearended December 31, 2006.  Managementhas subsequently recovered expenses through an intercompany charge for servicesfrom Linn Operating, Inc. to Linn Energy, LLC, which resulted in acorresponding tax expense for the three and six months ended June 30,2007.

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As noted above,Adjusted EBITDA is non-GAAP performance measure used by our management and is aquantitative measure used in the oil and gas industry.  On our condensed consolidated statements ofcash flows, our net cash used by operating activities for the six months endedJune 30, 2007, was approximately $19.4 million and includes approximately$91.5 million unrealized losses on derivatives and $7.7 million unit-basedcompensation and unit warrant expense. Our net cash used by operating activities for the six months endedJune 30, 2006, was approximately $14.1 million and includes $32.3 millionunrealized gains on derivatives and $9.8 million unit-based compensationexpense.

**NewAccounting Standards**

There have been noaccounting standards that materially affected the Company this period; however,see Note 13 in Notes to Condensed Consolidated Financial Statements fordetail regarding FIN 48.

**CautionaryStatement**

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

·                  business strategy;

·                  acquisition strategy;

·                  financial strategy;

·                  drilling locations;

·                  oil, gas and NGL reserves;

·                  realized oil, gas and NGL 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 ofstatements, other than statements of historical fact included in this QuarterlyReport on Form 10-Q, are forward looking statements.  These forward-looking statements may be foundin Item 2.  In some cases,forward-looking statements can be identified by terminology such as “may,” “will,”“could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,”“estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” thenegative of such terms or other comparable terminology.

The forward-lookingstatements contained in this Quarterly Report on Form 10-Q are largelybased on our 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 and assumptions to be reasonable, they are inherentlyuncertain and involve a number of risks and uncertainties beyond ourcontrol.  In addition, management’sassumptions may prove to be inaccurate. We caution that the forward-looking statements contained in thisQuarterly Report on Form 10-Q are not guarantees of future performance,and we cannot assure any reader that such statements will be realized or theforward-looking statements or events will occur.  Actual results may differ materially fromthose anticipated or implied in forward-looking statements due to factorslisted in “Item 1A. Risk Factors” in our Annual Report on Form 10-Kfor the year ended December 31, 2006, and elsewhere in our Annual Reportand also in our Quarterly Reports on Form 10-Q.  The forward-looking statements speak only asof the date made, and other than as required by law, we undertake no obligationto publicly update or revise any forward-looking statement, whether as a resultof new information, future events or otherwise.

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

Theprimary objective of the following information is to provide forward-lookingquantitative and qualitative information about our potential exposure to marketrisks.  The term “market risk” refers tothe risk of loss arising from adverse changes in oil, gas and NGL prices andinterest rates.  The disclosures are notmeant to be precise indicators of expected future losses, but rather indicatorsof reasonably possible losses.  Thisforward-looking information provides indicators of how we view and manage ourongoing market risk exposures.  All ofour market risk sensitive instruments were entered into for purposes other thanspeculative trading.

**Commodity Price Risk**

Ourmajor market risk exposure is in the pricing applicable to our oil, gas and NGLproduction.  Realized pricing isprimarily driven by the spot market prices applicable to our production and theprevailing price for oil, gas and NGL. Pricing for oil, gas and NGL production has been volatile andunpredictable for several years, and we expect this volatility to continue inthe future.  The prices we receive forproduction depend on many factors outside of our control.

Weperiodically have entered into and anticipate entering into hedgingarrangements with respect to a portion of our projected production throughvarious transactions that hedge the future prices received.  These transactions may include price swapswhereby we will receive a fixed price for our production and pay a variablemarket price to the contract counterparty. At the settlement date, we receive the excess, if any, of the fixedfloor over the floating rate. Additionally, we have put options for which we pay the counterparty thefair value at the purchase date.  Thesehedging activities are intended to support commodity prices at targeted levelsand to manage our exposure to oil, gas and NGL price fluctuations.  We do not hold or issue derivativeinstruments for speculative trading purposes.

AtJune 30, 2007, the fair value of hedges that settle during the next twelvemonths was an asset of approximately $29.4 million and a liability ofapproximately $4.5 million for a net asset of approximately $24.9 million, whichwe are owed by the counterparty.  A 10%increase in the index oil and gas prices above the June 30, 2007 pricesfor the next twelve months would result in a reduction in the value of ourhedges of approximately $16.8 million; conversely, a 10% decrease in the indexoil and gas prices would result in an increase of approximately $21.3 million.

In July 2007, the Companyentered into hedging contracts to reduce oil, gas and NGL price risk exposuresrelated to its pending Mid-Continent Acquisition (see Note 2 in Notes toCondensed Consolidated Financial Statements). The contracts cover 40 Bcf of gas and 800,000 Bbls of oil per year for2008 through 2012 and 7.8 Bcf of gas and 157,000 Bbls of oil for the fourthquarter of 2007.  The contracts includedeferred premium puts entered into in July 2007, for which the Company will paythe counterparty approximately $132.2 million in October 2007.  In addition, the contracts include adeal-contingent option to enter into oil and gas price swaps upon consummationof the Mid-Continent Acquisition for which the Company expects to paycommitment fees and premiums totaling approximately $71.9 million to thecounterparty.  The Company’s commitmentto enter into the swaps is contingent on the closing of the Mid-Continent Acquisition.

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The following tablessummarize open derivative positions on annual production volumes as ofJuly 31, 2007, including the hedging contracts entered into in July 2007and the swap contracts contingent on closing of the Mid-Continent Acquisitiondiscussed above:
|                          | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** | **Year  2012** | ** ** |
|--------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas  Positions**       |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price  Swaps:      |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MMMBtu)   |       | 7,361          |       | 40,005         |       | 41,346         |       | 39,461         |       | 38,741         |       | 26,741         |       |
| Average Price ($/MMBtu)  |       | $              | 8.52       |           | $          | 8.41           |       | $              | 8.23       |           | $          | 8.10           |       | $ | 8.08 |   | $ | 8.35 |   |
| Puts:                    |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MMMBtu)   |       | 6,536          |       | 20,312         |       | 20,219         |       | 20,219         |       | 20,219         |       | 13,259         |       |
| Average Price ($/MMBtu)  |       | $              | 8.49       |           | $          | 8.55           |       | $              | 8.35       |           | $          | 8.35           |       | $ | 8.35 |   | $ | 8.80 |   |
| Total:                   |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MMMBtu)   |       | 13,897         |       | 60,317         |       | 61,565         |       | 59,680         |       | 58,960         |       | 40,000         |       |
| Average Price  ($/MMBtu) |       | $              | 8.50       |           | $          | 8.45           |       | $              | 8.27       |           | $          | 8.19           |       | $ | 8.17 |   | $ | 8.50 |   |

 
|                        | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** | **Year  2012** | ** ** |
|------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Oil  Positions**     |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price  Swaps:    |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)  |       | 295            |       | 1,080          |       | 1,100          |       | 1,070          |       | 1,045          |       | 520            |       |
| Average Price ($/Bbl)  |       | $              | 74.85      |           | $          | 73.44          |       | $              | 73.22      |           | $          | 73.55          |       | $ | 67.01 |   | $ | 72.50 |   |
| Puts:                  |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)  |       | 695            |       | 1,830          |       | 1,830          |       | 1,980          |       | 2,030          |       | 280            |       |
| Average Price ($/Bbl)  |       | $              | 67.24      |           | $          | 67.68          |       | $              | 67.68      |           | $          | 67.47          |       | $ | 66.43 |   | $ | 75.36 |   |
| Total:                 |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume (MBbls)  |       | 990            |       | 2,910          |       | 2,930          |       | 3,050          |       | 3,075          |       | 800            |       |
| Average Price  ($/Bbl) |       | $              | 69.51      |           | $          | 69.82          |       | $              | 69.76      |           | $          | 69.61          |       | $ | 66.63 |   | $ | 73.50 |   |

 

***Interest Rate Risk***

AtJune 30, 2007, we had long-term debt outstanding of $476.0 million underour Credit Facility, which incurred interest at floating rates in accordancethe Credit Facility agreement.  As ofJune 30, 2007, our rate based on the one-month LIBOR was approximately6.625%.  A 1% increase in the one-monthLIBOR would result in an estimated $4.8 million increase in annual interestexpense.

Wehave periodically entered into interest rate swap agreements to minimize theeffect of fluctuations in interest rates. We are required to pay our counterparties the difference between thefixed rate in the contract and the actual rate if the actual rate is lower thanthe fixed rate and conversely, our counterparties are required to pay us if theactual rate is higher than the fixed rate in the contract.  At June 30, 2007, we had two interestrate swaps outstanding with notional amounts of $50.0 million for 2007 and2008, and fixed interest rates of 5.30% and 5.79%, respectively.

A 1%change in LIBOR as of June 30, 2007 would result in an estimated $1.0million change in annual interest expense associated with our interest swapagreements.

Underthe terms of the swap agreements, we receive quarterly interest payments at thethree-month LIBOR rate.

Wedid not designate the interest rate swap agreements we entered into as hedgesunder SFAS 133, even though they protect us from changes in interestrates.  Therefore, the changes in fairvalue of these instruments were recorded in our current earnings.  These amounts are non-cash gains and losses.

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**Item 4.     Controls andProcedures**

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

The Company maintainsdisclosure controls and procedures that are designed to ensure that informationrequired to be disclosed in the Company’s reports under the Securities ExchangeAct of 1934 is recorded, processed, summarized and reported within the timeperiods specified in the SEC’s rules and forms, and that such information isaccumulated and communicated to management, including the Company’s ChiefExecutive Officer and Chief Financial Officer, and the Company’s AuditCommittee of the Board of Directors, as appropriate, to allow timely decisionsregarding required disclosure.  Indesigning and evaluating the disclosure controls and procedures, managementrecognizes that any controls and procedures, no matter how well designed andoperated, can provide only reasonable assurance of achieving the desiredcontrol objectives, and management is required to apply its judgment inevaluating the cost-benefit relationship of possible controls and procedures.

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

Due to the remediationstatus of our material weaknesses described below, our Chief Executive Officerand Chief Financial Officer continue to conclude that our disclosure controlsand procedures were not entirely effective as of June 30, 2007.  We believe we have taken the necessary stepsto address the matters related to the material weaknesses described below andwe conclude that the material weaknesses have been substantially remediated.  Regarding review controls, including controlsover significant computations involving estimates and judgment, we believe thatthese internal controls have not been implemented and operational for a sufficientperiod of time to demonstrate that they are operating effectively.  We believe our condensed consolidatedfinancial statements included in this Quarterly Report on Form 10-Q fairlypresent in all material respects our financial position, results of operationsand cash flows for the periods presented in accordance with United Statesgenerally accepted accounting principles.

*Materialweaknesses in internal control*.  Specifically, the Company lacked:  (i) personnel with sufficient technicalaccounting and financial reporting expertise, (ii) adequate reviewcontrols over account reconciliations and account analyses, (iii) policiesand procedures to determine and document the appropriate application ofaccounting principles, and (iv) policies and procedures requiring adetailed and comprehensive review of the underlying information supporting theamounts included in the annual and interim consolidated financial statementsand disclosures.  We conclude that thematerial weaknesses have been substantially remediated.  Regarding review controls, including controlsover significant computations involving estimates and judgment, we believe thatthese internal controls have not been implemented and operational for asufficient period of time to demonstrate they are operating effectively.

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

1.                                     Werecruited an experienced accounting team with over 130 combined years ofexperience in oil and gas accounting and financial reporting.

2.                                     Weutilized outside consultants with extensive oil and gas financial reportingexperience and augmented our accounting resources to assist with requiredfilings and documentation of reconciliations and procedures.

3.                                     Accountingand reporting position papers were developed for critical accounting policiesinvolving judgment or application of complex accounting standards.

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

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

6.                                     Weimplemented the use of disclosure checklists addressing the disclosurerequirements under GAAP as well as the incremental financial and non-financialinformation required by SEC regulations.

7.                                     Weprovided extensive training on our accounting software system to both new andestablished accounting personnel.

In addition, to furtherenhance controls, during the three months ended June 30, 2007, thefollowing improvements were implemented:

1.                                     Westrengthened controls over financially significant spreadsheets, includingchange, version, access, input/output and data controls.

2.                                     Weenhanced information technology (“IT”) controls, in areas including the generalIT environment, access to programs and data and change management.

As noted above, webelieve we have taken the necessary steps to address the matters related to thematerial weaknesses described above and we conclude that the materialweaknesses have been substantially remediated. Regarding review controls, including controls over significantcomputations involving estimates and judgment, we believe that these internalcontrols have not been implemented and operational for a sufficient period oftime to demonstrate that they are operating effectively.

***(b)  *Changes and remediation in the Company’s internal control overfinancial reporting**

The items noted aboveconstitute the changes in our internal control over financial reporting, asdefined in Rule 13(a)-15(f) under the Exchange Act, during the threemonths ended June 30, 2007, that have materially affected, or arereasonably likely to materially affect, our internal control over financial reporting.

As previously reported,we expect to continue to make changes in our internal control over financialreporting during the periods prior to December 31, 2007 in connection withour compliance efforts under Section 404 of the Sarbanes-Oxley Act of 2002.  As such, we will continue to assess theadequacy of our internal control over financial reporting, remediate anycontrol weaknesses that may be identified, validate through testing thatcontrols are functioning as designed and implement a continuous reporting andimprovement process for internal control over financial reporting.

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**PART II – OTHER INFORMATION**

**Item 1.        LegalProceedings**

Not applicable.

**Item 1A.     Risk Factors**

Ourbusiness has many risks.  As of the dateof this report, the factors that have materially changed from those reported in“Item 1A. Risk Factors” in our Annual Report on Form 10-K forthe year ended December 31, 2006 are presented below.  These risk factors primarily relate to theaddition of NGL to our revenue stream in the first quarter of 2007, inconjunction with our acquisition of properties in the Texas Panhandle.  This information should be consideredcarefully, together with other information in this report and other reports andmaterials we file with the SEC.

**RisksRelated to Our Business**

***We may not have sufficient cash flow from operations to pay the quarterlydistribution at the current distribution level and future distributions to ourunitholders may fluctuate from quarter to quarter.***

We may not have sufficient cashflow from operations each quarter to pay the quarterly distribution at thecurrent distribution level.  Under theterms of our limited liability company agreement, the amount of cash otherwiseavailable for distribution will be reduced by our operating expenses and theamount of any cash reserve amounts that our Board of Directors establishes toprovide for future operations, future capital expenditures, future debt servicerequirements and future cash distributions to our unitholders.  The amount of cash we can distribute on ourunits principally depends upon the amount of cash we generate from ouroperations, which will fluctuate from quarter to quarter based on, among otherthings:

·                  the amount of oil, gas and NGL we produce;

·                  the price at which we are able to sell our oil,gas and NGL production;

·                  the level of our operating costs;

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

·                  the level of our capital expenditures.

In addition, the actual amount ofcash we will have available for distribution will depend on other factors, someof which are beyond our control, including:

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

·                  the costs of acquisitions, if any;

·                  fluctuations in our working capital needs;

·                  timing and collectibility of receivables;

·                  restrictions on distributions contained in ourcredit facility;

·                  prevailing economic conditions; and

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

As a result of these factors, theamount of cash we distribute to our unitholders in any quarter may fluctuatesignificantly from quarter to quarter and may be significantly less than thecurrent distribution level.

***We actively seek to acquire oiland gas properties.  Acquisitions involvepotential risks that could adversely impact our future growth and our abilityto increase distributions.***

Any acquisition involvespotential risks, including, among other things:

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

·                  inaccurate assumptions about revenues and costs,including synergies;

·                  significant increases in our indebtedness andworking capital requirements;

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·                  an inability to transition and integratesuccessfully or timely the businesses we acquire;

·                  an inability to integrate data systemssuccessfully or timely;

·                  the assumption of unknown liabilities;

·                  limitations on rights to indemnity from theseller;

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

·                  increased demands on existing personnel and on ourcorporate structure;

·                  customer or key employee losses at the acquiredbusinesses; and

·                  the failure to realize expected growth orprofitability.

The scope and cost ofthese risks may ultimately be materially greater than estimated at the time ofthe 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.

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

Our revenue, profitability andcash flow depend upon the prices of and demand for oil, gas and NGL.  The oil, gas and NGL market is very volatileand a drop in prices can significantly affect our financial results and impedeour growth.  Changes in oil, gas and NGLprices have a significant impact on the value of our reserves and on our cashflow.  Prices for these commodities mayfluctuate widely in response to relatively minor changes in the supply of anddemand for them, market uncertainty and a variety of additional factors thatare beyond our control, such as:

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

·                  the price and level of foreign imports;

·                  the level of consumer product demand;

·                  weather conditions;

·                  overall domestic and global economic conditions;

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

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

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

·                  technological advances affecting energyconsumption;

·                  domestic and foreign governmental regulations andtaxation;

·                  the impact of energy conservation efforts;

·                  the proximity and capacity of pipelines and othertransportation facilities; and

·                  the price and availability of alternative fuels.

In the past, the prices of oil, gas and NGL have beenextremely volatile, and we expect this volatility to continue.  If commodity prices decline significantly fora prolonged period, our cash flow from operations will decline, and we may haveto lower our distribution or may not be able to pay distributions at all.

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

Declines in oil, gas andNGL prices may result in our having to make substantial downward adjustments toour estimated proved reserves.  If thisoccurs, or if our estimates of development costs increase, production datafactors change or drilling results deteriorate, accounting rules may require usto write-down, as a non-cash charge to earnings, the carrying value of ourproperties for impairments.  We are requiredto perform impairment tests on our assets periodically and whenever events orchanges in circumstances warrant a review of our assets.  To the extent such tests indicate a reductionof the estimated useful life or estimated future cash flows of our assets, thecarrying value may not be recoverable and therefore require a write-down.  We may incur impairment charges in thefuture, which could have a material adverse effect on our results of operationsin the period incurred and on our ability to borrow funds under our creditfacility, which in turn may adversely affect our ability to make cashdistributions to our unitholders.

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

Producing oil and gasreservoirs are characterized by declining production rates that vary dependingupon reservoir characteristics and other factors.  The overall rate of decline for ourproduction will change if production from our existing wells declines in adifferent manner than we have estimated and can change when we drill additionalwells, make acquisitions and under other circumstances.  Thus, our future oil, gas and NGL reservesand production and, therefore, our cash flow and income, are highly dependenton our success in efficiently developing and exploiting our current reservesand finding or acquiring additional economically 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 cash flow from operationsand our ability to make distributions to our unitholders.

***Our estimated reserves are based on many assumptions that may prove tobe inaccurate.  Any material inaccuraciesin these reserve estimates or underlying assumptions will materially affect thequantities and present value of our reserves.***

No one can measureunderground accumulations of oil, gas and NGL in an exact way.  Reserve engineering requires subjectiveestimates of underground accumulations of oil, gas and NGL and assumptionsconcerning future oil, gas and NGL prices, production levels, and operating anddevelopment costs.  As a result, estimatedquantities of proved reserves and projections of future production rates andthe timing of development expenditures may prove to be inaccurate.  Independent petroleum engineering firmsprepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserveestimates taking into account the results of actual drilling andproduction.  Some of our reserveestimates are made without the benefit of a lengthy production history, whichare less reliable than estimates based on a lengthy production history.  Also, we make certain assumptions regardingfuture oil, gas and NGL prices, production levels, and operating anddevelopment costs that may prove incorrect. Any significant variance from these assumptions by actual figures couldgreatly affect our estimates of reserves, the economically recoverablequantities of oil, gas and NGL attributable to any particular group ofproperties, the classifications of reserves based on risk of recovery andestimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserveestimates are based, as described above, often result in the actual quantitiesof oil, gas and NGL we ultimately recover being different from our reserveestimates.

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

·                  actual prices we receive for oil, gas and NGL;

·                  the amount and timing of actual production;

·                  supply of and demand for oil, gas and NGL; and

·                  changes in governmental regulations or taxation.

The timing of both ourproduction and our incurrence of expenses in connection with the developmentand production of our properties will affect the timing of actual future netcash flows from proved reserves, and thus their actual present value.  In addition, the 10% discount factor,required to be used pursuant to SEC Regulation S-X Rule 4-10 whencalculating discounted future net cash flows, may not be the most appropriatediscount factor based on interest rates in effect from time to time and risksassociated with us or the oil and gas industry in general.

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

The oil and gasindustry is capital intensive.  We makeand expect to continue to make substantial capital expenditures in our businessfor the development, production and acquisition of oil, gas and NGLreserves.  These expenditures will reduceour cash available for distribution.  Weintend to finance our future capital expenditures with cash flow fromoperations and our financing arrangements. Our cash flow from operations and access to capital are subject to anumber of variables, including:

·                  our proved reserves;

·                  the level of oil, gas and NGL we are able toproduce from existing wells;

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·                  the prices at which we are able to sell our oil,gas and NGL; and

·                  our ability to acquire, locate and produce newreserves.

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

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

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

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

For the six months endedJune 30, 2007, Dominion Resources, Inc., ConocoPhillips and Duke EnergyCorporation accounted for approximately 31%, 16% and 13%, respectively, of ourtotal volumes, or 60% in the aggregate. For the year ended December 31, 2006, Dominion Resources, Inc. andConocoPhillips accounted for approximately 53%, and 14%, respectively, of ourtotal volumes, or 67% in the aggregate. To the extent these and other customers reduce the volumes of oil, gasor NGL that they purchase from us, our revenues and cash available fordistribution could decline.

***Shortagesof drilling rigs, pipe, equipment and crews could delay our operations andincrease our drilling costs, which could impact our ability to generatesufficient cash flow from operations to pay quarterly distributions to ourunitholders at the current distribution level.***

Higher oil, gas and NGLprices increase the demand for drilling rigs, pipe, equipment and crews and canlead to shortages of, and increasing costs for, drilling equipment, servicesand personnel.  Shortages of, orincreasing costs for, experienced drilling crews and oil field equipment andservices could restrict our ability to drill the wells and conduct theoperations which we currently have planned. Any delay in the drilling of new wells or significant increase indrilling costs could impact our ability to generate sufficient cash flow fromoperations to pay quarterly distributions to our unitholders at the currentdistribution level.

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

None not previouslyreported.

**Item 3.        Defaults Upon Senior Securities**

None.

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

A special meeting of unitholders was held onApril 5, 2007.  The matters voted onat the meeting and the results are set forth below.

1.               To vote upon (a) achange in terms of our Class C units to provide that each Class Cunit will convert automatically into one of our units and (b) the issuance of7,465,946 units upon such conversion.
| Votes For  | ** ** | **Votes Against  or Withheld** | ** ** | **Abstentions** |
|------------|------------|--------------------------------|------------|-----------------|
|       |       |                           |       |            |
| 27,484,956 |       | 56,028                         |       | 49,587          |

 

Our 2007 Annual Meetingof Unitholders was held on June 19, 2007. Set forth below are descriptions of the matters voted on at the meetingand the results of the votes taken at the meeting.

1.               To elect fourdirectors to the Company’s Board of Directors to serve until the 2008 AnnualMeeting of Unitholders.
| Name of Director      | ** ** | **Votes For** | ** ** | **Votes Against  or Withheld** |
|-----------------------|------------|---------------|------------|--------------------------------|
|                  |       |          |       |                           |
| Michael C. Linn       |       | 41,008,089    |       | 52,960                         |
| George A. Alcorn      |       | 40,972,109    |       | 88,940                         |
| Terrence S.  Jacobs   |       | 41,011,835    |       | 49,214                         |
| Jeffrey C.  Swoveland |       | 41,006,749    |       | 54,300                         |

2.               To ratify theappointment of KPMG LLP as independent auditor of the Company for the fiscalyear ending December 31, 2007.
| Votes For  | ** ** | **Votes Against  or Withheld** | ** ** | **Abstentions** |
|------------|------------|--------------------------------|------------|-----------------|
|       |       |                           |       |            |
| 40,981,026 |       | 53,874                         |       | 26,149          |

 

**Item 5.Other Information**

None.

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**Item6.    Exhibits**
| Exhibit Number | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|---------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2 .1†          | —     | Mid-Continent Onshore  Package Purchase Agreement, dated June 29, 2007, between Dominion Exploration  & Production, Inc., Dominion Oklahoma Texas Exploration & Production,  Inc., LDNG Texas Holdings, LLC, and DEPI Texas Holdings, LLC, as Sellers, and  Linn Energy, LLC, as Purchaser                                                                                                                                                     |
| 3 .1                | —     | Certificate of Formation of Linn Energy Holdings,  LLC (now Linn Energy, LLC) (incorporated herein by reference to  Exhibit 3.1 to our Registration Statement on Form S-1 (File  No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)                                                                                                                                                                                        |
| 3 .2                | —     | Certificate of Amendment to Certificate of Formation  of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by  reference to Exhibit 3.2 to our Form S-1 filed on June 3,  2005)                                                                                                                                                                                                                                     |
| 3 .3                | —     | Second Amended and Restated Limited Liability  Company Agreement of Linn Energy, LLC dated January 19, 2006  (incorporated herein by reference to Exhibit 3.3 to our Annual Report on  Form 10-K filed on March 30, 2007)                                                                                                                                                                                                          |
| 3 .4                | —     | Amendment No. 1 to Second Amended and Restated  Limited Liability Company Agreement of Linn Energy, LLC dated  October 24, 2006 (incorporated herein by reference to Exhibit 3.3  to our Annual Report on Form 10-K filed on March 30, 2007)                                                                                                                                                                                  |
| 3 .5                | —     | Amendment No. 2 to Second Amended and Restated  Limited Liability Company Agreement of Linn Energy, LLC dated  February 1, 2007 (incorporated herein by reference to Exhibit 3.3  to our Annual Report on Form 10-K filed on March 30, 2007)                                                                                                                                                                                  |
| 4 .1                | —     | Form of specimen unit certificate for the units of  Linn Energy, LLC (incorporated herein by reference to Exhibit 4.1 to the  Annual Report on our Form 10-K filed on May 31, 2006)                                                                                                                                                                                                                                                     |
| 10 .1*              | —     | Form of Linn Energy, LLC Long-Term Incentive Plan  (incorporated herein by reference to Exhibit 10.10 to Amendment  No. 4 to our Registration Statement on Form S-1 filed on  December 14, 2005)                                                                                                                                                                                                                                   |
| 10 .2*              | —     | First Amendment to Linn Energy, LLC Long-Term  Incentive Plan dated January 18, 2007 (incorporated by reference to  Exhibit 10.1 to our Current Report on Form 8-K filed on  January 19, 2007)                                                                                                                                                                                                                                     |
| 10 .3*              | —     | Second Amendment to Linn Energy, LLC Long-Term  Incentive Plan dated March 21, 2007 (incorporated herein by reference to  Exhibit 3.3 to our Annual Report on Form 10-K filed on  March 30, 2007)                                                                                                                                                                                                                                  |
| 10 .4*              | —     | Form of Executive Unit Option Agreement pursuant to  the Linn Energy, LLC Long-Term Incentive Plan (incorporated herein by  reference to Exhibit 3.3 to our Annual Report on Form 10-K  filed on March 30, 2007)                                                                                                                                                                                                                        |
| 10 .5*              | —     | Form of Executive Restricted Unit Agreement pursuant  to the Linn Energy, LLC Long-Term Incentive Plan (incorporated herein by  reference to Exhibit 3.3 to our Annual Report on Form 10-K  filed on March 30, 2007)                                                                                                                                                                                                                    |
| 10 .6*              | —     | Form of Phantom Unit Grant Agreement for Independent  Directors pursuant to the Linn Energy, LLC Long-Term Incentive Plan  (incorporated herein by reference to Exhibit 10.1 to our Current Report  on Form 8-K filed on August 9, 2006)                                                                                                                                                                                                |
| 10 .7               | —     | Second Amended and Restated Credit Agreement dated  as of August 1, 2006 among Linn Energy, LLC as Borrower, BNP Paribas, as  Administrative Agent, Royal Bank of Canada, as Syndication Agent, Societe  Generale, Comerica Bank and Citibank Texas, N.A. as Co-Documentation Agents  and the Lenders Party thereto (incorporated herein by reference to  Exhibit 10.1 to our Current Report on Form 8-K filed on  August 7, 2006) |
| 10 .8               | —     | First Amendment to Second Amended and Restated  Credit Agreement dated as of February 1, 2007, among Linn Energy, LLC,  as borrower, BNP Paribas, as administrative agent, and the lenders party  thereto (incorporated herein by reference to Exhibit 10.4 to our Current  Report on Form 8-K filed on February 5, 2007)                                                                                                          |
| 10 .9†         | —     | Second Amendment to Second Amended and Restated  Credit Agreement dated as of June 29, 2007, among Linn Energy, LLC, as  borrower, BNP Paribas, as administrative agent, and the lenders party thereto                                                                                                                                                                                                                                                 |
| 10 .10†        | —     | Third Amendment to Second Amended and Restated  Credit Agreement dated as of July 5, 2007, among Linn Energy, LLC, as borrower,  BNP Paribas, as administrative agent, and the lenders party thereto                                                                                                                                                                                                                                                   |

 

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| **Exhibit Number** |   | **Description**                                                                                                                                                                                                                                                               |
|-------------------------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10 .11                  | — | Class B Unit and Unit Purchase Agreement, dated as  of October 24, 2006 by and between Linn Energy, LLC and the Purchasers  named therein (incorporated herein by reference to Exhibit 10.1 to our  Current Report on Form 8-K filed on October 25, 2006) |
| 10 .12                  | — | Registration Rights Agreement dated as of  October 24, 2006 by and among Linn Energy, LLC and the Purchasers named  therein (incorporated herein by reference to Exhibit 10.2 to our Current  Report on Form 8-K filed on October 25, 2006)               |
| 10 .13                  | — | Class C Unit and Unit Purchase Agreement, dated  as of February 1, 2007 by and among the Company and the Purchasers named  therein (incorporated herein by reference to Exhibit 10.1 to our Current  Report on Form 8-K filed on February 5, 2007)   |
| 10 .14                  | — | Registration Rights Agreement dated February 1,  2007, by and among the Company and the Purchasers named therein (incorporated  herein by reference to Exhibit 10.2 to our Current Report on Form 8-K  filed on February 5, 2007)                         |
| 10 .15                  | — | Unit Purchase Agreement, dated as of June 1, 2007 by  and among the Company and the Purchasers named therein (incorporated herein  by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on June  4, 2007)                                                     |
| 10 .16                  | — | Registration Rights Agreement, dated as of June 1,  2007 by and among the Company and the Purchasers named therein (incorporated  herein by reference to Exhibit 10.2 to our Current Report on Form 8-K filed  on June 4, 2007)                                               |
| 10 .17†            | — | Class D Unit and Unit Purchase Agreement, dated as  of June 29, 2007, by and among the Company and the Purchasers named therein                                                                                                                                               |
| 31 .1†             | — | Section 302 Certification of Michael C. Linn,  Chairman, President and Chief Executive Officer of Linn Energy, LLC                                                                                                                                                            |
| 31 .2†             | — | Section 302 Certification of Kolja Rockov, Executive  Vice President and Chief Financial Officer of Linn Energy, LLC                                                                                                                                                          |
| 32 .1†             | — | Section 906 Certification of Michael C. Linn,  Chairman, President and Chief Executive Officer of Linn Energy, LLC                                                                                                                                                       |
| 32 .2†             | — | Section 906 Certification of Kolja Rockov,  Executive Vice President and Chief Financial Officer of Linn Energy, LLC                                                                                                                                                     |

 

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†  Filed herewith.

*  Management Contract or Compensatory Plan orArrangement required to be filed as an Exhibit hereto pursuant to Item 601of Regulation S-K.

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**SIGNATURE**

Pursuant to the requirements of the SecuritiesExchange Act of 1934, the registrant has duly caused this report to be signedon its behalf by the undersigned, thereunto duly authorized.
|                             | ** ** | **LINN  ENERGY, LLC**                                      |
|-----------------------------|------------|------------------------------------------------------------|
|                        |       | (Registrant)                                               |
|                        |       |                                                       |
|                        |       |                                                       |
| Date:  August 14, 2007 |       | /s/ Lisa D.  Anderson                                      |
|                        |       | Lisa D. Anderson                                           |
|                        |       | Senior Vice  President and Chief Accounting Officer        |
|                        |       | (As Duly  Authorized Officer and Chief Accounting Officer) |

 

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