**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**Form 10-Q**

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

**Forthe Quarterly Period Ended March 31, 2007**

**OR**

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

**forthe transition period from                               to                             **

**CommissionFile Number: 000-51719**

**LINN ENERGY, LLC**

*(Exact name of registrant asspecified in its charter)*

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

 

**(281) 605-4100**

*(Registrant’s telephone number,including area code)*

Indicate by check mark whether the registrant(1) has filed all reports required to be filed by Section 13 or 15(d)of the Securities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file such reports), and(2) has been subject to such filing requirements for the past90 days.    Yes  x    No  o

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer (asdefined in Rule 12b-2 of the Exchange Act).

| Large accelerated filer  o |   | Accelerated  filer  o |   | Non-accelerated  filer  x |
|--------------------------------------|--------|---------------------------------|--------|-------------------------------------|

 

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

As of April 30, 2007, there were 57,798,965 units outstanding.

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**TABLE OF CONTENTS**
|           | ** ** | ** **                                                                                                                          | ** ** | **Page** |
|-----------|------------|-------------------------------------------------------------------------------------------------------------------------------------|------------|----------|
|      |       |                                                                                                                                |       |     |
|      | ** ** | **Glossary  of Terms**                                                                                                              |       | i        |
|      |       |                                                                                                                                |       |     |
|      | ** ** | **Part  I - Financial Information**                                                                                                 |       |     |
| Item 1.   |       | Financial Statements                                                                                                                |       |     |
|      |       | Condensed  Consolidated Balance Sheets as of March 31, 2007 (Unaudited) and  December 31, 2006                       |       | 3        |
|      |       | Condensed  Consolidated Statements of Operations for the three months ended  March 31, 2007 and 2006 (Unaudited)               |       | 5        |
|      |       | Condensed Consolidated Statements of Unitholders’  Capital for the three months ended March 31, 2007 and 2006 (Unaudited) |       | 6        |
|      |       | Condensed Consolidated Statements of Cash Flows for  the three months ended March 31, 2007 and 2006 (Unaudited)                |       | 7        |
|      |       | Notes to Condensed Consolidated Financial Statements  (Unaudited)                                                                   |       | 9        |
| Item 2.   |       | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                                         |       | 24       |
| Item 3.   |       | Quantitative  and Qualitative Disclosures About Market Risk                                                                         |       | 34       |
| Item 4.   |       | Controls and  Procedures                                                                                                            |       | 35       |
|      | ** ** | **Part  II - Other Information**                                                                                                    |       |     |
| Item 1.   |       | Legal Proceedings                                                                                                                   |       | 37       |
| Item  1A. |       | Risk  Factors                                                                                                                       |       | 37       |
| Item 2.   |       | Unregistered  Sales of Equity Securities and Use of Proceeds                                                                        |       | 40       |
| Item 3.   |       | Defaults Upon  Senior Securities                                                                                                    |       | 40       |
| Item 4.   |       | Submission of  Matters to a Vote of Security Holders                                                                                |       | 40       |
| Item 5.   |       | Other Information                                                                                                                   |       | 40       |
| Item  6.  |       | Exhibits                                                                                                                            |       | 41       |
|      | ** ** | **Signature**                                                                                                                       |       | 43       |

 

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**GLOSSARYOF TERMS**

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

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

*Bcf.*  One billion cubic feet.

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

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

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

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

*Developedacres.*  Acres spaced orassigned to productive wells.

*Dryhole* or*well.*  A well found to be incapable of producinghydrocarbons in sufficient quantities such that proceeds from the sale of suchproduction would exceed production 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. *Federal Energy RegulatoryCommission.

*Grossacres* 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.

*Netacres* 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.

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

i

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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.

*Provedreserves.*  Proved oiland gas reserves are the estimated quantities of gas, natural gas liquids andoil which geological and engineering data demonstrate with reasonable certaintyto be recoverable in future years from known reservoirs under existing economicand operating conditions, i.e.,prices and costs as of the date the estimate is made.  Prices include consideration of changes inexisting prices provided only by contractual arrangements, but not onescalations based on future conditions. The definition of proved reserves is in accordance with the Securitiesand Exchange Commission’s definition set forth in Regulation S-X Rule 4-10 (a)and its subsequent staff interpretations andguidance.

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

*Provedundeveloped reserves* or*PUDs. *Reserves that areexpected to be recovered from new wells on undrilled acreage or from existingwells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage are limited tothose drilling units offsetting productive units that are reasonably certain ofproduction when drilled.  Proved reservesfor other undrilled units are claimed only where it can be demonstrated withcertainty that there is continuity of production from the existing productiveformation.  Estimates for provedundeveloped reserves are not attributed to any acreage for which an applicationof fluid injection or other improved recovery technique is contemplated, unlesssuch techniques have been proved effective by actual tests in the area and inthe 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.

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

*Successfulwell.*  A well capableof producing oil and/or gas in commercial quantities.

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

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

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

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

ii

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**PART I — FINANCIAL INFORMATION**

**Item 1.        Financial Statements**

**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED BALANCE SHEETS**
| ** **                                                                | ** ** | **March 31,**      | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                                | ** ** | **2007**                | ** ** | **2006**              | ** ** |
| ** **                                                                | ** ** | **(Unaudited)**         | ** ** | ** **            | ** ** |
| ** **                                                                | ** ** | **(in thousands)** | ** ** |
| **Assets**                                                                |       |                    |       |                  |       |
| **Current assets:**                                                       |       |                    |       |                  |       |
| Cash and cash  equivalents                                                |       | $                       | 976        |                  | $          | 6,595 |   |
| Receivables — trade, net                                             |       | 23,414                  |       | 19,124                |       |
| Inventory                                                                 |       | 745                     |       | 578                   |       |
| Current portion  of derivatives                                           |       | 24,513                  |       | 37,817                |       |
| Current portion  of deferred tax assets, net                              |       | —                  |       | 3,344                 |       |
| Other current  assets                                                     |       | 2,723                   |       | 2,218                 |       |
| Total current  assets                                                     |       | 52,371                  |       | 69,676                |       |
| ** **                                                                |       |                    |       |                  |       |
| Oil and gas properties  and related equipment (successful efforts method) |       | 1,253,363               |       | 766,638               |       |
| Less accumulated  depreciation, depletion and amortization                |       | (44,188                 | )          | (33,349               | )          |
|                                                                      |       | 1,209,175               |       | 733,289               |       |
|                                                                      |       |                    |       |                  |       |
| Property and equipment,  net                                              |       | 24,067                  |       | 20,754                |       |
|                                                                      |       |                    |       |                  |       |
| **Other assets:**                                                         |       |                    |       |                  |       |
| Long-term  portion of derivatives                                         |       | 86,443                  |       | 70,435                |       |
| Deposit for oil  and gas properties                                       |       | —                  |       | 20,086                |       |
| Deferred  financing fees and other assets, net                            |       | 2,897                   |       | 2,068                 |       |
|                                                                      |       | 89,340                  |       | 92,589                |       |
| Total assets                                                              |       | $                       | 1,374,953  |                  | $          | 916,308 |   |

 

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

3

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED BALANCE SHEETS**
| ** **                                                                                                                     | ** ** | **March 31,**                                      | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                     | ** ** | **2007**                                                | ** ** | **2006**              | ** ** |
| ** **                                                                                                                     | ** ** | **(Unaudited)**                                         | ** ** | ** **            | ** ** |
| ** **                                                                                                                     | ** ** | **(in thousands,  except unit amounts)** | ** ** |
| **Liabilities  and Unitholders’ Capital**                                                                                 | ** ** | ** **                                              | ** ** | ** **            | ** ** |
| ** **                                                                                                                     |       |                                                    |       |                  |       |
| **Current liabilities:**                                                                                                       |       |                                                    |       |                  |       |
| Current portion  of long-term notes payable                                                                                    |       | $                                                       | 871        |                  | $          | 873 |   |
| Accounts payable  and accrued expenses                                                                                         |       | 14,369                                                  |       | 12,506                |       |
| Current portion  of derivatives                                                                                                |       | 6,078                                                   |       | 462                   |       |
| Revenue  distribution                                                                                                          |       | 1,620                                                   |       | 1,839                 |       |
| Accrued interest  payable                                                                                                      |       | 2,441                                                   |       | 2,084                 |       |
| Gas purchases  payable                                                                                                         |       | 101                                                     |       | 253                   |       |
| Total current  liabilities                                                                                                     |       | 25,480                                                  |       | 18,017                |       |
|                                                                                                                           |       |                                                    |       |                  |       |
| **Long-term liabilities:**                                                                                                     |       |                                                    |       |                  |       |
| Notes payable                                                                                                                  |       | 2,250                                                   |       | 2,487                 |       |
| Credit facility                                                                                                                |       | 596,750                                                 |       | 425,750               |       |
| Asset retirement  obligation                                                                                                   |       | 14,877                                                  |       | 8,594                 |       |
| Derivatives                                                                                                                    |       | 24,785                                                  |       | 9,934                 |       |
| Other long-term  liabilities                                                                                                   |       | 968                                                     |       | 572                   |       |
| Total long-term  liabilities                                                                                                   |       | 639,630                                                 |       | 447,337               |       |
| Total  liabilities                                                                                                             |       | 665,110                                                 |       | 465,354               |       |
| ** **                                                                                                                     |       |                                                    |       |                  |       |
| **Unitholders’ capital:**                                                                                                 |       |                                                    |       |                  |       |
| 50,303,019 units  and 33,617,187 units issued and outstanding at March 31, 2007 and  December 31, 2006, respectively |       | 577,855                                                 |       | 246,034               |       |
| 9,185,965  Class B units issued and outstanding at December 31, 2006                                                 |       | —                                                  |       | 188,590               |       |
| 7,465,946  Class C units issued and outstanding at March 31, 2007                                                    |       | 183,505                                                 |       | —                |       |
| Accumulated  income (loss)                                                                                                     |       | (51,517                                                 | )          | 16,330                |       |
|                                                                                                                           |       | 709,843                                                 |       | 450,954               |       |
| Total liabilities and  unitholders’ capital                                                                               |       | $                                                       | 1,374,953  |                  | $          | 916,308 |   |

 

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

4

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF OPERATIONS**

**(Unaudited)**
| ** **                                     | ** ** | **Three Months Ended March 31,**             | ** ** |
|------------------------------------------------|------------|------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **2007**                                                         | ** ** | **2006** | ** ** |
| ** **                                     | ** ** | **(in thousands,  except per unit amounts)** | ** ** |
| **Revenues:**                                  |       |                                                             |       |   |   |
| Oil, gas and natural gas liquid sales          |       | $                                                                | 39,204     |   | $ | 16,375 |   |
| Gain (loss) on oil and gas derivatives         |       | (60,441                                                          | )          | 24,246 |   |
| Natural gas marketing revenues                 |       | 1,778                                                            |       | 1,218 |   |
| Other revenues                                 |       | 2,090                                                            |       | 289 |   |
|                                           |       | (17,369                                                          | )          | 42,128 |   |
| **Expenses:**                                  |       |                                                             |       |   |   |
| Operating expenses                             |       | 12,456                                                           |       | 2,994 |   |
| Natural gas marketing expenses                 |       | 1,347                                                            |       | 983 |   |
| General and administrative expenses            |       | 10,621                                                           |       | 9,470 |   |
| Depreciation, depletion and amortization       |       | 11,851                                                           |       | 3,700 |   |
|                                           |       | 36,275                                                           |       | 17,147 |   |
|                                           |       | (53,644                                                          | )          | 24,981 |   |
| **Other  income and (expenses):**              |       |                                                             |       |   |   |
| Interest income                                |       | 146                                                              |       | 146 |   |
| Interest expense, net of amounts capitalized   |       | (9,913                                                           | )          | (2,639 | ) |
| Write-off of deferred financing fees and other |       | (804                                                             | )          | (392 | ) |
|                                           |       | (10,571                                                          | )          | (2,885 | ) |
| Income (loss)  before income taxes             |       | (64,215                                                          | )          | 22,096 |   |
| Income tax provision                           |       | (3,632                                                           | )          | (119 | ) |
| Net income (loss)                              |       | $                                                                | (67,847    | ) | $ | 21,977 |   |
| ** **                                     |       |                                                             |       |   |   |
| **Net  income (loss) per unit:**               |       |                                                             |       |   |   |
| Units — basic                             |       | $                                                                | (1.35      | ) | $ | 0.84 |   |
| Units — diluted                           |       | $                                                                | (1.35      | ) | $ | 0.84 |   |
|                                           |       |                                                             |       |   |   |
| Class C units — basic                |       | $                                                                | (1.35      | ) | $ | — |   |
| Class C units — diluted              |       | $                                                                | (1.35      | ) | $ | — |   |
|                                           |       |                                                             |       |   |   |
| **Weighted  average units outstanding:**       |       |                                                             |       |   |   |
| Units — basic                             |       | 45,456                                                           |       | 26,273 |   |
| Units — diluted                           |       | 45,456                                                           |       | 26,273 |   |
|                                           |       |                                                             |       |   |   |
| Class C units — basic                |       | 4,894                                                            |       | — |   |
| Class C units — diluted              |       | 4,894                                                            |       | — |   |
|                                           |       |                                                             |       |   |   |
| Distributions declared  per unit               |       | $                                                                | 0.52       |   | $ | — |   |

 

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

5

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL**

**(Unaudited)**
| ** **                                                 | ** ** | **Three Months Ended March 31,** | ** ** |
|------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2007**                                             | ** ** | **2006** | ** ** |
| ** **                                                 | ** ** | **(in thousands)**                              | ** ** |
| **Unitholders’  capital:**                            |       |                                                 |       |   |   |
| Balance, beginning of period                               |       | $                                                    | 434,624    |   | $ | 16,024 |   |
| Sale of units, net of offering expense of $4,339           |       | —                                               |       | 225,139 |   |
| Sale of private placement units, net of expense of  $6,860 |       | 353,140                                              |       | — |   |
| Cancellation of member interests                           |       | —                                               |       | (100,778 | ) |
| Cancellation of units                                      |       | (7,399                                               | )          | — |   |
| Distribution to members                                    |       | (22,745                                              | )          | — |   |
| Unit-based compensation expense                            |       | 3,258                                                |       | 5,680 |   |
| Unit warrant expense                                       |       | 482                                                  |       | — |   |
| Balance, end of period                                     |       | 761,360                                              |       | 146,065 |   |
| **Accumulated  income (loss):**                            |       |                                                 |       |   |   |
| Balance, beginning of period                               |       | 16,330                                               |       | (62,855 | ) |
| Net income (loss)                                          |       | (67,847                                              | )          | 21,977 |   |
| Balance, end of period                                     |       | (51,517                                              | )          | (40,878 | ) |
| **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                           |       | $                                                    | 709,843    |   | $ | 105,187 |   |

 

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

6

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS**

**(Unaudited)**
| ** **                                                                                       | ** ** | **Three Months Ended March 31,** | ** ** |
|--------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                                       | ** ** | **2007**                                             | ** ** | **2006** | ** ** |
| ** **                                                                                       | ** ** | **(in thousands)**                              | ** ** |
| **Cash  flow from operating activities:**                                                        |       |                                                 |       |   |   |
| Net income (loss)                                                                                |       | $                                                    | (67,847    | ) | $ | 21,977 |   |
| **Adjustments to reconcile net income to net cash  provided by (used in) operating activities:** |       |                                                 |       |   |   |
| Depreciation, depletion and amortization                                                         |       | 11,851                                               |       | 3,700 |   |
| Amortization and write-off of deferred financing  fees and other                                 |       | 718                                                  |       | 582 |   |
| Gain on sale of assets                                                                           |       | (946                                                 | )          | — |   |
| Accretion of asset retirement obligation                                                         |       | 110                                                  |       | 58 |   |
| Unit-based compensation and unit warrant expense                                                 |       | 3,740                                                |       | 5,680 |   |
| Deferred income tax                                                                              |       | 3,501                                                |       | — |   |
| **Mark-to-market on oil and gas and interest rate  derivatives:**                                |       |                                                 |       |   |   |
| Total (gains) losses                                                                             |       | 60,518                                               |       | (24,653 | ) |
| Realized gains                                                                                   |       | 6,447                                                |       | 651 |   |
| **Premiums paid for oil and gas derivatives**                                                    |       | (52,992                                              | )          | — |   |
| **Changes in assets and liabilities:**                                                           |       |                                                 |       |   |   |
| (Increase) decrease in accounts receivable                                                       |       | (3,923                                               | )          | 8,126 |   |
| Increase in inventory and other assets                                                           |       | (672                                                 | )          | (992 | ) |
| Decrease in derivatives                                                                          |       | 3,766                                                |       | — |   |
| Decrease in accounts payable and accrued expenses                                                |       | (2,428                                               | )          | (4,344 | ) |
| Increase (decrease) in accrued interest payable                                                  |       | 357                                                  |       | (489 | ) |
| Decrease in revenue distribution                                                                 |       | (219                                                 | )          | (4,562 | ) |
| Decrease in gas purchases payable                                                                |       | (152                                                 | )          | (447 | ) |
| Increase in other liabilities                                                                    |       | 282                                                  |       | 113 |   |
| Net cash provided by (used in) operating activities                                              |       | (37,889                                              | )          | 5,400 |   |
| **Cash  flow from investing activities:**                                                        |       |                                                 |       |   |   |
| Acquisition of oil and gas properties                                                            |       | (440,418                                             | )          | (17,640 | ) |
| Development of oil and gas properties                                                            |       | (10,378                                              | )          | (4,144 | ) |
| Change in payable related to investing activities                                                |       | (8,337                                               | )          | 3,024 |   |
| Purchases of property and equipment                                                              |       | (3,284                                               | )          | (747 | ) |
| Proceeds from sale of assets                                                                     |       | 2,492                                                |       | 14 |   |
| Net cash used in investing activities                                                            |       | (459,925                                             | )          | (19,493 | ) |
| **Cash  flow from financing activities:**                                                        |       |                                                 |       |   |   |
| Proceeds from sale of units                                                                      |       | 360,000                                              |       | 243,149 |   |
| Redemption and cancellation of units                                                             |       | (7,399                                               | )          | (114,449 | ) |
| Principal payments on notes payable                                                              |       | (239                                                 | )          | (60,056 | ) |
| Proceeds from credit facility                                                                    |       | 171,000                                              |       | 13,000 |   |
| Payments on credit facility                                                                      |       | —                                               |       | (62,000 | ) |
| Distribution to members                                                                          |       | (22,745                                              | )          | — |   |
| Offering costs                                                                                   |       | (6,860                                               | )          | (807 | ) |
| Financing fees                                                                                   |       | (1,562                                               | )          | 95 |   |
| Net cash provided by financing activities                                                        |       | 492,195                                              |       | 18,932 |   |
| Net increase (decrease) in cash                                                                  |       | (5,619                                               | )          | 4,839 |   |
| **Cash  and cash equivalents:**                                                                  |       |                                                 |       |   |   |
| Beginning                                                                                        |       | 6,595                                                |       | 11,041 |   |
| Ending                                                                                           |       | $                                                    | 976        |   | $ | 15,880 |   |

 

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

7

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**LINN ENERGY, LLC**

**CONDENSEDCONSOLIDATED STATEMENTS OF CASH FLOWS — SUPPLEMENTAL DISCLOSURES**

**(Unaudited)**
| ** **                                                                                       | ** ** | **Three Months Ended March 31,** | ** ** |
|--------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                                       | ** ** | **2007**                                             | ** ** | **2006** | ** ** |
| ** **                                                                                       | ** ** | **(in thousands)**                              | ** ** |
| **Supplemental  disclosure of cash flow information:**                                           |       |                                                 |       |   |   |
| Cash payments for interest                                                                       |       | $                                                    | 9,310      |   | $ | 3,336 |   |
| **Supplemental  disclosures of non-cash investing and financing activities:**                    |       |                                                 |       |   |   |
| Acquisitions of vehicles and equipment through  issuance of notes payable                        |       | $                                                    | —     |   | $ | 1,172 |   |
| In connection with the purchase of oil and gas  properties, liabilities were assumed as follows: |       |                                                 |       |   |   |
| Fair value of assets acquired                                                                    |       | $                                                    | 450,694    |   | $ | 17,640 |   |
| Cash paid                                                                                        |       | (440,418                                             | )          | (17,640 | ) |
| Liabilities  assumed                                                                             |       | $                                                    | 10,276     |   | $ | — |   |

 

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

8

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**LINN ENERGY, LLC**

**NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS**

**(Unaudited)**

**(1)           Basisof Presentation**

The condensedconsolidated financial statements at March 31, 2007, and for the threemonths ended March 31, 2007 and 2006, are unaudited, but in the opinion ofmanagement include all adjustments (consisting only of normal recurringadjustments) necessary for a fair presentation of the results for the interimperiods.  Certain information and notedisclosures normally included in annual financial statements prepared inaccordance with 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 financialinformation included herein should be read in conjunction with the financialstatements and notes in our Annual Report on Form 10-K for the yearended December 31, 2006.  Certainamounts in the condensed consolidated financial statements and notes theretohave been reclassified to conform to the 2007 financial statement presentation.

**(2)           Summary ofSignificant Accounting Policies**

***(a)***                                 Organizationand Description of Business

LinnEnergy, LLC (“Linn” or the “Company”) is an independent oil and gas companyfocused on the development and acquisition of long-lived properties in theUnited States that began operations in March 2003 and was formed as a Delawarelimited liability company in April 2005. Linn is a holding company that conducts its operations through, and itsoperating assets are owned by, its wholly-owned subsidiaries.

***(b)***                                 Principlesof Consolidation

Thecondensed consolidated financial statements include the accounts of the Companyand its wholly-owned subsidiaries.  Allsignificant intercompany transactions and balances have been eliminated uponconsolidation.

***(c)***                                  Useof Estimates

Managementof the Company has made a number of estimates and assumptions relating to thereporting of assets and liabilities and revenues and expenses and thedisclosure of contingent assets and liabilities to prepare these condensedconsolidated financial statements in conformity with GAAP.  Actual results could differ from thoseestimates.  The estimates that areparticularly significant to the financial statements include estimates of oil,gas and natural 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.

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

Reserves and their relation toestimated future net cash flows impact the Company’s depletion and impairmentcalculations.  As a result, adjustmentsto depletion and impairment are made concurrently with changes to reserveestimates.  The Company prepares itsreserve estimates, and the projected cash flows derived from these reserveestimates, in accordance with SEC guidelines.

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Theindependent engineering firm adheres to the same guidelines when preparingtheir reserve reports.  The accuracy ofthe Company’s reserve estimates is a function of many factors including thefollowing:  the quality and quantity ofavailable data, the interpretation of that data, the accuracy of variousmandated economic assumptions and the judgments of the individuals preparingthe estimates.  As a result, the Company’sproved reserve estimates developed from such assumptions could materially varyfrom the ultimate quantities of oil, gas and NGL eventually recovered.

***(d)***                                 CashEquivalents

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

***(e)***                                  TradeAccounts Receivable, Net

Tradeaccounts receivable are recorded at the invoiced amount and do not bearinterest.  The Company routinely assessesthe financial strength of its customers and bad debts are recorded based on anaccount-by-account review after all means of collection have been exhausted andthe potential for recovery is considered remote.  The Company does not have anyoff-balance-sheet credit exposure related to its customers.

***(f)***                                    Inventory

Inventoryof well equipment, parts, and supplies are valued at cost, determined by thefirst-in-first-out method.

***(g)***                                 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.

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

Proved reserves are estimated by anindependent petroleum engineering firm and are subject to future revisionsbased on availability of additional information.  The Company accounts for asset retirementobligations in accordance with SFAS No. 143, *“Accountingfor Asset Retirement Obligations”* (“SFAS 143”).  In accordance with SFAS 143, estimatedasset retirement costs are recognized when the obligation is incurred, and areamortized over proved developed reserves using the units of productionmethod.  Asset retirement costs areestimated by the Company’s engineers using existing regulatory requirements andanticipated future inflation rates.

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

Upon sale or retirement of completefields of depreciable or depleted property, the book value thereof, lessproceeds or salvage value, is charged or credited to income.  On sale or retirement of an individual wellthe proceeds are credited to accumulated depreciation and depletion.

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In accordance withSFAS No. 144, *“Accounting for theImpairment or Disposal of Long-Lived Assets”* (“SFAS 144”), weassess proved oil and gas properties for possible impairment when events orcircumstances indicate that the recorded carrying value of the properties maynot be recoverable.  We recognize animpairment loss as a result of a triggering event and when the estimatedundiscounted future cash flows from a property are less than the carryingvalue.  If impairment is indicated, thecash flows are discounted at a rate approximate to our cost of capital andcompared to the carrying value for determining the amount of the impairmentloss to record.  Estimated future cashflows are based on management’s expectations for the future and includeestimates of oil and gas reserves and future commodity prices and operatingcosts.  Downward revisions in estimatesof reserve quantities or expectations of falling commodity prices or risingoperating costs could result in a reduction in undiscounted future cash flowsand could indicate property impairment. No impairments were recorded during the three months endedMarch 31, 2007 or 2006.

Unproven properties that areindividually insignificant are amortized. Unproved properties that are individually significant are assessed forimpairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairmentis deemed to have occurred.

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

Tangiblelong-lived assets are evaluated in accordance with SFAS 144, when eventsand circumstances indicate that the carrying value of an asset may not berecoverable.  Recoverability of assets to be held and used is measured by a comparisonof the carrying amount of an asset to estimated undiscounted future cash flowsexpected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cashflows, an impairment charge is recognized as the amount by which the carryingamount of the asset exceeds the fair value of the asset.  No impairments were recorded during thethree months ended March 31, 2007 or 2006.

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

***(i)***                                    DerivativeInstruments and Hedging Activities

TheCompany uses derivative financial instruments to achieve a more predictablecash flow from its oil and gas production by reducing its exposure to pricefluctuations.  As of March 31, 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 Company accountsfor its derivatives at fair value as an asset or liability and the change inthe 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.

The accounting for changes in thefair value of a derivative instrument depends on the intended use of thederivative and the resulting designation, which is established at the inceptionof a derivative.  SFAS 133 requiresthat a company formally document, at the inception of a hedge, the hedgingrelationship and the entity’s risk management objective and strategy forundertaking the hedge, including identification of the hedging instrument, thehedged item or transaction, the nature of the risk being hedged, the methodthat will be used to assess effectiveness and the method that will be used tomeasure hedge ineffectiveness of derivative instruments that receive hedgeaccounting treatment.  None of theCompany’s commodity or interest rate derivatives are designated as hedges andtherefore the change in the fair value of the derivatives is included in thecondensed consolidated statements of operations.  See Note 11 for discussion related toderivative financial instruments.

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***(j)***                                    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 granted unit grants, unit options, unit warrants, restricted units,and phantom units to employees, non-employee directors and consultants.  The unit options and restricted units vestratably over one to three years from the grant date of the award, unless othercontractual arrangements are made.  Thecontractual life of unit options is ten years. The terms of unit warrants issued to consultants are detailed inNote 13.  See Note 13 also fordetails regarding unit-based compensation granted during the three months endedMarch 31, 2007.

The Company accounts for unit-basedcompensation under the provisions of SFAS No. 123 (revised 2004),*“Share Based Payment”* (“SFAS 123R”).  SFAS 123R requires the recognition ofcompensation expense, over the requisite service period, in an amount equal tothe fair value of unit-based payments granted.

***(k)***                                 RevenueDistribution

Revenuedistribution on the condensed consolidated balance sheets of $1.6 million and$1.8 million represents amounts owed to working interest and royalty interestowners as of March 31, 2007 and December 31, 2006, respectively.

***(l)***                                    OfferingCosts

AtDecember 31, 2006, the line item reported as “other current assets” on thecondensed consolidated balance sheets, includes approximately $56,000 of costsincurred in connection with a private placement in February 2007 (seeNote 4).  These were reclassified tounitholders’ capital upon receipt of the proceeds during the three months endedMarch 31, 2007.

***(m)***                              DeferredFinancing Fees

TheCompany incurred legal and bank fees related to the issuance of debt (see Note 7).  The financing fees incurred for the threemonths ended March 31, 2007 and 2006 were $1.6 million and zero,respectively.  These debt issuance costsare amortized over the life of the debt agreement.  For the three months ended March 31,2007 and 2006, amortization expense of $0.2 million and $0.2 million,respectively, is included in interest expense. Deferred financing fees of approximately $0.5 million and $0.4 millionwere written-off in connection with refinancings during the three months endedMarch 31, 2007 and 2006, respectively.

***(n)***                                 FairValue of Financial Instruments

Thecarrying values of the Company’s receivables, payables and debt are estimatedto be substantially the same as their fair values at March 31, 2007 andDecember 31, 2006.

***(o)***                                 OperatingFee

TheCompany is paid a monthly operating fee for each well it operates for outsideowners.  The fee covers monthly operatingand accounting costs, insurance, and other recurring costs.  As the operating fee is a reimbursement forcosts incurred on behalf of third parties, the portion of the fee that exceedsthe reimbursement of operating costs has been netted against general andadministrative expenses.  For the threemonths ended March 31, 2007 and 2006, the operating fees netted against generaland administrative expenses were approximately $0.1 million and $0.3 million,respectively.

***(p)***                                 IncomeTaxes

TheCompany is a limited liability company treated as a partnership for federal andstate income tax purposes with all income tax liabilities and/or benefits ofthe Company being passed through to the 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.

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Certain of the Company’s subsidiariesare Subchapter C-corporations subject to corporate income taxes, which areaccounted for under the provisions of SFAS No. 109 *“Accounting for Income Taxes”* (“SFAS 109”), which usesthe asset and liability method.  Deferredtax assets and liabilities are recognized for the future tax consequencesattributable to differences between the financial statement carrying amounts ofexisting assets and liabilities and their respective tax basis and operatingloss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax ratesexpected to apply to taxable income in the years in which those temporarydifferences are expected to be recovered or settled.  The effect on deferred tax assets andliabilities of a change in tax rates is recognized in income in the period thatincludes the enactment date.  At March 31,2007, deferred tax liabilities of approximately $0.7 million are recorded onthe condensed consolidated balance sheets and deferred tax assets of $2.5million, net of a valuation allowance of $1.9 million are also recorded.  At December 31, 2006, deferred taxliabilities of approximately $0.7 million are recorded on the condensedconsolidated balance sheets and deferred tax assets of $6.3 million, net of avaluation allowance of $2.3 million are also recorded.

The Company adopted FinancialInterpretation No. 48, *“Accounting forUncertainty in Income Taxes — an interpretation of FASB Statement No. 109”*(“FIN 48”) on January 1, 2007.  FIN48 requires that the Company recognize only the impact of income tax positionsthat, based on their merits, are more likely than not to be sustained uponaudit by a taxing authority.  It also requiresexpanded financial statement disclosure of such positions.

In evaluating its current taxpositions in order to identify any material uncertain tax positions, theCompany developed a policy in identifying uncertain tax positions thatconsiders support for each tax position, industry standards, tax returndisclosures and schedules and the significance of each position.

As of January 1, 2007, the dateof adoption of FIN 48, the Company had no material uncertain taxpositions.  The Company does not currentlyanticipate that any significant uncertain tax positions will be recorded duringthe next 12 months.

***(q)***                                 RevenueRecognition

Sales ofoil, gas and NGL are recognized when produced quantities have been delivered toa custody transfer point, persuasive evidence of a sales arrangement exists,the rights and responsibility of ownership pass to the purchaser upon delivery,collection of revenue from the sale is reasonably assured, and the sales priceis fixed or determinable.  Oil, gas andNGL are sold by the Company on a monthly basis. Virtually all of the Company’s contracts’ pricing provisions are tied toa market index, with certain adjustments based on, among other factors, whethera well delivers to a gathering or transmission line, quality of producedcommodity and prevailing supply and demand conditions, so that the price of theoil, gas and NGL fluctuate to remain competitive with other availablesuppliers.

Gas imbalances occur when the Companysells more or less than its entitled ownership percentage of total gasproduction.  Any amount received inexcess of the Company’s share is treated as a liability.  If the Company receives less than itsentitled share, the underproduction is recorded as a receivable.  The Company did not have any significant gasimbalance positions at March 31, 2007 or December 31, 2006.

Natural gas marketing is recorded onthe gross accounting method because the Company takes title to the gas itpurchases from the various producers and bears the risks and enjoys thebenefits of that ownership.  Natural gasmarketing revenues and natural gas marketing expenses, titled as such, arereported on the condensed consolidated statements of operations for the threemonths ended March 31, 2007 and 2006.

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

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

***(r)***                                   ProductionTaxes

Oil, gasand NGL revenues are presented on a gross basis on the condensed consolidatedstatements of operations.  Productiontaxes are included in operating expenses on the condensed consolidatedstatements of operations and were approximately $1.5 million and $0.9million for the three months ended March 31, 2007 and 2006, respectively.

**(3)           Acquisitionsand Dispositions**

On February 1, 2007,effective January 1, 2007, the Company completed the acquisition ofcertain oil and gas properties and related assets in the Texas Panhandle fromStallion Energy LLC, acting as general partner for Cavallo Energy, LP, for acontract price of $415.0 million, subject to customary closingadjustments.  The Texas Panhandleacquisition was financed with a combination of a private placement of our units(see Note 4) and borrowings under the Company’s senior secured revolvingcredit facility.

The following tablepresents the preliminary purchase price for the acquisition based onpreliminary estimates of fair value:

|                                    | ** ** | **Texas Panhandle** | ** ** |
|------------------------------------|------------|--------------------------|------------|
| ** **                         | ** ** | **(in thousands)**  | ** ** |
| Cash                               |       | $                        | 407,762    |   |
| Estimated  transaction costs       |       | 3,006                    |       |
| Estimated  closing adjustments     |       | 3,508                    |       |
|                               |       | 414,276                  |       |
| Fair value of  liabilities assumed |       | 1,706                    |       |
| Total purchase  price              |       | $                        | 415,982    |   |

 

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

|                         | ** ** | **Texas Panhandle** | ** ** |
|-------------------------|------------|--------------------------|------------|
| ** **              | ** ** | **(in thousands)**  | ** ** |
| Oil and gas  properties |       | $                        | 415,244    |   |
| Vehicles and  buildings |       | 738                      |       |
|                    |       | $                        | 415,982    |   |

The preliminary purchaseprice allocation is based on independent appraisals, discounted cash flows,quoted market prices and estimates by management.  The most significant assumptions related tothe estimated fair values assigned to proved oil and gas properties.  To estimate the fair values of theseproperties, we prepared estimates of oil, gas and NGL reserves.  We estimated future prices to apply to theestimated reserve quantities acquired, and estimated future operating anddevelopment costs, to arrive at estimates of future net revenues.  For estimated proved reserves, the future netrevenues were discounted using a market-based weighted average 

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cost of capital ratedetermined appropriate at the time of the acquisition.  The market-based weighted average cost ofcapital rate was subjected to additional project-specific risking factors.  There were no unproved properties identifiedwith the Texas Panhandle acquisition.  Asnoted, the purchase price allocation is preliminary; it is subject to finalclosing adjustments and will be finalized within one year of the acquisitiondate.

The following unauditedpro forma financial information presents a summary of Linn’s consolidatedresults of operations for the three months ended March 31, 2007 and 2006,assuming the acquisition of our Texas Panhandle properties had been completedas of January 1, 2006, including adjustments to reflect the allocation ofthe purchase price to the acquired net assets. The pro forma financial information also assumes the Company’s February2007 private placement of units (see Note 4) was completed onJanuary 1, 2006, since the private placement was contingent on the TexasPanhandle acquisition.  In addition, thepro forma financial information assumes that our California acquisitions ofcertain affiliated entities of Blacksand Energy, LLC and certain Mid-Continentassets of the Kaiser-Francis Oil Company were completed as of January 1,2006.  The California and Mid-Continentacquisitions were completed in 2006 and the revenues and expenses are includedin the consolidated results of the Company effective August 1, 2006 and September 1,2006, respectively.  The revenues andexpenses of the Texas Panhandle assets are included in the consolidated resultsof the Company effective February 1, 2007. The pro forma financial information is not necessarily indicative of theresults of operations if the acquisitions had been effective as of these dates.

|                                    | ** ** | **Three Months Ended  March 31,** | ** ** |
|------------------------------------|------------|--------------------------------------------------|------------|
| ** **                         | ** ** | **2007**                                         | ** ** | **2006** | ** ** |
| Total revenues                     |       | $                                                | (13,348    | ) | $ | 97,691 |   |
| Total operating  expenses          |       | $                                                | 39,004     |   | $ | 31,417 |   |
| Net income  (loss)                 |       | $                                                | (66,777    | ) | $ | 53,678 |   |
|                               |       |                                             |       |   |   |
| Net income  (loss) per unit:       |       |                                             |       |   |   |
| Units — basic                 |       | $                                                | (1.33      | ) | $ | 1.33 |   |
| Units — diluted               |       | $                                                | (1.33      | ) | $ | 1.33 |   |
|                               |       |                                             |       |   |   |
| Class C units — basic    |       | $                                                | (1.33      | ) | $ | 1.33 |   |
| Class C  units — diluted |       | $                                                | (1.33      | ) | $ | 1.33 |   |

 

The 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 4). 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, theCompany completed the acquisitions of certain gas properties located in theAppalachian Basin of West Virginia for an aggregate contract price of $39.0million, subject to customary closing adjustments.  In connection with these acquisitions and theTexas Panhandle acquisition, the Company amended its credit facility toincrease the borrowing base from $480.0 million to $725.0 million (seeNote 7).

In February 2007, theCompany paid, to a third-party, fees of $10.0 million and a term net-profitsinterest in conjunction with the Company’s purchase of a net profits interestin certain oil and gas properties in California from Aera Energy LLC.  The $10.0 million is recorded in oil and gasproperties on the Company’s condensed consolidated balance sheets and isdepleted based on units of production. Effective April 1, 2007, the Company assumed operatorship of theproperties and began distributing revenue based on formulas set forth in therespective agreements.

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

**(4)           Unitholders’Capital**

***PrivatePlacements***

In February 2007, the Company entered into aClass C Unit and Unit Purchase Agreement with a group of institutional investors whereby it privately placed7,465,946 Class C units at a price of $25.06 per unit, and 6,650,144 unitsat a price of $26.00 per unit, for aggregate gross proceeds of $360.0 million(the “Class C Private Placement”). Proceeds, net of expenses, were $353.1 million.  The proceeds from the Class C PrivatePlacement were used to finance the Texas Panhandle acquisition and theacquisitions of certain gas properties in West Virginia (see Note 3).

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 Class C PrivatePlacement, the Company agreed to file a registration statement with the SECcovering the units and the units underlying the Class C units.  In accordance with the agreement, theregistration statement must be declared effective by the SEC no later than 165days following the closing.

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 the Class Bprivate placement closing.  The effectivedate deadline was extended under a separate agreement to 210 days.

The Company could berequired to pay purchasers, as liquidated damages, certain amounts as definedin the agreements in the event the registration effectiveness deadlines are notmet.  The potential payments would beapproximately $0.8 million and $0.9 million for the October 2006 and February2007 placements, respectively, for each 30 day period that the registrationdeadlines are not met, up through 90 days. Subsequent to 90 days, the potential payments would increase for each 30day period, up to a maximum of 1.0% of the gross proceeds of eachoffering.  If an accounting changeresulted in units being reclassified as a liability, any payment would be furtherlimited to the units remaining under equity treatment on the financialstatements of the Company.

The Company evaluated itsliability exposure related to the liquidated damages and determined itsprobable payments to be approximately $0.3 million.  As such, the Company recorded a liability forthis amount on its condensed consolidated balance sheets at March 31,2007.  Subsequent changes in the amountof the liability will be recorded in “other income and (expenses)” on thecondensed consolidated statements of operations.  The Company will continue to monitor andassess its exposure in this matter; however, the Company does not currentlyexpect payments under these agreements, if any, to be material to the Company’sfinancial position or results of operations.

***Cancellationof 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.

***InitialPublic Offering***

In the first quarter of 2006, theCompany completed its initial public offering (“IPO”) of 12,450,000 unitsrepresenting limited liability interests in the Company at $21.00 per unit, fornet proceeds, after underwriting discounts of $18.3 million and offeringexpenses of $4.3 million, of $238.8 million, of which $122.0 million was usedto reduce indebtedness, $114.4 million was used to redeem a portion of themembership interests in the Company and units held by certain affiliated andnon-affiliated holders and approximately $2.0 million was used to pay bonusesto certain executive officers of the Company.

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

Aggregatecapitalized costs related to oil and gas production activities with applicableaccumulated depreciation, depletion and amortization are presented below:

|                                                            | ** ** | **March 31,**      | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2007**                | ** ** | **2006**              | ** ** |
| ** **                                                 | ** ** | **(in thousands)** | ** ** |
| Unproved properties                                        |       | $                       | 8,438      |                  | $          | 8,624 |   |
| Proved properties:                                         |       |                    |       |                  |       |
| Leasehold,  equipment and drilling                         |       | 1,164,226               |       | 737,202               |       |
| Gas compression  plant and pipelines                       |       | 80,699                  |       | 20,812                |       |
| Less accumulated  depletion, depreciation and amortization |       | 1,253,363               |       | 766,638               |       |
|                                                       |       | (44,188                 | )          | (33,349               | )          |
| Net capitalized costs                                      |       | $                       | 1,209,175  |                  | $          | 733,289 |   |

 

**(6)           Property and Equipment**

Property andequipment consists of the following:

|                                       | ** ** | **March 31,**      | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2007**                | ** ** | **2006**              | ** ** |
| ** **                            | ** ** | **(in thousands)** | ** ** |
| Land                                  |       | $                       | 320        |                  | $          | 308 |   |
| Buildings and leasehold  improvements |       | 3,190                   |       | 2,759                 |       |
| Vehicles                              |       | 4,144                   |       | 3,097                 |       |
| Aircraft                              |       | 5,890                   |       | 5,890                 |       |
| Drilling equipment                    |       | 10,773                  |       | 8,611                 |       |
| Furniture and equipment               |       | 2,333                   |       | 1,966                 |       |
|                                  |       | 26,650                  |       | 22,631                |       |
| Less accumulated  depreciation        |       | (2,583                  | )          | (1,877                | )          |
|                                  |       | $                       | 24,067     |                  | $          | 20,754 |   |

Depreciation expense forthe three months ended March 31, 2007 and 2006, was approximately $0.7 and$0.2 million, respectively.

**(7)           CreditFacility**

At March 31, 2007,the Company had an $800.0 million senior secured revolving credit facility witha maturity of August 2010, and a borrowing base of $725.0 million (“CreditFacility”).  In February 2007, inconjunction with the Texas Panhandle acquisition and two acquisitions in WestVirginia (see Note 3), the Company amended its Credit Facility, increasingthe borrowing base from $480.0 million to $725.0 million.  In connection with this amendment, in thefirst quarter of 2007, the Company paid fees of approximately $1.6 million,which will be amortized over the remaining term of the Credit Facility, andwrote-off deferred financing fees of approximately $0.5 million.

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The borrowing baseunder the Credit Facility will be redetermined semi-annually by the lenders intheir sole discretion, based on, among other things, reserve reports asprepared by reserve engineers taking into account the oil and gas prices atsuch time.  Our obligations under theCredit Facility are secured by mortgages on our oil and gas properties as wellas a pledge of all ownership interests in our 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 the Credit Facility is determined by reference to LIBOR plus an applicablemargin between 1.00% and 1.75% per annum; or a domestic bank rate plus anapplicable margin between 0.00% and 0.25% per annum.  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.  TheCredit Facility 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.

As of March 31, 2007and December 31, 2006, the Credit Facility consisted of the following:

|                         | ** ** | **March 31,**      | ** ** | **December 31,** | ** ** |
|-------------------------|------------|-------------------------|------------|-----------------------|------------|
| ** **              | ** ** | **2007**                | ** ** | **2006**              | ** ** |
| ** **              | ** ** | **(in thousands)** | ** ** |
| Total (1)               |       | $                       | 596,750    |                  | $          | 425,750 |   |
| Less current maturities |       | ——            |       | ——          |       |
|                    |       | $                       | 596,750    |                  | $          | 425,750 |   |

----

(1)          Variable rate of 6.875%and 7.125% at March 31, 2007 and December 31, 2006, respectively.

At March 31, 2007,the Company also had $5.0 million outstanding letters of credit, which reduceits borrowing availability under the Credit Facility.  At March 31, 2007, available borrowingunder the Credit Facility was $123.2 million.

Total accrued interest onthe Credit Facility was approximately $2.4 million and $2.1 million atMarch 31, 2007 and December 31, 2006, respectively.

18

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**(8)           Long-termNotes Payable**

The Company hasthe following long-term notes payable outstanding:

|                                                                                                                                                                                                                                                                                                                                                                                            | ** ** | **March 31,  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.                                                                                                                                                                                      |       | $                        | 369        |                        | $          | 372 |   |
| Various notes for the purchase  of vehicles and equipment, payable in monthly installments totaling  approximately $88 and $88, as of March 31, 2007 and December 31,  2006, respectively, including interest. The interest rates range from  3.9%-9.11%. The notes are secured by the vehicles and equipment purchased and  expire at various dates from 2007 through 2011. (1) |       | 2,752                    |       | 2,989                       |       |
|                                                                                                                                                                                                                                                                                                                                                                                       |       | 3,121                    |       | 3,361                       |       |
| Less current maturities                                                                                                                                                                                                                                                                                                                                                                    |       | (871                     | )          | (874                        | )          |
|                                                                                                                                                                                                                                                                                                                                                                                       |       | $                        | 2,250      |                        | $          | 2,487 |   |

----

(1)                At March 31,2007 and December 31, 2006, includes approximately $16 and $1.0 million,respectively, of notes payable on which interest was imputed at 7.0%.

As of March 31,2007, maturities on the aforementioned long-term notes payable were as follows:

|            | ** ** | **(in thousands)** | ** ** |
|------------|------------|-------------------------|------------|
| 2007       |       | $                       | 634        |   |
| 2008       |       | 870                     |       |
| 2009       |       | 641                     |       |
| 2010       |       | 446                     |       |
| 2011       |       | 229                     |       |
| Thereafter |       | 301                     |       |
|       |       | $                       | 3,121      |   |

 

**(9)           Business and Credit Concentrations**

***Cash***

The Company maintains its cash in bank depositaccounts, which, at times, may exceed federally insured amounts.  The Company has not experienced any losses insuch accounts.  The Company believes itis not exposed to any significant credit risk on its cash.

***Revenue and TradeReceivables***

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 performs ongoing credit evaluations of its customers andgenerally does not require collateral.

19

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A majority of theCompany’s largest customers are oil and gas producers, suppliers andoperators.  For the three months endedMarch 31, 2007, the Company’s three largest customers representedapproximately 34%, 19% and 12%, respectively, of the Company’s sales.  The Company’s two largest customersrepresented approximately 70% and 10%, of the Company’s sales for the threemonths ended March 31, 2006, respectively.

At March 31, 2007,three customers’ trade accounts receivable from oil, gas and NGL salesaccounted for more than 10% of the Company’s total trade accountsreceivable.  At March 31, 2007,trade accounts receivable from these customers represented approximately 38%,17% and 16% of the Company’s receivables. At December 31, 2006, three customers’ trade accounts receivablefrom oil and gas sales accounted for more than 10% of the Company’s total tradeaccounts receivable.  As ofDecember 31, 2006, trade accounts receivable from our three largestcustomers represented approximately 41%, 22% and 16% of the Company’sreceivables.

**(10)         Commitmentsand Contingencies**

The Company would beexposed to oil, gas and NGL price fluctuations on underlying sale contractsshould the 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 months ended March 31, 2007 or 2006.

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.

**(11)         Oiland Gas Derivatives**

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

Settledderivatives on gas production for the three months ended March 31,2007, included a volume of 4,695 MMBtu at an average contract price of$8.42.  Settledderivatives on oil and NGL production for the three months endedMarch 31, 2007 included a volume of 392MBbls at an average contract price of $69.73. The gas derivatives are settled based upon the closing NYMEX futureprice of gas on the settlement date, which occurs on the third day precedingthe production month.  The oiltransactions are settled based upon the average month’s daily NYMEX price oflight oil and settlement occurs on the final day of the production month.

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The following tables summarize open positions as of March 31, 2007and represents, as of such date, our derivatives in place throughDecember 31, 2011, on annual production volumes:
| ** **               | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** |
|--------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas Positions**        |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price Swaps:       |       |           | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume  (MMBtu)   |       | 5,908          |       | 10,264         |       | 10,405         |       | 8,520          |       | 7,800          |       |
| Average Price  ($/MMBtu) |       | $              | 8.74       |           | $          | 8.37           |       | $              | 7.73       |           | $          | 7.20 |   | $ | 7.20 |   |
| Puts:                    |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMBtu)   |       | 6,446          |       | 7,053          |       | 6,960          |       | 6,960          |       | 6,960          |       |
| Average Price  ($/MMBtu) |       | $              | 8.18       |           | $          | 8.07           |       | $              | 7.50       |           | $          | 7.50 |   | $ | 7.50 |   |
| Total:                   |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMBtu)   |       | 12,354         |       | 17,317         |       | 17,365         |       | 15,480         |       | 14,760         |       |
| Average Price ($/MMBtu)  |       | $              | 8.45       |           | $          | 8.25           |       | $              | 7.64       |           | $          | 7.34 |   | $ | 7.34 |   |

 
| ** **              | ** ** | **Year  2007** | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** |
|-------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Oil Positions**       |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price Swaps:      |       |           | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged Volume  (MMBbls) |       | 375            |       | 560            |       | 580            |       | 550            |       | 525            |       |
| Average Price  ($/Bbl)  |       | $              | 75.83      |           | $          | 74.31          |       | $              | 73.87      |           | $          | 74.54 |   | $ | 61.58 |   |
| Puts:                   |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMBbls) |       | 1,125          |       | 1,550          |       | 1,550          |       | 1,700          |       | 1,750          |       |
| Average Price  ($/Bbl)  |       | $              | 66.33      |           | $          | 66.29          |       | $              | 66.29      |           | $          | 66.18 |   | $ | 65.00 |   |
| Total:                  |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMBbls) |       | 1,500          |       | 2,110          |       | 2,130          |       | 2,250          |       | 2,275          |       |
| Average Price ($/Bbl)   |       | $              | 68.71      |           | $          | 68.42          |       | $              | 68.35      |           | $          | 68.22 |   | $ | 64.21 |   |

 

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

The followingtable presents the outstanding notional amounts and maximum number of monthsoutstanding of our derivatives:

|                                                     | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **2007**           | ** ** | **2006**              | ** ** |
| Outstanding notional  amounts of gas hedges (MMBtu) |       | 77,276             |       | 31,503                |       |
| Maximum number of  months gas hedges outstanding    |       | 57                 |       | 35                    |       |
| Outstanding notional  amounts of oil hedges (MBbls) |       | 10,265             |       | 8,700                 |       |
| Maximum number of months oil hedges outstanding     |       | 58                 |       | 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.

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

Basic earnings perunit is 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.  At March 31, 2007, the Company had twoclasses of units outstanding:  (i) unitsrepresenting limited liability company interests (“units”) listed on The NASDAQGlobal Market under the symbol “LINE” and (ii) Class C units.  See Note 4 for details regarding theClass C units.

In accordance with SFASNo. 128, *“Earnings Per Share”* (“SFAS 128”),dual presentation of basic and diluted earnings per unit has been presented inthe condensed consolidated statements of operations for each class of unitsissued and outstanding at March 31, 2007, units and Class Cunits.  Net income per unit is allocatedto the units and the Class C units on an equal basis.  Since the Class C units were convertedto units in April 2007, they share equally in the May 2007 distributions andall future distributions.  The Companymade no distributions to Class C unitholders during the period theClass C units were outstanding.

The followingreconciliation presents the impact on the unit amounts of potential commonunits and the earnings per unit amounts:

|                                                                 | ** ** | **Three Months Ended  March 31,**                 | ** ** |
|-----------------------------------------------------------------|------------|------------------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2007**                                                         | ** ** | **2006** | ** ** |
| ** **                                                      | ** ** | **(in thousands, except per  unit amounts)** | ** ** |
| Net income (loss)                                               |       | $                                                                | (67,847    | ) | $ | 21,977 |   |
| ** **                                                      |       |                                                             |       |   |   |
| **Weighted average units  outstanding:**                        |       |                                                             |       |   |   |
| Basic units  outstanding                                        |       | 45,456                                                           |       | 26,273 |   |
| Dilutive effect  of unit equivalents and Class C units (1) |       | —                                                           |       | — |   |
| Diluted units  outstanding                                      |       | 45,456                                                           |       | 26,273 |   |
|                                                            |       |                                                             |       |   |   |
| **Weighted average Class C  units outstanding:**           |       |                                                             |       |   |   |
| Basic  Class C units outstanding                           |       | 4,894                                                            |       | — |   |
| Dilutive effect  of unit equivalents                            |       | —                                                           |       | — |   |
| Diluted  Class C units outstanding                         |       | 4,894                                                            |       | — |   |
|                                                            |       |                                                             |       |   |   |
| **Net income (loss) per unit:**                                 |       |                                                             |       |   |   |
| Units — basic                                              |       | $                                                                | (1.35      | ) | $ | 0.84 |   |
| Units — diluted                                            |       | $                                                                | (1.35      | ) | $ | 0.84 |   |
|                                                            |       |                                                             |       |   |   |
| Class C  units — basic                                |       | $                                                                | (1.35      | ) | $ | — |   |
| Class C units —  diluted                              |       | $                                                                | (1.35      | ) | $ | — |   |

----

(1)          Excludes the effect ofaverage anti-dilutive common stock equivalents related to out-of-the-money unitoptions, restricted units and unit warrants of 451,252 and 188,257 for thethree months ended March 31, 2007 and 2006, respectively.  In addition, excludes the effect of averageanti-dilutive Class C units for the three months ended March 31, 2007.  All equivalent units are anti-dilutive forthe three months ended March 31, 2007 as the Company reported a net loss fromoperations.

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

***EmployeeGrants***

During the three months ended March 31, 2007, theCompany granted an aggregate 400,500 restricted units to employees as part ofits annual review of employee compensation and 50,000 restricted units to a newofficer of the Company with an aggregate fair value of approximately $13.0million and $1.7 million, respectively. In addition, during the three months ended March 31, 2007, theCompany granted 50,000 unit options to a new officer of the Company with a fairvalue of approximately $0.3 million. These restricted units and options vest ratably over three years.

For the three monthsended March 31, 2007 and 2006, the Company recorded unit-based compensationexpense of approximately $3.3 million and $5.7 million, respectively, as acharge against income before income taxes and it is included in general andadministrative expenses on the condensed consolidated statements of operations.

Subsequent toMarch 31, 2007, the Company issued 30,000 restricted units and 30,000 unitoptions to a new officer of the Company.

***Non-EmployeeGrants***

In February 2007, the Company granted an aggregate150,000 unit warrants to certain individuals in connection with a transition servicesagreement entered into with the Texas Panhandle acquisition (seeNote 3).  The unit warrants have anexercise price of $25.50 per unit warrant, may be exercised in whole or in-parton or after December 13, 2007, and expire ten years from issuance.  In accordance with SFAS 123R, the Companycomputed the fair value of the unit warrants using the Black-Scholesmodel.  At March 31, 2007, theaggregate fair value of the unit warrants was approximately $1.2 million andthe expense will be recognized over the five month term of the agreement, orthrough June 30, 2007.  For thethree months ended March 31, 2007, the Company recorded approximately $0.5million as a charge against income before income taxes and it is included ingeneral and administrative expenses on the condensed consolidated statements ofoperations.  In accordance with EmergingIssues Task Force Issue No. 96-18 *“Accounting for EquityInstruments That Are Issued to Other Than Employees for Acquiring, or inConjunction With Selling, Goods or Services,”*the fair value of thewarrants was recomputed at March 31, 2007, and will be recomputed onJune 30, 2007.

**(14)         RelatedParty Transactions**

During the three monthsended March 31, 2006, the Company made payments of approximately $61,000to 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 reimbursementsended.  Simultaneous with thistransaction, the senior executive was able to fully liquidate the investment inthe aircraft owned by his company.

**(15)         SubsequentEvent**

In May 2007, the Companyentered into a definitive purchase agreement to acquire certain oil and gasproperties in the Texas Panhandle for $90.5 million, subject to customaryclosing adjustments.  The Company anticipatesthe acquisition will close on or before June 30, 2007 and will be financed withborrowings under the Company’s existing Credit Facility.

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**Item2.****                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations**

**Executive Summary**

We are an independent oil and gas company focused onthe development and acquisition of long-lived properties in the UnitedStates.  Our goal is to provide stabilityand growth in distributions to our unitholders through continued successful drilling, acquisitions, increasing production ofexisting wells and pursuing operational and administrativeefficiencies.  Our properties and our oil and gas reserves are currently located infour core areas:

·                  AppalachianBasin, which includes West Virginia, Pennsylvania and Virginia;

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

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

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

From inception throughMarch 31, 2007, we have completed 17 acquisitions of oil and gasproperties and related gathering and pipeline assets for an aggregate purchaseprice of approximately $1.1 billion, with total proved reserves of approximately 772.0 Bcfe, or an acquisition cost ofapproximately $1.44 per Mcfe.

In February 2007, the Company completed theacquisition of certain oil and gas properties and related assets in the TexasPanhandle for a contract price of $415.0 million, subject to customary closingadjustments (see Note 3 in Notes to Condensed Consolidated FinancialStatements for additional details).  Inaddition, in January 2007, the Company completed two acquisitions of certaingas properties located in the Appalachian Basin of West Virginia for anaggregate contract price of $39.0 million, subject to customary closingadjustments.  In connection with theseacquisitions, the Company amended its credit facility to increase the borrowingbase from $480.0 million to $725.0 million. See “Credit Facility” below for additional details.

Our acquisitions were financed with a combination ofprivate placements of our units, proceeds from bank borrowings and cash flowfrom operations.  Our activities arefocused on evaluating and developing our asset base, increasing our acreagepositions and evaluating potential acquisitions.  Because of our rapid growth throughacquisitions and development of our properties, our historical results ofoperations and period-to-period comparisons of these results and certainfinancial data may not be meaningful or indicative of future results.

We utilize the successful effortsmethod of accounting for our oil and gas properties.  Leasehold costs are capitalized whenincurred.  Unproved properties areassessed periodically within specific geographic areas and impairments are chargedto expense.  Geological and geophysicalexpenses and delay rentals are charged to expense as incurred.  Developmental drilling costs are capitalizedand costs for exploratory wells are charged to expense if the well isdetermined to be unsuccessful.  We carrythe costs of an exploratory well as an asset if the well finds a sufficientquantity of reserves to justify its capitalization as a producing well as longas we are making sufficient progress assessing the reserves and the economicand operating viability of the project.

Higher oil and gas prices have led to higher demandfor drilling rigs, operating personnel and field supplies and services and havecaused increases in the costs of those goods and services.  The Company performs certain activities inconnection with its drilling of oil and gas wells, which includes preparing andclearing well sites, providing drilling engineers, roustabouts and otherpersonnel necessary for drilling.  During 2006, the Company took delivery of itsfirst two drilling rigs, with an additional rig delivered on March 30,2007, which will reduce reliance on contract rigs.  Given the inherent volatility of oil and gasprices, which are influenced by manyfactors beyond our control, we plan our activities and budget based onconservative sales price assumptions, which are lower than the average salesprices ultimately realized.  We focus ourefforts on increasing oil and gas reserves and production while controllingcosts at a level that is appropriate for long-term operations.  Our future cash flow from operations isdependent on our ability to manage our overall cost structure.

We face the challenge of natural productiondeclines.  As initial reservoir pressuresare depleted, oil, gas or NGL production from a given well decreases.  We attempt to overcome this natural declineby drilling to find additional reserves and acquiring more reserves than weproduce.  Our future growth will dependon our ability to continue to add reserves in excess of production.  We will maintain our focus on adding reservesthrough drilling and acquisitions as well as managing the costs necessary toproduce such reserves.  Our ability toadd reserves through 

24

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drilling is dependent on our capital resources and canbe limited by many factors, including our ability to timely obtain drillingpermits and regulatory approvals.

***Operations***

Our revenues are highly sensitive to changes in oil,gas and NGL prices and levels of production. As of March 31, 2007, we have hedged a significant portion of ourexpected production through 2011 using oil and gas derivatives, which allows usto mitigate, but not eliminate, commodity price risk.  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.  We continuously conduct financial sensitivityanalyses to assess the effect of changes in pricing and production.  These analyses allow us to determine howchanges in oil, gas and NGL prices will affect the ability to drill additionalwells and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact suchchanges in oil and gas prices may have on the value of our proved reserves andtheir impact, if any, on any redetermination of the borrowing base under ourcredit facility.

Our revenue, cash flow from operations and futuregrowth depend substantially on factors beyond our control, such as economic,political and regulatory developments and competition from otherproducers.  Oil, gas and NGL priceshistorically have been volatile and may fluctuate widely in the future.  Sustained periods of low prices for oil, gasor NGL could materially and adversely affect our financial position, ourresults of operations, the quantities of productive reserves that we caneconomically produce and our access to capital.

***Production and Operating Costs Reporting***

We strive to increase our production levels tomaximize our revenue and cash available for distribution.  Additionally, we continuously monitor ouroperations to ensure that we are incurring operating costs at the lowestpossible level.  Accordingly, we analyzeour production and operating costs per well to determine if any wells should beshut in or sold.

***Land and Lease Tracking System***

As a significant amount of our growth is dependent ondrilling new wells, we continuously monitor our lease agreements and ourdrilling locations to avoid delays.  Ourmonitoring system matches our lease agreements to existing wells and sites forfuture development, allowing management to make real time decisions on whichacreage to develop and at what point in time. We continually seek to acquire new lease positions to increase potentialdrilling locations.

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**Results of Operations - Three MonthsEnded March 31, 2007 Compared to Three Months Ended March 31, 2006**
| ** **                                    | ** ** | **Three Months Ended  March 31,** | ** ** | ** ** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------------|------------|------------|------------|
| ** **                                    | ** ** | **2007**                                         | ** ** | **2006**   | ** ** | **Variance** | ** ** |
| ** **                                    | ** ** | **(in thousands)**                          | ** ** |
| **Revenues:**                                 |       |                                             |       |       |       |   |   |
| Gas sales                                     |       | $                                                | 23,360     |       | $          | 16,007 |   | $ | 7,353 |   |
| Oil sales                                     |       | 9,758                                            |       | 368        |       | 9,390 |   |
| Natural gas liquid sales                      |       | 6,086                                            |       | —     |       | 6,086 |   |
| Total oil, gas and natural gas liquid sales   |       | 39,204                                           |       | 16,375     |       | 22,829 |   |
| Gain (loss) on oil and gas derivatives        |       | (60,441                                          | )          | 24,246     |       | (84,687 | ) |
| Natural gas marketing revenues                |       | 1,778                                            |       | 1,218      |       | 560 |   |
| Other revenues                                |       | 2,090                                            |       | 289        |       | 1,801 |   |
| Total revenues                                |       | $                                                | (17,369    | )          | $          | 42,128 |   | $ | (59,497 | ) |
| **Expenses:**                                 |       |                                             |       |       |       |   |   |
| Operating expenses                            |       | $                                                | 12,456     |       | $          | 2,994 |   | $ | 9,462 |   |
| Natural gas marketing expenses                |       | 1,347                                            |       | 983        |       | 364 |   |
| General and administrative expenses           |       | 10,621                                           |       | 9,470      |       | 1,151 |   |
| Depreciation, depletion and amortization      |       | 11,851                                           |       | 3,700      |       | 8,151 |   |
| Total expenses                                |       | $                                                | 36,275     |       | $          | 17,147 |   | $ | 19,128 |   |
| **Other  income and (expenses):**             |       |                                             |       |       |       |   |   |
| Interest  expense, net of amounts capitalized |       | $                                                | (9,913     | )          | $          | (2,639 | ) | $ | (7,274 | ) |

 
| ** **                                                 | ** ** | **Three Months Ended  March 31,** | ** ** | **Percentage  Increase** | ** ** |
|------------------------------------------------------------|------------|--------------------------------------------------|------------|--------------------------|------------|
| ** **                                                 | ** ** | **2007**                                         | ** ** | **2006**                 | ** ** | **(Decrease)** | ** ** |
| **Production:**                                            |       |                                             |       |                     |       |   |   |
| Gas production (MMcf)                                      |       | 3,374                                            |       | 1,798                    |       | 87.7 | % |
| Oil production (MBbls)                                     |       | 215                                              |       | 6                        |       | 3,483.3 | % |
| Natural gas liquid production (MBbls)                      |       | 127                                              |       | —                   |       | — |   |
| Total production (MMcfe)                                   |       | 5,424                                            |       | 1,836                    |       | 195.4 | % |
| Average daily production (Mcfe/d)                          |       | 60,267                                           |       | 20,400                   |       | 195.4 | % |
| ** **                                                 |       |                                             |       |                     |       |   |   |
| **Weighted  average realized prices: (1)**                 |       |                                             |       |                     |       |   |   |
| Gas (Mcf)                                                  |       | $                                                | 8.40       |                     | $          | 9.74 |   | (13.8 | )% |
| Oil (Bbl) (2)                                              |       | $                                                | 64.47      |                     | $          | 58.46 |   | 10.3 | % |
| Natural gas liquid (Bbl)                                   |       | $                                                | 47.92      |                     | $          | — |   | — |   |
| Total (Mcfe)                                               |       | $                                                | 8.90       |                     | $          | 9.72 |   | (8.4 | )% |
| ** **                                                 |       |                                             |       |                     |       |   |   |
| **Average  unit costs per Mcfe of production (non-GAAP):** |       |                                             |       |                     |       |   |   |
| Operating expenses                                         |       | $                                                | 2.30       |                     | $          | 1.63 |   | 41.1 | % |
| General and administrative expenses (3)                    |       | $                                                | 1.27       |                     | $          | 0.97 |   | 30.9 | % |
| Depreciation,  depletion and amortization                  |       | $                                                | 2.18       |                     | $          | 2.02 |   | 7.9 | % |

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(1)          Includes the effect of realized gains of $9.1 million and$3.3 million on oil and gas derivatives for the three months endedMarch 31, 2007 and 2006, respectively.

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

(3)          This is a non-GAAP performance measure used by ourmanagement and is a quantitative measure used in the oil and gas industry.  The measure for the three months endedMarch 31, 2007 and 2006 excludes approximately $3.7 million and $5.7million, respectively, of unit-based compensation expense and unit warrantexpense.  The measure for the threemonths ended March 31, 2006 excludes approximately $2.0 million of bonusespaid to certain executive officers in connection with our initial publicoffering.  General and administrativeexpenses including these amounts was $1.96 per Mcfe and $5.16 per Mcfe for thethree months ended March 31, 2007 and 2006, respectively.

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***Revenue***

Gas, oil and NGL sales increased to approximately $39.2 million forthe three months ended March 31, 2007, from $16.4 million for the threemonths ended March 31, 2006.

The increase in revenue from gas, oil and NGL sales was primarilyattributable to increased production. Total production increased to 5,424 MMcfe during the three months endedMarch 31, 2007, from 1,836 MMcfe during the three months endedMarch 31, 2006.  Gas productionincreased to 3,374 MMcf during the three months ended March 31, 2007, from1,798 MMcf during the three months ended March 31, 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 41 wells during the three months ended March 31, 2007,compared to 29 wells during the three months ended March 31, 2006.  Oil production increased to 215 MBbls duringthe three months ended March 31, 2007, from 6 MBbls during the during thethree months ended March 31, 2006, due to the California and TexasPanhandle acquisitions in August 2006 and February 2007, respectively.  The acquisition in the Texas Panhandle alsoincreased NGL production to 127 MBbls during the three months endedMarch 31, 2007, from zero during the comparative period of the prior year.

***Hedging Activities***

During the three months endedMarch 31, 2007, we entered into commodity pricing derivative contracts forapproximately 115% of our gas production and 110% of our oil production, whichresulted in revenues that were $9.1 million greater than we would have achievedat unhedged prices.  The calculation ofpercentage production hedged for the three months ended March 31, 2007includes an adjustment to reflect the production attributable to the TexasPanhandle acquisition, which was hedged, but was not included in the Company’sreported production; instead, it was reflected as a purchase price adjustment(see Note 3 in Notes to Condensed Consolidated Financial Statements).  During the three months ended March 31,2006, we entered into commodity pricing derivative contracts for approximately100% of our oil and gas production, which resulted in revenues that were $3.3million greater than we would have achieved at unhedged prices.  Unrealized losses on derivatives in theamount of $69.5 million for the three months ended March 31, 2007 andunrealized gains of $21.0 million for the three months ended March 31,2006, were also recorded.  Unrealized gainsand losses result from changes in market valuations of oil and gas derivativesas future oil and gas price expectations change compared to the contract priceon the derivative.  During the quarter, short-term oil and gasprices increased, which reduced the market value of the derivatives. Such market value adjustment, if realized in the future, would be offset byhigher actual oil and gas prices for our production.

***Expenses***

Operating expenses include leaseoperating expenses, labor, field office expenses, vehicle expenses,supervision, transportation, minor maintenance, tools and supplies, severanceand ad valorem taxes and other customary charges.  Severance taxes are a function of volumes andrevenues generated from production.  Advalorem taxes vary by state/county and are based on the value of ourreserves.  We assess our operatingexpenses by monitoring the expenses in relation to the amount of production andthe number of wells operated.  Operatingexpenses increased to $12.5 million for the three months ended March 31,2007, from $3.0 million for the three months ended March 31, 2006, due tothe increase in the number of producing wells as a result of the acquisitionscompleted in both the first quarter of 2007 and in 2006 and the drilling of 41wells in the three months ended March 31, 2007, and 400 wells frominception through March 31, 2007.

In addition, our averageoperating expenses per equivalent unit of production increased to $2.30 for thethree months ended March 31, 2007, compared to $1.63 for the three months endedMarch 31, 2006, due to the changing mix of production from third quarter 2006to include oil and NGL production which has higher operating costs than our gaswells.  Finally, we have incurred costsin 2007 for workover and maintenance of our wells to enhance future productionand/or offset 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.  Wemonitor general and administrative expenses in relation to the amount ofproduction and the number of wells operated. General and administrative expenses increased to approximately $10.6million for the three months ended March 31, 2007, from $9.5 

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million for the three monthsended March 31, 2006.  Theincrease in general and administrative expenses was primarily due toapproximately $3.6 million of costs incurred to support our rapid growththrough acquisitions and position the Company for future growth, which includeincreasing our staffing levels to manage the 400 wells drilled and 4,246 wellsacquired from inception in 2003 through March 31, 2007, relocating theCompany headquarters from Pittsburgh, Pennsylvania to Houston, Texas,recruiting key management team members and performing the functions associatedwith being a public company.  The lattercosts include preparation of public partnership tax reporting, audit fees,proxy and printing costs and other professional fees.  In addition, acquisition costs that are noteligible for capitalization, including internal and indirect costs forcompleted acquisitions, as well as direct costs associated with acquisitionefforts that have not reached fruition, contributed to the increase.  The Company also incurred unit warrantexpense of approximately $0.5 million in connection with the issuance of unitwarrants pursuant to a transition services agreement associated with the TexasPanhandle properties (see Note 13 in Notes to Condensed ConsolidatedFinancial Statements).  The increase ingeneral and administrative expenses was partially offset by decreased employeeunit-based compensation expense, which was $3.3 million during the three monthsended March 31, 2007, compared to $5.7 million during the comparativequarter of 2006.  General andadministrative expenses are presented net of approximately $0.1 million and$0.3 million during the three months endedMarch 31, 2007 and 2006, respectively, which represent expensereimbursements from other working interest owners.

Depreciation, depletion and amortization increased to approximately $11.9 million for the three monthsended March 31, 2007, from $3.7 million for the three months endedMarch 31, 2006.  Of thisincrease, approximately $4.7 million was as a result of depletion related tothe California and Mid-Continent acquisitions in the third quarter of 2006 andthe Texas Panhandle acquisition in the first quarter of 2007.  In addition, the depletion rate for our oiland gas properties in the Appalachia Basin increased 37.4% in the fourthquarter of 2006, due to a downward revision of our estimated reserves from theprior year primarily attributable to decreases in gas prices.  During the threemonths ended March 31, 2007 and 2006, the Company capitalizedapproximately $1.9 million and $0.3million, respectively, of costs for specific activities related to drilling itswells, which included site preparation, drilling labor, meter installation,pipeline connection and site reclamation. Capitalized drilling costs increased in the three months ended March 31,2007 due to the Company’s purchase and placement of two drilling rigs intoservice during the third quarter of 2006 and one additional drilling rig in thefirst quarter of 2007.  Company personnelalso perform activities using leased equipment, and did so prior to thepurchase of its own rigs.

Interest and financing income (expense) increasedto a net expense of $9.9million forthe three months ended March 31, 2007,compared to a net expense of $2.6millionfor the three months ended March 31,2006, primarily due to increased debt levels associated withacquisitions and drilling.  Cash paymentsfor interest increased to $9.3millionfor the three months ended March 31,2007, compared to $3.3millionfor the three months ended March 31,2006.  Our interest rate swapswere not designated as hedges under SFAS 133, even though they reduce ourexposure to changes in interest rates. Therefore, the changes in fair values of these instruments were recordedas gains of approximately $0.2 million and $0.4 million for the three months ended March 31, 2007 and 2006,respectively.  These amounts are non-cashgains.

Income tax was an expense of approximately $3.7million for the three months ended March 31,2007 compared to an expense of approximately $0.1 million for the three months ended March 31, 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 first quarter of 2007.

**Critical Accounting 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 a result,there exists the likelihood that materially different amounts would be reportedunder different conditions or using different assumptions.

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Asof March 31, 2007, there have been no significant changes with regard tothe critical accounting policies disclosed in the Company’s Annual Report onForm 10-K for the year ended December 31, 2006.  The policies disclosed included theaccounting for oil and gas properties, oil and gas reserve quantities, revenuerecognition, purchase accounting and derivative instruments.

**Liquidity and Capital Resources**

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

***Statements of Cash Flows — Operating Activities***

AtMarch 31, 2007, we had cash and cash equivalents of approximately $1.0million compared to $6.6 million at December 31, 2006.

Cashused by operating activities for the three months ended March 31, 2007 was$37.9 million, compared to cash provided by operating activities of $5.4million for the three months ended March 31, 2006.  The decrease in cash provided by operatingactivities was primarily due to premiums paid for oil and gas derivatives of$53.0 million, since the reported net loss arose predominately from thenon-cash market valuation adjustment at March 31, 2007 for outstanding hedgeinvestments.  Cash provided by operationsfor the three months ended March 31, 2006, resulted primarily from netincome from operations.  See “Results ofOperations” above for details about the increase in components of net income.

Ourcash flow from operations is subject to many variables, the most significant ofwhich is the volatility of oil, gas and NGL prices.  Oil, gas and NGL prices are determinedprimarily by prevailing market conditions, which are dependent on regional andworldwide economic activity, weather and other factors beyond our control.  Our future cash flow from operations willdepend on our ability to maintain and increase production through our drillingprogram and acquisitions, as well as the prices received for our production.  We enter into derivative arrangements toreduce the impact of oil and gas price volatility on our operations.  Currently, we use fixed price swaps and putsto reduce our exposure to the volatility in oil, gas and NGL prices.  See Note 11 in Notes to CondensedConsolidated Financial Statements for details about our derivatives in placethrough December 31, 2011.

***Statements of Cash Flows — Investing Activities***

Cashused in investing activities was $459.9 million for the three months endedMarch 31, 2007, compared to $19.5 million for the three months endedMarch 31, 2006.  The increase incash used in investing activities was primarily due to an increase inacquisition activity during the three months ended March 31, 2007,compared to the prior year.

Thetotal cash used in investing activities for the three months endedMarch 31, 2007 includes $387.7 million for the Texas Panhandleacquisition and $38.5 million the acquisitions of certain gas properties inWest Virginia.  See Note 3 in Notes to CondensedConsolidated Financial Statements for additional details.  Other acquisitions, including acquisitions ofadditional working interests in our current wells, were approximately $14.2million and property, plant and equipment purchases accounted for $3.3million.  The total for the three monthsended March 31, 2007 also includes $10.4 million for the drilling anddevelopment of oil and gas properties.

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

Cashprovided by financing activities was $492.2 million for the three months endedMarch 31, 2007, compared to $18.9 million for the three months endedMarch 31, 2006.

The Company recordedgross proceeds of $360.0 million from a private placement of its units duringthe three months ended March 31, 2007 (see “Private Placement —Class C Units” below).  Theproceeds, net of expenses of approximately $6.9million, were used to finance theTexas Panhandle acquisition and the acquisitions of certain gasproperties in West Virginia.  Totalproceeds from borrowings under the Credit Facility during the three months ended March 31, 2007 were$171.0 million.

In January 2007, the Company’s Board of Directorsdeclared a distribution of $0.52 per unit with respect to the fourth quarter of2006.  The distribution totalingapproximately $22.7 million 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 totalingapproximately $30.1 million will be paid in May 2007 to unitholders of recordat the close of business on May 3, 2007.

Company management currently anticipatesrecommending to the Board of Directors an increase in the cash distributionbeginning with the second fiscal quarter of 2007 to an annual rate of $2.28 perunit from the current annual rate of $2.08 per unit.

***Private Placements***

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 “Class C Private Placement”).  The proceeds from the Class C PrivatePlacement were used to finance the Texas Panhandle acquisition and theacquisitions of certain gas properties in West Virginia.  SeeNote 3 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 Class C PrivatePlacement, the Company agreed to file a registration statement with the SECcovering the units and the units underlying the Class C units.  In accordance with the agreement, theregistration statement must be declared effective by the SEC no later than 165days following the closing.

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 the Class Bprivate placement closing.  The effectivedate deadline was extended under a separate agreement to 210 days.

The Company could be required to pay purchasers, asliquidated damages, certain amounts as defined in the agreements in the eventthe registration effectiveness deadlines are not met.  The potential payments would be approximately$0.8 million and $0.9 million for the October 2006 and February 2007placements, respectively, for each 30 day period that the registrationdeadlines are not met, up through 90 days. Subsequent to 90 days, the potential payments would increase for each 30day period, up to a maximum of 1.0% of the gross proceeds of eachoffering.  If an accounting changeresulted in units being reclassified as a liability, any payment would befurther limited to the units remaining under equity treatment on the financialstatements of the Company.

The Company evaluated itsexposure to the payment of liquidated damages under these agreements anddetermined its probable payments to be approximately $0.3 million.  As such, the Company recorded a liability forthis amount on its condensed consolidated balance sheets at March 31,2007.  Subsequent changes in the amountof the liability will be recorded in “other income and (expenses)” on thecondensed consolidated statements of operations.  The Company will continue to monitor andassess its exposure in this matter; however, the Company does not currently 

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expect payments underthese agreements, if any, to be material to the Company’s financial position orresults of operations.

***Initial PublicOffering***

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

***Credit Facility***

AtMarch 31, 2007 the Company had an $800.0 million senior secured revolvingcredit facility with a maturity of August 2010, and a borrowing base of $725.0million.  In February 2007, inconjunction with the Texas Panhandleacquisition and two acquisitions in West Virginia (see Note 3 in Notes toCondensed Consolidated Financial Statements) the Company amended its CreditFacility, increasing the borrowing base from $480.0 million to $725.0million.  In connection with thisamendment, in the first quarter of 2007, the Company paid fees of approximately$1.6 million, which will be amortized over the remaining term of the CreditFacility, and wrote-off deferred financing fees of approximately $0.5million.  At April 30, 2007, we had $120.2 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 the Credit Facility is determined by reference toLIBOR plus an applicable margin between 1.00% and 1.75% per annum; or adomestic bank rate plus an applicable margin between 0.00% and 0.25% perannum.  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 March 31, 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.

***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.

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***Commitmentsand Contractual Obligations***

The Company has contractual obligations for long-termdebt, operating leases and other long-term liabilities that were summarized ina table of contractual obligations in the 2006 Annual Report on Form 10-K.  As of March 31, 2007, there have been nosignificant changes to the Company’s contractual obligations fromDecember 31, 2006.

**Non-GAAP Financial Measure**

***Adjusted EBITDA***

Wedefine Adjusted EBITDA as net income (loss) plus:

·                  Interestexpense; net of amounts capitalized;

·                  Depreciation,depletion and amortization;

·                  Write-off of deferredfinancing 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.

Thefollowing table presents a reconciliation of our consolidated net income (loss)to Adjusted EBITDA:

|                                                   | ** ** | **Three Months Ended  March 31,** | ** ** |
|---------------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                        | ** ** | **2007**                                         | ** ** | **2006** | ** ** |
| ** **                                        | ** ** | **(in thousands)**                          | ** ** |
| Net income  (loss)                                |       | $                                                | (67,847    | ) | $ | 21,977 |   |
| Plus:                                             |       |                                             |       |   |   |
| Interest expense, net of amounts capitalized      |       | 9,913                                            |       | 2,639 |   |
| Depreciation, depletion and amortization          |       | 11,851                                           |       | 3,700 |   |
| Write-off of deferred financing fees and other    |       | 804                                              |       | 374 |   |
| (Gain) loss on sale of assets                     |       | (945                                             | )          | 18 |   |
| Accretion of asset retirement obligation          |       | 110                                              |       | 58 |   |
| Unrealized (gain) loss on oil and gas derivatives |       | 69,514                                           |       | (20,923 | ) |
| Unit-based compensation and unit warrant expense  |       | 3,740                                            |       | 5,680 |   |
| IPO cash bonuses                                  |       | —                                           |       | 2,039 |   |
| Income tax provision (1)                          |       | 3,632                                            |       | 119 |   |
| Adjusted EBITDA                                   |       | $                                                | 30,772     |   | $ | 15,681 |   |

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(1)                                  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 firstquarter of 2007.

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Asnoted above, Adjusted EBITDA is non-GAAP performance measure used by ourmanagement and is a quantitative measure used in the oil and gas industry.  On our condensed consolidated statements ofcash flows, our net cash used by operating activities for the three monthsended March 31, 2007, was approximately $37.9 million and includesapproximately $54.1 million unrealized loss on oil and gas and interest ratederivatives and $3.7 million unit-based compensation and unit warrantexpense.  Our net cash used by operatingactivities for the three months ended March 31, 2006, was approximately$5.4 million and includes $24.0 million gain on unrealized oil and gasderivatives and $5.7 million unit-based compensation expense.

**NewAccounting Standards**

There have been noaccounting standards that materially affected the Company this period; however,see Note 2 in Notes to Condensed Consolidated Financial Statements fordetail regarding FIN 48.

**CautionaryStatement**

This Quarterly Report on Form 10-Q containsforward-looking statements within the meaning of federal securities laws thatare subject to a number of risks and uncertainties, many of which are beyondour control.  These statements mayinclude statements about our:

·                  business strategy;

·                  acquisition strategy;

·                  financial strategy;

·                  drilling locations;

·                  oil and gas reserves;

·                  realized oil and gas prices;

·                  production volumes;

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

·                  future operating results; and

·                  plans, objectives, expectations and intentions.

All of these types of statements, other thanstatements of historical fact included in this Quarterly Report on Form 10-Q,are forward looking statements.  Theseforward-looking statements may be found in Item 2.  In some cases, forward-looking statements canbe identified by terminology such as “may,” “will,” “could,” “should,” “expect,”“plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,”“pursue,” “target,” “continue,” the negative of such terms or other comparableterminology.

The forward-looking statements contained in thisQuarterly Report on Form 10-Q are largely based on our expectations, whichreflect estimates and assumptions made by our management.  These estimates and assumptions reflect ourbest judgment based on currently known market conditions and otherfactors.  Although we believe suchestimates and assumptions to be reasonable, they are inherently uncertain andinvolve a number of risks and uncertainties beyond our control.  In addition, management’s assumptions mayprove to be inaccurate.  We caution thatthe forward-looking statements contained in this Quarterly Report onForm 10-Q are not guarantees of future performance, and we cannot assureany reader that such statements will be realized or the forward-lookingstatements or events will occur.  Actualresults may differ materially from those anticipated or implied inforward-looking statements due to factors listed in “Item 1A. Risk Factors”in our Annual Report on Form 10-K for the year endedDecember 31, 2006, and elsewhere in our Annual Report and also in thisQuarterly Report on Form 10-Q.  Theforward-looking statements speak only as of the date made, and other than asrequired by law, we undertake no obligation to publicly update or revise anyforward-looking statement, whether as a result of new information, future eventsor otherwise.

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**Item3.****                        Quantitativeand Qualitative Disclosures About 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 gas prices and interestrates.  The disclosures are not meant tobe precise indicators of expected future losses, but rather indicators ofreasonably 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**

Our major market risk exposure isin the pricing applicable to our oil, gas and NGL production.  Realized pricing is primarily driven by thespot market prices applicable to our production and the prevailing price foroil.  Pricing for oil and gas productionhas been volatile and unpredictable for several years, and we expect thisvolatility to continue in the future. The prices we receive for production depend on many factors outside ofour control.

We periodically have entered intoand anticipate entering into hedging arrangements with respect to a portion ofour projected oil and gas production through various transactions that hedgethe future prices received.  Thesetransactions may include price swaps whereby we will receive a fixed price forour production and pay a variable market price to the contractcounterparty.  At the settlement date, wereceive the excess, if any, of the fixed floor over the floating rate.  Additionally, we have put options for whichwe pay the counterparty the fair value at the purchase date.  These hedging activities are intended tosupport oil and gas prices at targeted levels and to manage our exposure tooil, gas and NGL price fluctuations.  Wedo not hold or issue derivative instruments for speculative trading purposes.

At March 31, 2007, the fairvalue of hedges that settle during the next twelve months was an asset ofapproximately $24.5 million and a liability of approximately $5.9 millionfor a total asset of approximately $18.6 million, for which we are owed by thecounterparty.  A 10% increase in theindex oil and gas prices above the March 31, 2007 prices for the nexttwelve months would result in a reduction in the value of our hedges ofapproximately $16.4 million; conversely, a 10% decrease in the index oil andgas prices would result in an increase of approximately $19.8 million.

Our derivatives as ofMarch 31, 2007, for 2007 through 2011, are summarized in the tablepresented in Note 11 in Notes to Condensed Consolidated FinancialStatements.

***Interest RateRisk***

At March 31, 2007, we hadlong-term debt outstanding of $596.8 million under our Credit Facility, whichincurred interest at floating rates in accordance the Credit Facilityagreement.  As of March 31, 2007,our rate based on the one-month LIBOR was approximately 6.875%.  A 1% increase in the one-month LIBOR wouldresult in an estimated $6.0 million increase in annual interest expense.

Inorder to finance the Texas Panhandle acquisition and the acquisitions ofcertain gas properties in West Virginia, in February 2007, the Company modifiedits Credit Facility, increasing the borrowing base to $725.0 million.  See Note 7 in Notes to CondensedConsolidated Financial Statements.

We have periodically entered intointerest rate swap agreements to minimize the effect of fluctuations ininterest rates.  We are required to payour counterparties the difference between the fixed rate in the contract andthe actual rate if the actual rate is lower than the fixed rate and conversely,our counterparties are required to pay us if the actual rate is higher than thefixed rate in the contract.  AtMarch 31, 2007, we had two interest rate swaps outstanding with notionalamounts of $50.0 million for 2007 and 2008, and fixed interest rates of 5.30%and 5.79%, respectively.

A 1% change in LIBOR as ofMarch 31, 2007 would result in an estimated $1.0 million change in annualinterest expense associated with our interest swap agreements.

Under the terms of the swapagreements, we receive quarterly interest payments at the three-month LIBORrate.

We did not designate the interestrate swap agreements we entered into as hedges under SFAS 133, even though theyprotect us from changes in interest rates. Therefore, the changes in fair value of these instruments were recordedin our current earnings.  These amountsare non-cash gains and losses.

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**Item4.****                       Controlsand Procedures**

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

The Company maintains disclosure controls andprocedures that are designed to ensure that information required to bedisclosed in the Company’s reports under the Exchange Act is recorded,processed, summarized and reported within the time periods specified in the SEC’srules and forms, and that such information is accumulated and communicated tomanagement, including the Company’s Chief Executive Officer and Chief FinancialOfficer, and the Company’s Audit Committee of the Board of Directors, asappropriate, to allow timely decisions regarding required disclosure.  In designing and evaluating the disclosurecontrols and procedures, management recognizes that any controls andprocedures, no matter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives, andmanagement is required to apply its judgment in evaluating the cost-benefitrelationship of possible controls and procedures.

We carried out an evaluation under the supervision andwith the participation of our management, including our Chief Executive Officerand Chief Financial Officer, of the effectiveness of our disclosure controlsand procedures as of the end of the period covered by this report.

Due to the material weakness described below, ourChief Executive Officer and Chief Financial Officer continue to conclude thatour disclosure controls and procedures were not effective as of March 31,2007.  As noted below, we believe we havetaken the necessary steps to address the matters related to the materialweakness.  However, before concludingthat the material weakness has been remediated, management believes that thenew internal controls should be implemented and operational for a sufficientperiod of time to demonstrate that the controls 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.

*Material weaknesses in internalcontrol*.  Specifically,the Company lacked:  (i) personnelwith sufficient technical accounting and financial reporting expertise,(ii) adequate review controls over account reconciliations and accountanalyses, (iii) policies and procedures to determine and document theappropriate application of accounting principles, and (iv) policies andprocedures requiring a detailed and comprehensive review of the underlyinginformation supporting the amounts included in the annual and interim consolidatedfinancial statements and disclosures.

*Remediation activities.*  During 2006, Company management took thefollowing steps to strengthen internal control over financial reporting.

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

2.               We utilized outsideconsultants with extensive oil and gas financial reporting experience andaugmented our accounting resources to assist with required filings anddocumentation of reconciliations and procedures.

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

4.               We performedadditional analysis and other post-closing procedures to enable the preparationof accurate consolidated financial statements, including all requireddisclosures.  In addition, we implementedcertain review and monitoring controls over account reconciliations, and analysisand post-closing procedures.

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

6.               We implemented theuse of disclosure checklists addressing the disclosure requirements under GAAPas well as the incremental financial and non-financial information required bySEC regulations.

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7.               We providedextensive training on our accounting software system to both new andestablished accounting personnel.

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

***(b) *Changes and remediation in the Company’sinternal control over financial reporting**

During the three months ended March 31, 2007, wehave not made any changes that have materially affected, or are reasonablylikely to materially affect, our internal control over financial reporting, asdefined in Rule 13(a)-15(f) under the Exchange Act.

As previously reported, we expect to continue to makechanges in our internal control over financial reporting during the periodsprior to December 31, 2007 in connection with our compliance efforts underSection 404 of the Sarbanes-Oxley Act of 2002. As such, we will continue to assess the adequacy of our internal controlover financial reporting, remediate any control weaknesses that may beidentified, validate through testing that controls are functioning as designedand implement a continuous reporting and improvement process for internal controlover 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**

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

Our revenue, profitability 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 oil 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 oil, gas and NGLpipelines and other transportation 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 our oiland gas properties for impairments.  Weare required to perform impairment tests on our assets periodically andwhenever events or changes in circumstances warrant a review of ourassets.  To the extent such testsindicate a reduction of the estimated useful life or estimated future cashflows of our assets, the carrying value may not be recoverable and thereforerequire a write-down.  We may incurimpairment charges in the future, which could have a material adverse effect onour results of operations in the period incurred and on our ability to borrowfunds under our credit facility, which in turn may adversely affect our abilityto make cash distributions 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, gas andNGL reservoirs are characterized by declining production rates that varydepending upon reservoir characteristics and other factors.  The overall rate of decline for ourproduction will change if production from our existing wells declines in adifferent manner than we have estimated and can change when we drill additionalwells, make acquisitions and under other circumstances.  Thus, our future oil, 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 at acceptablecosts, which would adversely affect our cash flow from operations and ourability 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,estimated quantities of proved reserves and projections of future productionrates and the timing of development expenditures may prove to beinaccurate.  Independent petroleumengineering firms prepare estimates of our proved reserves.  Over time, our internal engineers may makematerial changes to reserve estimates taking into account the results of actualdrilling and production.  Some of ourreserve estimates are made without the benefit of a lengthy production history,which are less reliable than estimates based on a lengthy productionhistory.  Also, we make certainassumptions regarding future oil, gas and NGL prices, production levels, andoperating and development costs that may prove incorrect.  Any significant variance from theseassumptions by actual figures could greatly affect our estimates of reserves,the economically recoverable quantities of oil, gas and NGL attributable to anyparticular group of properties, the classifications of reserves based on riskof recovery and estimates of the future net cash flows.  Numerous changes over time to the assumptionson which our reserve estimates are based, as described above, often result inthe actual quantities of oil, gas and NGL we ultimately recover being differentfrom our reserve estimates.

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 we usewhen calculating discounted future net cash flows may not be the mostappropriate discount factor based on interest rates in effect from time to timeand risks associated with us or the oil and gas industry in general.

***Our development operations require substantialcapital expenditures, which will reduce our cash available fordistribution.  We may be unable to obtainneeded capital or financing on satisfactory terms, which could lead to adecline in our reserves.***

The oil and gas industryis capital intensive.  We make and expectto continue to make substantial capital expenditures in our business for thedevelopment, production and acquisition of oil, gas and NGL reserves.  These expenditures will reduce our cashavailable for distribution.  We intend tofinance our future capital expenditures with cash flow from operations and ourfinancing arrangements.  Our cash flowfrom operations and access to capital are subject to a number of variables,including:

·                  our proved reserves;

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

·                  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.  Our creditfacility 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 capital requirements,the failure to obtain additional financing could result in a curtailment of ourdevelopment operations, which in turn could lead to a possible decline in ourreserves.

***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 three monthsended March 31, 2007, Dominion Resources, Inc., ConocoPhillips and Duke EnergyCorporation accounted for approximately 34%, 18% and 13%, respectively, of ourtotal volumes, or 65% 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, gasand NGL prices increase the demand for drilling rigs, pipe, equipment and crewsand can lead to shortages of, and increasing costs for, drilling equipment,services and 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.****                       DefaultsUpon Senior Securities**

None.

**Item4.****                       Submissionof Matters to a Vote of Security Holders**

A special meeting of unitholders was held onJanuary 18, 2007.  The matters votedon at the meeting and the results were as follows:

1.               To vote upon (a) achange in terms of our Class B units to provide that each Class Bunit will convert automatically into one of our units and (b) the issuance of9,185,968 units upon such conversion.

|               | ** ** | **Votes Against** | ** ** | ** **      |
|---------------|------------|-------------------|------------|-----------------|
| **Votes For** | ** ** | **or Withheld**   | ** ** | **Abstentions** |
| 18,951,949    |       | 67,148            |       | 61,484          |
|          |       |              |       |            |

2.               A proposal toapprove an amendment to the Linn Energy, LLC Long-Term Incentive Plan (the “LTIP”)to provide that not more than 1,500,000 of the total number of units authorizedto be issued under the LTIP may be issued as restricted units.

|               | ** ** | **Votes Against** | ** ** | ** **      |
|---------------|------------|-------------------|------------|-----------------|
| **Votes For** | ** ** | **or Withheld**   | ** ** | **Abstentions** |
| 22,047,961    |       | 178,986           |       | 57,393          |

 

 

**Item5.****                        OtherInformation**

None.

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**Item6.****                        Exhibits**
| Exhibit Number | ** ** | ** ** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|---------------------|------------|------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2 .1                |       | —     |       | Gathering System Purchase Agreement dated  February 1, 2007, by and between Cavallo Gathering Company LLC, a Texas  limited liability company, and Penn West Pipeline, LLC, a Delaware limited  liability company (incorporated herein by reference to Exhibit 2.3 to  our Current Report on Form 8-K filed on February 5, 2007)                                                                                                   |
| 3 .1                |       | —     |       | Certificate of Formation of Linn Energy Holdings,  LLC (now Linn Energy, LLC) (incorporated herein by reference to  Exhibit 3.1 to our Registration Statement on Form S-1 (File  No. 333-125501) filed by Linn Energy, LLC on June 3, 2005)                                                                                                                                                                                        |
| 3 .2                |       | —     |       | Certificate of Amendment to Certificate of Formation  of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by  reference to Exhibit 3.2 to our Form S-1 filed on June 3,  2005)                                                                                                                                                                                                                                     |
| 3 .3                |       | —     |       | Second Amended and Restated Limited Liability  Company Agreement of Linn Energy, LLC dated January 19, 2006  (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)                                                                                                          |

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| 10 .9       |   | — |   | 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 .10      |   | — |   | 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 .11      |   | — |   | 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 .12      |   | — |   | 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 .13      |   | — |   | Transition Services Agreement Dated February 1,  2007, by and between Stallion Energy LLC, a Delaware limited liability  company, and Linn Energy, LLC, a Delaware limited liability company, Linn  Energy Holdings, LLC, a Delaware limited liability company, Linn Operating,  Inc., a Delaware corporation and Penn West Pipeline, LLC, a Texas limited  liability company (incorporated herein by reference to Exhibit 10.3 to  our Current Report on Form 8-K filed on February 5, 2007) |
| 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: May 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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