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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
FORM OF SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF LINN ENERGY, LLC

As filed with the Securities and Exchange Commission on December 14, 2005

Registration No. 333-125501

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 4
to
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Linn Energy, LLC
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	1311 (Primary Standard Industrial Classification Code Number)	65-1177591 (I.R.S. Employer Identification Number)
650 Washington Road, 8^th Floor Pittsburgh, Pennsylvania 15228 (412) 440-1400 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)
Michael C. Linn Linn Energy, LLC 650 Washington Road, 8^th Floor Pittsburgh, Pennsylvania 15228 (412) 440-1400 (Name, address, including zip code, and telephone number, including area code, of agent for service)

*Copies to:*
James V. Baird Gislar Donnenberg Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200		Thomas P. Mason Vinson & Elkins L.L.P. First City Tower 1001 Fannin, Suite 2300 Houston, Texas 77002 (713) 758-2222

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. o

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to completion, dated December 14, 2005

PROSPECTUS

Linn Energy, LLC
11,750,000 Units
Representing Limited Liability Company Interests
$ per unit

This is the initial public offering of our units. We expect the initial public offering price to be between $19.00 and $21.00 per unit. We intend to list our units on The Nasdaq National Market under the symbol "LINE."

Investing in our units involves risks. Please read "Risk Factors" beginning on page 17.

These risks include the following:

•: We may not have sufficient cash flow from operations to pay the initial quarterly distribution. We would have had significant shortfalls in recent periods, and in 2006, absent expected borrowings of $17.9 million under our credit facility, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash generated from operations, to fund our drilling program and to pay our annualized initial quarterly distribution.
•: We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions in the amount of the initial quarterly distribution.
•: If commodity prices decline significantly for a prolonged period, we may lower our distribution or not be able to pay distributions at all.
•: Unless we replace our reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
•: Our development operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves.
•: Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.
•: Our management and Quantum Energy Partners will own, in the aggregate, a controlling interest in us, with management and Quantum Energy Partners owning approximately 17.5% and 39.2%, respectively, of our units.
•: Each of our management or Quantum Energy Partners, or both, may have conflicts of interest with us. Our limited liability company agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.
•: You will experience immediate and substantial dilution of $17.49 per unit.
•: You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

	Per Unit	Total
Public offering price	$	$
Underwriting discount(1)	$	$
Proceeds, before expenses, to Linn Energy, LLC	$	$

(1): Excludes structuring fee of $400,000.

The underwriters expect to deliver the units on or about , 2006. We have granted the underwriters a 30-day option to purchase up to an additional 1,762,500 units on the same terms and conditions as set forth above if the underwriters sell more than 11,750,000 units in this offering.

Joint Book-Running Managers

RBC CAPITAL MARKETS

LEHMAN BROTHERS

A.G. EDWARDS
UBS INVESTMENT BANK
				KEYBANC CAPITAL MARKETS

, 2006

TABLE OF CONTENTS

PROSPECTUS SUMMARY
	Linn Energy, LLC
	Business Strategy
	Competitive Strengths
	Summary of Risk Factors
	Our LLC Structure
	The Offering
	Summary Historical and Pro Forma Consolidated Financial and Operating Data
	Summary Reserve and Operating Data
	Non-GAAP Financial Measure
RISK FACTORS
	Risks Related to Our Business
	Risks Related to Our Structure
	Tax Risks to Unitholders
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
USE OF PROCEEDS
CAPITALIZATION
DILUTION
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
	General
	Cash Distributions
	Estimated Adjusted EBITDA
	Pro Forma Cash Available to Pay Distributions for the Year Ended December 31, 2004 and the Pro Forma Twelve-Month Period Ended September 30, 2005
	Assumptions and Considerations
HOW WE MAKE CASH DISTRIBUTIONS
	Definition of Available Cash
	Distributions of Cash Upon Liquidation
	Adjustments to Capital Accounts
SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview
	Production and Operating Costs Reporting
	Land and Lease Tracking System
	Results of Operations
	Capital Resources and Liquidity
	Cash Flow from Operations
	Investing Activities — Acquisitions and Capital Expenditures
	Financing Activities
	Critical Accounting Policies and Estimates
	Natural Gas and Oil Properties
	Natural Gas and Oil Reserve Quantities
	Revenue Recognition
	Derivative Instruments and Hedging Activities
	Acquisitions
	Stock Based Compensation
	New Accounting Pronouncements
	Quantitative and Qualitative Disclosure About Market Risk
BUSINESS
	Overview
	Recent Developments
	Acquisition History
	Business Strategy
	Competitive Strengths
	Drilling
	Appalachian Basin
	Natural Gas Prices
	Natural Gas and Oil Data
	Natural Gas Gathering Activities
	Natural Gas Gathering for Others
	Purchase for Resale
	Operations
MANAGEMENT
	Our Board of Directors
	Compensation Committee Interlocks and Insider Participation

	Our Board of Directors and Executive Officers
	Executive Compensation
	Compensation of Directors
	Employment Agreements
	Long-Term Incentive Plan
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	Stakeholders' Agreement
DESCRIPTION OF THE UNITS
	The Units
	Transfer Agent and Registrar
	Transfer of Units
THE LIMITED LIABILITY COMPANY AGREEMENT
	Organization
	Purpose
	Fiduciary Duties
	Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney
	Capital Contributions
	Limited Liability
	Voting Rights
	Issuance of Additional Securities
	Election of Members of Our Board of Directors
	Removal of Members of Our Board of Directors
	Amendment of Our Limited Liability Company Agreement
	Merger, Sale or Other Disposition of Assets
	Termination and Dissolution
	Liquidation and Distribution of Proceeds
	Anti-Takeover Provisions
	Limited Call Right
	Meetings; Voting
	Non-Citizen Assignees; Redemption
	Indemnification
	Books and Reports
	Right To Inspect Our Books and Records
	Registration Rights
UNITS ELIGIBLE FOR FUTURE SALE
MATERIAL TAX CONSEQUENCES
INVESTMENT IN OUR COMPANY BY EMPLOYEE BENEFIT PLANS
UNDERWRITING
VALIDITY OF THE UNITS
EXPERTS
WHERE YOU CAN FIND MORE INFORMATION
INDEX TO FINANCIAL STATEMENTS

APPENDIX A	—	Form of Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC	A-1
APPENDIX B	—	Glossary of Terms	B-1
APPENDIX C	—	Reserve Report	C-1

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

Until , 2006 (25 days after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma consolidated financial statements and the notes to those financial statements. The information presented in this prospectus assumes an initial public offering price of $20.00 per unit and that the underwriters' option to purchase additional units is not exercised. You should read "Risk Factors" beginning on page 17 for information about important factors that you should consider carefully before buying the units. We include a glossary of some of the terms used in this prospectus in Appendix B. Schlumberger Data and Consulting Services, an independent engineering firm, provided the estimates of proved natural gas and oil reserves as of September 30, 2005 included in this prospectus. These estimates are contained in a summary prepared by Schlumberger of its reserve report as of September 30, 2005 for the properties described below, including the interests acquired from Exploration Partners. This summary is located at the back of this prospectus as Appendix C and is referred to in this prospectus as the reserve report. References in this prospectus to "Linn Energy," "we," "our," "us," or like terms refer to Linn Energy, LLC and its subsidiaries.

Linn Energy, LLC

We are an independent natural gas company focused on the development, exploitation and acquisition of natural gas properties in the Appalachian Basin, primarily in Pennsylvania, West Virginia, New York and Virginia. Our goal is to provide stability and growth in distributions to our unitholders through a combination of continued successful drilling and acquisitions. Our company was formed in March 2003 by our President and Chief Executive Officer Michael C. Linn, Quantum Energy Partners and non-affiliated equity investors with an aggregate equity investment of $16.3 million. Since inception, we have made nine acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate purchase price of $203.2 million, with total proved reserves of 160.1 Bcfe, or an acquisition cost of $1.27 per Mcfe. Our nine acquisitions included 1,914 producing wells and we have drilled 191 wells since inception. At November 30, 2005, our production was approximately 21.6 MMcfe per day from 2,105 wells.

Our proved reserves at September 30, 2005 were 189.6 Bcfe, which includes the interests acquired from Exploration Partners (see below), of which approximately 99% were natural gas and 66% were classified as proved developed, with estimated future net revenues discounted at 10% (Standardized Measure) of $898.7 million. At November 30, 2005, we operated 1,913, or 91%, of our 2,105 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 29 years based on our September 30, 2005 reserve report and annualized pro forma production for the nine months ended September 30, 2005. As of September 30, 2005, we had identified 362 proved undeveloped drilling locations and over 500 additional drilling locations and had a leasehold interest in 140,045 net acres in the Appalachian Basin. From inception through September 30, 2005, we added 27.2 Bcfe of proved natural gas and oil reserves through our drilling activities, at a finding and development cost of $1.21 per Mcfe, which includes the estimated development costs for proved undeveloped reserves.

Recent Developments

total wells acquired. We also acquired approximately 250 miles of natural gas gathering systems, which deliver 6.7 MMcf per day to eight different purchasers through 110 delivery points, as well as related oilfield service equipment. We conduct the oilfield services through our subsidiary Mid Atlantic Well Service, Inc. Additionally, we acquired, pursuant to a standard farm out agreement, the option to drill on approximately 10,000 undeveloped acres in northern West Virginia. As of November 30, 2005, we had identified 105 proved undeveloped drilling locations and 117 additional drilling locations on this acreage and currently expect to drill 25 wells annually.

Drilling

The Appalachian Basin is a mature producing region with well known geologic characteristics. Reserves in the Appalachian Basin typically have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

From inception through September 30, 2005, we spent $32.9 million and drilled 168 wells, all of which produce natural gas in commercial quantities, with an average finding and development cost of $1.21 per Mcfe, which includes the estimated development costs for proved undeveloped reserves. To carry out our active drilling program, we are currently utilizing three drilling rigs that are under contract for our 2005 drilling program. During 2005, we anticipate spending $23.6 million to drill 110 wells, 104 of which we will operate. As of November 30, 2005, we had drilled 101 out of our planned 110 wells.

Acquisitions

We focus on acquisitions that allow us to:

•: Increase production through workovers, addition of equipment, improved field operations as well as additional infill drilling and other development activities; and
•: Implement efficiencies through operational and administrative consolidation.

Since inception, we completed the following acquisitions:

Date	Seller	Wells	Location	Purchase Price (in millions)
May 2003	Emax Oil Company	34	West Virginia	$	3.1
Aug 2003	Lenape Resources, Inc.	61	New York		2.0
Sep 2003	Cabot Oil & Gas Corporation	50	Pennsylvania		15.5
Oct 2003	Waco Oil & Gas Company	353	West Virginia and Virginia		31.0
May 2004	Mountain V Oil & Gas, Inc.	251	Pennsylvania		12.4
Sep 2004	Pentex Energy, Inc.	447	Pennsylvania		14.2
Apr 2005	Columbia Natural Resources, LLC	38	West Virginia and Virginia		4.3
Aug 2005	GasSearch Corporation	130	West Virginia		5.4
Oct 2005	Exploration Partners, LLC	550	West Virginia and Virginia		115.3

	Total	1,914		$	203.2

Natural Gas Prices

Natural gas produced in the Appalachian Basin typically sells for a premium to New York Mercantile Exchange (NYMEX) natural gas prices due to the proximity to major consuming markets in the northeastern United States. For the year ended December 31, 2004, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin on the Columbia Gas Transmission Corp. Appalachia Pipeline and the Dominion Transmission Inc. Appalachia Pipeline was $0.26 and $0.35 per Mcf, respectively. In addition, most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices. As of December 31, 2004, our average realized natural gas prices, net of gathering fees, represented a $0.67 per Mcf premium to NYMEX natural gas prices.

We enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use fixed price swaps and puts to hedge NYMEX natural gas prices, which do not include the additional net premium we typically realize in the Appalachian Basin. For the year ending December 31, 2006, we currently have fixed price swaps and puts in place for a total hedged amount of 8,142 MMMBtu, which represents approximately 94% of our total expected production volume of 8,655 MMcfe. By removing the price volatility from a significant portion of our natural gas production, we have mitigated, but not eliminated, the potential effects of changing natural gas prices on our cash flow from operations for those periods.

Natural Gas Gathering

We own and operate an extensive network of natural gas gathering systems and gather more than 90% of our production, which allows us to more efficiently transport our gas to market. Our gathering assets are comprised of approximately 780 miles of pipeline, associated compression and metering facilities that connect to numerous sales outlets on eight intrastate as well as eight interstate pipelines. Our wholly owned subsidiary Chipperco, LLC owns an aggregate of approximately 46 miles of natural gas gathering systems. We transport our natural gas as well as a limited amount for third parties.

Business Strategy

The key elements of our business strategy are:

•: Executing low risk, low cost exploitation drilling;
•: Focusing on acquisitions that increase cash available for distribution;
•: Creating additional value post-acquisition;
•: Maximizing the value and stability of our cash flows through operating control; and
•: Reducing commodity price risk through hedging.

Competitive Strengths

We believe our competitive strengths will result in a sufficient level of cash available for distribution and provide strong growth potential. Our competitive strengths are:

•: Low risk, low cost exploitation drilling;
•: Strong acquisition track record;
•: Large undeveloped land base;
•: Operating control;
•: Experienced operator in the Appalachian Basin;
•: Long life reserves;
•: Production diversification; and
•: Premium pricing.

Summary of Risk Factors

An investment in our units involves risks associated with our business, regulatory and legal matters, our limited liability company structure and the tax characteristics of our units. The following list of risk factors is not exhaustive. Please read carefully these and the other risks under the caption "Risk Factors" beginning on page 17.

Risks Related to Our Business

•: We may not have sufficient cash flow from operations to pay the initial quarterly distribution. We would have had significant shortfalls in recent periods and in 2006, absent expected borrowings of $17.9 million under our credit facility, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash generated from operations, to fund our drilling program and to pay our annualized initial quarterly distribution.
•: We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions in the amount of the initial quarterly distribution.
•: If commodity prices decline significantly for a prolonged period of time, we may lower our distribution or not be able to pay distributions at all.
•: If we are unable to achieve the Estimated Adjusted EBITDA set forth in "Cash Distribution Policy and Restrictions on Distributions," we may be unable to pay the full, or any, amount of the initial quarterly distribution on the units, in which event the market price of our units may decline substantially.
•: Unless we replace our reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
•: Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

•: Our development operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves.
•: Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.
•: Because we handle natural gas and other petroleum products, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

Risks Related to Our Structure

•: Our management and Quantum Energy Partners will own, in the aggregate, a controlling interest in us, with management and Quantum Energy Partners owning approximately 17.5% and 39.2%, respectively, of our units.
•: Each of our management or Quantum Energy Partners, or both, may have conflicts of interest with us. Our limited liability company agreement limits the remedies available to you if you have a claim relating to conflicts of interest.
•: You will experience immediate and substantial dilution of $17.49 per unit.
•: We may issue additional units without your approval, which would dilute your existing ownership interests.

Tax Risks to Unitholders

•: Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.
•: You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.
•: A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the costs of any contest will reduce cash available for distribution.
•: Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.
•: Tax gain or loss on the disposition of our units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your units.

OUR LLC STRUCTURE

Linn Energy, LLC, a Delaware limited liability company formed in April 2005, is a holding company that conducts its operations through, and its operating assets are owned by, its subsidiaries Linn Energy Holdings, LLC (formed in March 2003 and formerly known as Linn Energy, L.L.C.), Linn Operating, Inc. (formerly Linn Operating, LLC), Chipperco, LLC and Mid Atlantic Well Service, Inc. We own, directly or indirectly, all of the ownership interests in our operating subsidiaries. Linn Energy Holdings owns all of our interests in natural gas and oil properties, all of our employees are employed by Linn Operating or Mid Atlantic Well Service, Chipperco owns and operates our natural gas gathering assets and Mid Atlantic Well Service conducts our oilfield service operations.

Concurrently with this offering, a portion of our members' existing membership interests will be exchanged for units of Linn Energy, LLC, and we will redeem approximately $84.7 million of membership interests from Quantum Energy Partners, $2.2 million of membership interests from non-affiliated equity investors and $3.0 million of membership interests from Michael C. Linn.

Following our initial public offering and the application of the related net proceeds and based on an assumed initial public offering price per unit of $20.00:

•: Our management will own 4,867,235 units, representing an aggregate 17.5% membership interest in us;
•: Quantum Energy Partners will own 10,914,228 units, representing an aggregate 39.2% membership interest in us; and
•: the public unitholders will own 11,750,000 units, representing an aggregate 42.3% membership interest in us.

We will use any net proceeds from the exercise of the underwriters' option to purchase additional units to redeem the number of units from Quantum Energy Partners and the non-affiliated equity investors equal to the number of units issued upon the exercise of the underwriters' option. If the underwriters' option to purchase additional units is exercised in full, Quantum Energy Partners' ownership of units will be reduced from 10,914,228 units to 9,195,973 units, or 33.1% of all then outstanding units, and the ownership interest of the public unitholders will increase to 13,512,500, or 48.6% of all the outstanding units.

Quantum Energy Partners is a provider of private equity to exploration and production companies as well as midstream, natural gas storage and independent power companies in the United States and Canada with approximately $670 million under management. Affiliates of Quantum Energy Partners have established three energy investment funds and currently manage capital on behalf of over 30 United States and European non-affiliated institutions and individuals.

Our board of directors has sole responsibility for conducting our business and for managing our operations. Our principal executive offices are located at 650 Washington Road, 8^th Floor, Pittsburgh, Pennsylvania 15228, and our telephone number is (412) 440-1400. We also maintain a corporate office at 600 Travis, Suite 6910, Houston, Texas 77002, and our Houston telephone number is (713) 223-0880. Our internet address is www.linnenergy.com.

The following diagram depicts our organizational structure after our initial public offering:

(1): Does not include 281,037 units (or 1.0% of all outstanding units) owned by non-affiliated equity investors.
(2): Includes Michael C. Linn, our President and Chief Executive Officer; Kolja Rockov, our Executive Vice President and Chief Financial Officer; Gerald W. Merriam, our Executive Vice President-Engineering Operations; and Roland P. Keddie, our Executive Vice President-Secretary.
(3): If the underwriters' option to purchase additional units is exercised in full, Quantum Energy Partners' ownership in us will be reduced to 9,195,973 units, or 33.1% of all outstanding units, and the ownership interest of the public unitholders will increase to 13,512,500 units, or 48.6% of all then outstanding units.

THE OFFERING

Units offered by us	11,750,000 units.
	13,512,500 units if the underwriters exercise their option to purchase additional units in full.
Units outstanding after this offering	27,812,500 units.
Use of proceeds	We anticipate using the net proceeds of $218.6 million from this offering to:
		•	repay $122.0 million of the indebtedness outstanding under our revolving credit facility;
		•	redeem $84.7 million of membership interests from Quantum Energy Partners;
		•	redeem $2.2 million of membership interests from certain non-affiliated investors;
		•	redeem $3.0 million of membership interests from Michael C. Linn; and
		•	pay $6.7 million of expenses associated with this offering. Please read "Use of Proceeds."
	The $6.7 million of expenses associated with this offering include one-time bonuses payable to Michael C. Linn, our President and Chief Executive Officer, and Kolja Rockov, our Executive Vice President and Chief Financial Officer, upon completion of this offering. For a more detailed discussion of these bonuses, please read "Management — Employment Agreements."
	We will use any net proceeds from any exercise of the underwriters' option to purchase additional units to redeem the number of units from Quantum Energy Partners and non-affiliated equity investors equal to the number of units issued upon the exercise of the underwriters' option. If the underwriters' option to purchase additional units is exercised in full, Quantum Energy Partners' ownership of units will be reduced from 10,914,228 units to 9,195,973 units.
Cash distributions	We will distribute all of our cash on hand at the end of each quarter, after payment of fees and expenses, less reserves established by our board of directors. We refer to this cash as "available cash," and we define its meaning in more detail in our limited liability company agreement and in the glossary found in Appendix B. Our board of directors has broad discretion in establishing reserves for the proper conduct of our business. These reserves, which could be substantial, will reduce the amount of cash available for distribution to you.

Agreement to be bound by Limited Liability Company Agreement; Voting rights	By purchasing a unit in us, you will be admitted as a unitholder of our company and will be deemed to have agreed to be bound by all of the terms of our limited liability company agreement. Pursuant to our limited liability company agreement, as a unitholder you will be entitled to vote on the following matters:
		•	the annual election of members of our board of directors;
		•	specified amendments to our limited liability company agreement;
		•	the merger of our company or the sale of all or substantially all of our assets; and
		•	the dissolution of our company.
	Please read "The Limited Liability Company Agreement — Voting Rights."
Fiduciary duties	Our limited liability company agreement provides that except as expressly modified by its terms, the fiduciary duties of our directors and officers are identical to the fiduciary duties they would have as directors and officers of a Delaware corporation.
	Our limited liability company agreement establishes a conflicts committee of our board of directors, consisting solely of independent directors, which will be responsible for reviewing transactions involving potential conflicts of interest. If the conflicts committee approves such a transaction, you will not be able to assert that such approval constituted a breach of fiduciary duties owed to you by our directors and officers. Please read "Management — Our Board of Directors."
Estimated ratio of taxable income to distributions	We estimate that if you hold the units that you purchase in this offering through the record date for distributions for the period ending December 31, 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 10% of the cash distributed to you with respect to that period. Please read "Material Tax Consequences — Tax Consequences of Unit Ownership" beginning on page 127 of this prospectus for the basis of this estimate.
Listing and trading symbol	We intend to list our units on The Nasdaq National Market under the symbol "LINE."

SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED
FINANCIAL AND OPERATING DATA

Set forth below is our summary historical and pro forma consolidated financial and operating data for the periods indicated for Linn Energy, LLC (Successor). The historical financial data for the periods ended December 31, 2003 and 2004 and the balance sheet data as of December 31, 2003 and 2004 have been derived from our audited financial statements. The historical financial data for the nine months ended September 30, 2004 and 2005 and the balance sheet data as of September 30, 2005 are derived from our unaudited financial statements included in this prospectus. The pro forma statement of operations data gives effect to the acquisitions of the properties acquired from Mountain V Oil & Gas, Inc. and Pentex Energy, Inc. in 2004 and Exploration Partners, LLC in 2005 as if they occurred on January 1, 2004. The pro forma balance sheet data gives effect to the acquisition of the properties acquired from Exploration Partners, LLC in 2005 and this offering as if they occurred on September 30, 2005.

On October 31, 2003, we completed a $31.0 million acquisition of natural gas and oil assets from Waco Oil & Gas (Predecessor). The historical financial data for the period from January 1, 2003 through October 31, 2003 and the year ended December 31, 2002 have been derived from the audited financial statements of the Predecessor. The historical financial data for the years ended December 31, 2000 and 2001 and the balance sheet data as of December 31, 2000, 2001 and 2002 have been derived from the unaudited financial statements of the Predecessor.

You should read the following summary financial data in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our financial statements and related notes appearing elsewhere in this prospectus. You should also read the pro forma information together with the Unaudited Pro Forma Financial Statements and related notes included in this prospectus.

Because of our rapid growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

The following table presents a non-GAAP financial measure, adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measure calculated and presented in accordance with GAAP in "Non-GAAP Financial Measure" beginning on page 16.


															Successor
			Predecessor																					Nine Months Ended September 30,
			Year Ended December 31,									Period from January 1, 2003 through October 31, 2003			Period from March 14, 2003 (inception) through December 31, 2003			Year Ended December 31, 2004									2005
			2000			2001			2002			Period from January 1, 2003 through October 31, 2003						Historical			Pro Forma			2004			Historical			Pro Forma
			(unaudited)																		(unaudited)			(unaudited)
			(in thousands)															(in thousands)
Statement of Operations Data:
Revenues:
	Natural gas and oil sales		$	981		$	5,382		$	3,779		$	4,705		$	3,323		$	21,232		$	36,858		$	14,205		$	24,408		$	36,181
	Realized gain (loss) on natural gas derivatives(1)			—			—			—			—			163			(2,240	)		(2,240	)		(925	)		(45,822	)		(45,822	)
	Unrealized (loss) on natural gas derivatives(2)			—			—			—			—			(1,600	)		(8,765	)		(8,765	)		(10,890	)		(26,788	)		(26,788	)
	Natural gas marketing income			—			—			—			—			—			520			520			—			3,087			3,087
	Other income			660			1,488			698			788			4			160			160			86			158			158

		Total revenues		1,641			6,870			4,477			5,493			1,890			10,907			26,533			2,476			(44,957	)		(33,184	)

Expenses:
	Operating expenses			1,767			1,702			2,426			2,204			917			5,460			8,907			4,377			4,617			7,008
	Natural gas marketing expense			—			—			—			—			—			482			482			—			3,162			3,162
	General and administrative expenses			1,088			3,186			1,047			870			845			1,583			1,694			1,066			2,309			2,364
	Depreciation, depletion and amortization			964			1,152			1,494			1,185			972			3,749			10,405			2,408			3,736			8,196

		Total expenses		3,819			6,040			4,967			4,259			2,734			11,274			21,488			7,851			13,824			20,730

Other Income and (Expenses):
	Interest income			—			—			—			—			34			7			7			7			16			16
	Interest and financing expenses(3)			(392	)		(390	)		(352	)		(237	)		(517	)		(3,530	)		(8,866	)		(2,937	)		(3,282	)		(6,827	)
	Loss on equity investment			—			(57	)		(145	)		(63	)		(3	)		(56	)		(56	)		(42	)		(17	)		(17	)
	Write-off of deferred financing fees			—			—			—			—			—			—			—			—			(364	)		(364	)
	Gain (loss) on sale of assets			—			(111	)		(63	)		49			(5	)		(32	)		(32	)		(10	)		(43	)		(43	)

		Total other income and (expenses)		(392	)		(558	)		(560	)		(251	)		(491	)		(3,611	)		(8,947	)		(2,982	)		(3,690	)		(7,235	)

	Income (loss) before income taxes			(2,570	)		272			(1,050	)		983			(1,335	)		(3,978	)		(3,902	)		(8,357	)		(62,471	)		(61,149	)
	Income tax provision(4)			—			—			—			—			—			—			—			—			385			385
Income (loss) before cumulative effect of change in accounting principle				(2,570	)		272			(1,050	)		983			(1,335	)		(3,978	)		(3,902	)		(8,357	)		(62,856	)		(61,534	)
Cumulative effect of change in accounting principle				—			—			—			(757	)		—			—			—			—			—			—

Net income (loss)			$	(2,570	)		272			(1,050	)	$	226		$	(1,335	)	$	(3,978	)	$	(3,902	)	$	(8,357	)	$	(62,856	)	$	(61,534	)

(1): During the nine months ended September 30, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas swaps and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices.
(2): The natural gas swaps were not specifically designated as hedges under Statement of Financial Accounting Standards (SFAS) No. 133, even though they reduce our exposure to changes in natural gas prices. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these amounts represent non-cash charges.
(3): Includes the unrealized gain (loss) on interest rate swaps that were not specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to changes in interest rates. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these amounts represent non-cash items.
(4): Linn Operating, LLC was not subject to federal income tax before converting to a subchapter c-corporation on June 1, 2005. Prior to the conversion, there was no tax provision included in our consolidated financial statements because all of our taxable income or loss was included in the income tax returns of the individual members.


	Predecessor												Successor
										Period from January 1, 2003 through October 31, 2003			Period from March 14, 2003 (inception) through December 31, 2003
																			Nine Months Ended September 30,
	Year Ended December 31,
	Year Ended December 31,															Year Ended December 31, 2004
	2000			2001			2002									Year Ended December 31, 2004			2004			2005
	(unaudited)																		(unaudited)
	(in thousands)															(in thousands)
Cash Flow Data:
Net cash (used in) provided by operating activities(1)	$	(1,363	)	$	1,659		$	(40	)	$	1,826		$	929		$	11,381		$	7,018		$	(36,661	)
Net cash (used in) provided by investing activities		(1,687	)		(8,831	)		(1,480	)		10,880			(36,408	)		(62,402	)		(56,945	)		(28,309	)
Net cash provided by (used in) financing activities		2,829			7,473			1,056			(2,415	)		57,521			31,167			31,090			65,759
Capital expenditures	$	1,687		$	8,566		$	1,375		$	1,717		$	52,356		$	47,508		$	40,972		$	27,972
Other Financial Information (unaudited):
Adjusted EBITDA(2)													$	1,777		$	12,228		$	7,956		$	10,164


		Predecessor						Successor
		As of December 31,						As of December 31,				As of September 30, 2005
		2000		2001		2002		2003		2004		Historical			Pro Forma
		(unaudited)										(unaudited)
		(in thousands)						(in thousands)
Balance Sheet Data:
Cash and cash equivalents(3)		$	705	$	1,006	$	542	$	22,043	$	2,188	$	2,977		$	3,701
Other current assets			614		447		710		1,714		5,094		11,250			9,217
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization			5,844		12,831		12,829		53,036		97,123		121,178			237,517
Property, plant and equipment, net of accumulated depreciation			2,643		2,958		2,778		370		1,387		1,966			2,630
Other assets			—		208		168		2,486		542		6,216			6,216

	Total assets	$	9,806	$	17,450	$	17,027	$	79,649	$	106,334	$	143,587		$	259,281

Current liabilities		$	1,932	$	3,498	$	3,468	$	20,319	$	9,968	$	29,343		$	28,034
Long-term debt			3,388		2,686		1,919		41,518		72,750		138,975			132,275
Other long-term liabilities			—		—		—		3,123		12,905		27,414			29,117
Members' capital (deficit)			4,486		11,266		11,640		14,689		10,711		(52,145	)		69,855

	Total liabilities and members' capital	$	9,806	$	17,450	$	17,027	$	79,649	$	106,334	$	143,587		$	259,281

(1): During the nine months ended September 30, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas swaps and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices.
(2): See "Non-GAAP Financial Measure" on page 16.
(3): In December 2003, we borrowed approximately $18 million under our credit facility to pay the remaining purchase price for the Waco acquisition, which amount was paid to Waco on January 2, 2004.

SUMMARY RESERVE AND OPERATING DATA

The following tables show estimated net proved reserves, based on reserve reports prepared by our independent petroleum engineers (attached to this prospectus as Appendix C) and certain summary unaudited information with respect to our production and sales of natural gas and oil. You should refer to "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business — Natural Gas and Oil Data — Proved Reserves and Production and Price History" and the reserve report included in this prospectus in evaluating the material presented below.

			As of December 31,
			As of December 31,				As of September 30, 2005
			2003		2004		As of September 30, 2005
Reserve Data:
Estimated net proved reserves:
	Natural gas (Bcf)			68.9		118.9		188.2
	Oil (MMBbls)			0.2		0.1		0.2
		Total (Bcfe)		69.8		119.8		189.6
Proved developed (Bcfe)				41.8		74.4		124.9
Proved undeveloped (Bcfe)				28.0		45.4		64.7
Proved developed reserves as % of total proved reserves				59.9%		62.1%		65.9%
Standardized Measure (in millions)(1)			$	126.3	$	215.0	$	898.7
Representative Natural Gas and Oil Prices(2):
	Natural gas — NYMEX Henry Hub per MMBtu		$	5.97	$	6.18	$	15.36
	Oil — NYMEX WTI per Bbl			32.76		43.00		66.21

		Period from March 14, 2003 (inception) through December 31, 2003(3)
						Nine Months Ended September 30,
				Year Ended December 31, 2004		Nine Months Ended September 30,
				Year Ended December 31, 2004		2004		2005
Net Production:
	Total production (MMcfe)		802		3,385		2,288		3,240
	Average daily production (Mcfe/d)		3,748		9,274		8,350		11,868
Average Sales Prices per Mcfe:
	Average sales prices (including hedges)	$	5.07	$	5.74	$	5.54	$	6.27
	Average sales prices (excluding hedges)		4.87		6.43		5.95		7.62
Average Unit Costs per Mcfe:
	Operating expenses	$	1.14	$	1.61	$	1.91	$	1.43
	General and administrative expenses		1.05		0.47		0.47		0.71
	Depreciation, depletion and amortization		1.21		1.11		1.05		1.15

(1): Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Linn Energy Holdings, LLC, which is not subject to income taxes. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations" beginning on page 64.
(2): Natural gas and oil prices as of each period end were based on NYMEX prices per MMBtu and Bbl at such date, with these representative prices adjusted by field to arrive at the appropriate net price. As of December 31, 2004, our average realized natural gas prices, net of gathering fees, represented a $0.67 per Mcf premium to NYMEX natural gas prices. Due to NYMEX trading interruptions as a result of Hurricane Katrina on September 30, 2005, natural gas prices were based on the Appalachian spot prices per MMBtu at such date.
(3): In the period ended December 31, 2003, production commenced on May 30, 2003 following the purchase of natural gas properties from Emax Oil Company.

NON-GAAP FINANCIAL MEASURE

Adjusted EBITDA

We define adjusted EBITDA as net income (loss) plus:

•: Interest expense;
•: Depreciation, depletion and amortization;
•: Write-off of deferred financing fees;
•: (Gain) loss on sale of assets;
•: (Gain) loss from equity investment;
•: Accretion of asset retirement obligation;
•: Unrealized (gain) loss on natural gas swaps;
•: Realized (gain) loss on cancelled natural gas swaps; and
•: Income tax provision.

The costs of cancelling natural gas swaps before their original settlement date are the only adjustments to EBITDA that require expenditure of cash and were financed with borrowings under our credit facility and such long term debt is recognized as an increase in cash from financing activities. We do not anticipate cancelling any swap agreements prior to maturity following the consummation of this offering.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any reserves by our board of directors) the cash distributions we expect to pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

The following table presents a reconciliation of our consolidated net income (loss) to adjusted EBITDA:

											Nine Months Ended September 30,
		Period from March 14, 2003 (inception) through December 31, 2003
					Year Ended December 31, 2004
					Year Ended December 31, 2004									2005
					Historical			Pro Forma			2004			Historical			Pro Forma
								(unaudited)			(unaudited)
		(in thousands)
Net (loss)		$	(1,335	)	$	(3,978	)	$	(3,902	)	$	(8,357	)	$	(62,856	)	$	(61,534	)
Plus:
	Interest expense		517			3,530			8,866			2,937			3,282			6,827
	Depreciation, depletion and amortization		972			3,749			10,405			2,408			3,736			8,196
	Write-off of deferred financing fees		—			—			—			—			364			364
	Loss on sale of assets		5			32			32			10			43			43
	Loss from equity investment		3			56			56			42			17			17
	Accretion of asset retirement obligation		15			74			185			26			124			180
	Unrealized loss on natural gas derivatives		1,600			8,765			8,765			10,890			26,788			26,788
	Realized loss on cancelled natural gas derivatives(1)		—			—			—			—			38,281			38,281
	Income tax provision(2)		—			—			—			—			385			385

Adjusted EBITDA		$	1,777		$	12,228		$	24,407		$	7,956		$	10,164		$	19,547

(1): During the nine months ended September 30, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas swaps and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices.
(2): Linn Operating, LLC was not subject to federal income tax before converting to a subchapter c-corporation on June 1, 2005. Prior to the conversion, there was no tax provision included in our consolidated financial statements because all of our taxable income or loss was included in the income tax returns of the individual members.

RISK FACTORS

Membership interests in a limited liability company are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our units.

The following risks could materially and adversely affect our business, financial condition or results of operations. If any of the events described below were to occur, we may not be able to pay the initial quarterly distribution on our units, the trading price of our units could decline and you could lose part or all of your investment in our company.

Risks Related to Our Business

We may not have sufficient cash flow from operations to pay the initial quarterly distribution. We would have had significant shortfalls in recent periods and in 2006, absent expected borrowings of $17.9 million under our credit facility, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash generated from operations, to fund our drilling program and to pay our annualized initial quarterly distribution.

We may not have sufficient cash flow from operations each quarter to pay the initial quarterly distribution. We would have had significant shortfalls in recent periods and in 2006, absent expected borrowings of $17.9 million under our credit facility, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash generated from operations, to fund our drilling program and to pay the annualized initial quarterly distribution of $44.5 million. The amount borrowed would constitute approxmiately 40.2% of our annual distribution in 2006. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•: the amount of natural gas we produce;
•: the price at which we are able to sell our natural gas production;
•: the level of our operating costs;
•: the level of our interest expense which depends on the amount of our indebtedness and the interest payable thereon; and
•: the level of our capital expenditures.

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

•: the level of our capital expenditures;
•: our ability to make working capital borrowings under our credit facility to pay distributions;
•: the cost of acquisitions, if any;
•: our debt service requirements;

•: fluctuations in our working capital needs;
•: timing and collectibility of receivables;
•: restrictions on distributions contained in our credit facility;
•: prevailing economic conditions; and
•: the amount of cash reserves established by our board of directors for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than the initial quarterly distribution amount that we expect to distribute.

The amount of available cash we will need to pay the initial quarterly distribution for four quarters on the units to be outstanding immediately after this offering is $44.5 million. If we had completed the transactions contemplated in this prospectus on January 1, 2004, pro forma available cash generated during the year ended December 31, 2004 would have been approximately $3.6 million. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 8% of the initial quarterly distributions on our units during this period. If we had completed the transactions contemplated in this prospectus on October 1, 2004, pro forma cash available to pay distributions generated during the twelve-month period ended September 30, 2005 would have been approximately $0.2 million. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 1% of the initial quarterly distributions on our units during this period. For a calculation of our ability to make distributions to you based on our pro forma results for the year ended December 31, 2004, please read "Cash Distribution Policy and Restrictions on Distributions" included elsewhere in this prospectus.

We will be prohibited from borrowing under our credit facility to pay distributions to unitholders if the amount of borrowings outstanding under our credit facility reaches or exceeds 90% of the borrowing base, which is the amount of money available for borrowing, as determined semi-annually by our lenders in their sole discretion. The lenders will redetermine the borrowing base based on an engineering report with respect to our natural gas reserves, which will take into account the prevailing natural gas prices at such time. Any time our borrowings exceed 90% of the then specified borrowing base, our ability to pay distributions to our unitholders in any such quarter is solely dependent on our ability to generate sufficient cash from our operations. Giving effect of the use of the net proceeds from this offering, as of November 30, 2005 our borrowings under the credit facility would have been $145.0 million, or approximately 64% of our current borrowing base of $225.0 million.

We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions in the amount of the initial quarterly distribution.

Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile and we cannot predict the prices we will be able to realize for our production in the future. As a result, we may continue to borrow significant amounts under our credit facility in the future to enable us to pay quarterly distributions at current levels. Significant declines in our production or significant declines in realized natural gas prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.

If we are unable to achieve the Estimated Adjusted EBITDA set forth in "Cash Distribution Policy and Restrictions on Distributions" and cannot borrow the required amounts we may be unable to pay the full, or any, amount of the initial quarterly distribution on the units, in which event the market price of our units may decline substantially.

The Estimated Adjusted EBITDA set forth in "Cash Distribution Policy and Restrictions on Distributions" is for the year ending December 31, 2006. Our management has prepared this information and we have not received an opinion or report on it from any independent accountants. In addition, "Cash Distribution Policy and Restrictions on Distributions" includes a calculation of Estimated Adjusted EBITDA. The assumptions underlying this calculation are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those expected. If we do not achieve the expected results or cannot borrow the amounts needed, we may not be able to pay the full, or any, amount of the initial quarterly distribution, in which event the market price of our units may decline substantially.

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

Our revenue, profitability and cash flow depend upon the prices and demand for natural gas. The natural gas market is very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

•: the domestic and foreign supply of and demand for natural gas;
•: 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 natural gas and oil producing countries, including those in the Middle East and South America;
•: the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•: the impact of the U.S. dollar exchange rates on natural gas and oil prices;
•: technological advances affecting energy consumption;
•: domestic and foreign governmental regulations and taxation;
•: the impact of energy conservation efforts;
•: the proximity and capacity of natural gas pipelines and other transportation facilities; and
•: the price and availability of alternative fuels.

In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2004, the NYMEX natural gas index price ranged from a high of $8.21 per MMBtu to a low of $4.49 per MMBtu. During the

nine months ended September 30, 2005, the NYMEX natural gas index price ranged from a high of $14.50 to a low of $5.17.

Lower natural gas prices may not only decrease our revenues, but also reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management's plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility, which may adversely affect our ability to make cash distributions to our unitholders.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our cash flow from operations and our ability to make distribution to our unitholders.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our September 30, 2005 reserve report, our average decline rate for proved developed producing reserves is 8% during the first five years, 5% in the next five years and less than 4% thereafter. Because total estimated proved reserves include our proved undeveloped reserves at September 30, 2005, production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of natural gas in an exact way. Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our independent petroleum engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically

recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per Mcf, then the Standardized Measure of our proved reserves as of September 30, 2005 would decrease from $898.7 million to $831.4 million. Our Standardized Measure is calculated using unhedged natural gas prices and is determined in accordance with the rules and regulations of the Securities and Exchange Commission. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from our reserve estimates.

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

•: actual prices we receive for natural gas;
•: the amount and timing of actual production;
•: supply of and demand for natural gas; and
•: changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

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

The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of natural gas reserves. These expenditures will reduce our cash available for distribution. To date, we have financed capital expenditures primarily with equity capital contributions from existing investors, proceeds from bank borrowings and cash flow from operations. We intend to finance our future capital expenditures with cash flow from operations and our financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:

•: our proved reserves;
•: the level of natural gas we are able to produce from existing wells;
•: the prices at which our natural gas are sold; and
•: our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our revolving credit facility restricts our ability to obtain new financing. If additional capital is

needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves.

Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.

Although we gather more than 90% of our current production, the marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could reduce our revenues and cash available for distribution.

We depend on certain key customers for sales of our natural gas. To the extent these and other customers reduce the volumes of natural gas they purchase from us, our revenues and cash available for distribution could decline.

For the year ended December 31, 2004, Dominion Field Services, Inc., Cabot Oil & Gas Corporation, PG Energy Inc., Equitable Resources, Inc. and Amerada Hess Corporation accounted for approximately 33%, 19%, 16%, 13% and 9%, respectively, of our total volumes, or 90% in the aggregate. For the nine months ended September 30, 2005, sales of natural gas to Dominion, Cabot, Equitable, UGI Energy Services, and Amerada Hess accounted for approximately 46%, 21%, 11%, 8% and 6%, respectively, of our total volumes, or 92% in the aggregate. To the extent these and other customers reduce the volumes of natural gas that they purchase from us, our revenues and cash available for distribution could decline.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

Higher natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

Because we handle natural gas and other petroleum products, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operations of our wells, gathering systems, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

•: the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;
•: the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;
•: the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and
•: the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as "Superfund," and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of our wells or gathering pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance. Please read "Business — Operations — Environmental Matters and Regulation."

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

Our ability to grow and to increase distributions to unitholders is partially dependent on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because we are:

•: unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
•: unable to obtain financing for these acquisitions on economically acceptable terms; or
•: outbid by competitors.

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

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

•: mistaken assumptions about revenues and costs, including synergies;
•: an inability to integrate successfully the businesses we acquire;
•: the assumption of unknown liabilities;
•: limitations on rights to indemnity from the seller;
•: the diversion of management's attention from other business concerns; and
•: customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly. Further, our future acquisition costs may be higher than those we have achieved historically.

We have a limited operating history and a limited history of operating the assets we have acquired. Since our determination as to whether we will have sufficient available cash to pay the initial quarterly distribution is based on our limited operating history, our actual results may not allow us to make cash distributions at expected levels.

In considering whether to invest in our units, you should consider that we commenced our operations in March 2003, and there is only limited historical financial and operating information available on which to base your evaluation of our performance. Further, since we have rapidly grown through acquisitions and development of our properties, we have a limited history of operating these newly acquired assets and therefore have a limited historical basis upon which to rely in our determination as to whether we will have sufficient available cash to pay the initial quarterly distribution.

We have incurred losses from operations since our inception and may continue to do so in the future, which may impact our ability to pay distributions to our unitholders.

We incurred net losses of $1.3 million and $4.0 million in the periods from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004, respectively, and $8.4 million and $62.9 million for the nine months ended September 30, 2004 and 2005, respectively, and we may generate losses in the future, which may impact our ability to generate sufficient cash flow from operations to pay quarterly distributions to our unitholders at expected levels.

Locations that we decide to drill may not yield natural gas in commercially viable quantities.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough to be commercially viable after drilling, operating and other costs. From inception through November 30, 2005, we participated in the drilling of a total of 191 wells resulting in all wells producing natural gas in commercial quantities. If we drill future wells that we identify as dry holes, our drilling success rate would decline and may materially harm our business.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

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

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

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of September 30, 2005, we had identified 362 proved undeveloped drilling locations and over 500 additional drilling locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. In addition, Schlumberger Data and Consulting Services has not assigned any proved reserves to the over 500 unproved drilling locations we have identified and scheduled for drilling and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Drilling for and producing natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

•: the high cost, shortages or delivery delays of equipment and services;
•: unexpected operational events;
•: adverse weather conditions;
•: facility or equipment malfunctions;
•: title problems;
•: pipeline ruptures or spills;
•: compliance with environmental and other governmental requirements;
•: unusual or unexpected geological formations;
•: loss of drilling fluid circulation;

•: formations with abnormal pressures;
•: fires;
•: blowouts, craterings and explosions; and
•: uncontrollable flows of natural gas or well fluids.

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions to our unitholders.

We will depend on our revolving credit facility for future capital needs and to fund a portion of our distributions. The revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility could result in a default under our credit facility, which could cause all of our existing indebtedness to be immediately due and payable.

The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the borrowing base requires the consent of all the lenders. If the required lenders do not agree on an increase, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66²/3% of the commitments. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Natural gas operations in the Appalachian Basin are adversely affected by seasonal weather conditions, primarily in the spring. Many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This limits our access to these jobsites and our ability to service wells in these areas.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, our reviews of acquired properties are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Our hedging activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas, we currently and may in the future enter into hedging arrangements for a significant portion of our natural gas production. For example, during 2003 and 2004, our average unhedged or sales price for natural gas was $4.87 per Mcf and $6.43 per Mcf, respectively, and our average realized price for natural gas was $5.07 per Mcf and $5.74 per Mcf, respectively, resulting in hedging income of $0.2 million in 2003 and losses of $2.2 million in 2004. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge. Under our credit facility, we are prohibited from hedging all of our production, and we therefore retain the risk of a price decrease on our unhedged volumes.

We depend on our President and Chief Executive Officer who would be difficult to replace.

We depend on the performance of Michael C. Linn, our President and Chief Executive Officer. We maintain no key person insurance for Mr. Linn. The loss of our President and Chief Executive Officer could negatively impact our ability to execute our strategy and our results of operations.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to

lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

The natural gas and oil industry is intensely competitive, and we compete with other companies that have greater resources. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce natural gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low natural gas and oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

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

Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. For example, West Virginia has, beginning 2005, increased its severance tax rate. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry who can spread these additional costs over a greater number of wells and larger operating staff. Please read "Business — Operations — Environmental Matters and Regulation" and "Business — Operations — Other Regulation of the Natural Gas and Oil Industry" for a description of the laws and regulations that affect us.

Risks Related to Our Structure

Our management and Quantum Energy Partners will own, in the aggregate, a controlling interest in us, with management and Quantum Energy Partners owning approximately 17.5% and 39.2%, respectively, of our units.

Upon completion of this offering, our management and Quantum Energy Partners will own or control an aggregate 56.7% of the outstanding units, or 50.6% if the underwriters' option to purchase additional units is exercised in full. Accordingly, management and Quantum Energy Partners, acting together, will possess a controlling vote on all matters submitted to a vote of the holders of our units. As long as management and Quantum Energy Partners in the aggregate beneficially own a controlling interest in us, they will have the ability to elect all members of our board of directors and to control our management and affairs. Our management and Quantum Energy Partners will be able to cause a change of control of our company. This concentration of ownership may have the effect of preventing or discouraging transactions involving an actual or a potential change of control of our company, regardless of whether a premium is offered over then-current market prices.

Each of management or Quantum Energy Partners, or both, may have conflicts of interest with us. Our limited liability company agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.

Following the offering, one member of our board of directors will be an affiliate of Quantum Energy Partners. Conflicts of interest may arise between our management or Quantum Energy Partners, and us and our unitholders. These potential conflicts may relate to the divergent interests of our management or Quantum Energy Partners. Situations in which the interests of our management or Quantum Energy Partners may differ from interests of owners of units include, among others, the following situations:

•: our limited liability company agreement gives our board of directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our management will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;
•: our management team determines the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuances of additional membership interests and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders; and
•: Quantum Energy Partners and other affiliates of our directors are not prohibited from investing or engaging in other businesses or activities that compete with us.

Our limited liability company agreement prohibits a unitholder who acquires 15% or more of our units without the approval of our board of directors from engaging in a business combination with us for three years. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our units.

Our limited liability company agreement effectively adopts Section 203 of the Delaware General Corporation Laws, or the DGCL. Section 203 of the DGCL as it applies to us prevents an interested unitholder, defined as a person who owns 15% or more of our outstanding units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder. Section 203 broadly defines "business combination" to

encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our limited liability company agreement could have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for our units.

You will experience immediate and substantial dilution of $17.49 per unit.

The initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $2.51 per unit. Based on the initial public offering price, you will incur immediate and substantial dilution of $17.49 per unit. The main factor causing dilution is that our management, Quantum Energy Partners and non-affiliated investors acquired interests in us at equivalent per unit prices lower than the public offering price. Please read "Dilution."

We may issue additional units without your approval, which would dilute your existing ownership interests.

We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.

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

•: your proportionate ownership interest in us may decrease;
•: the amount of cash distributed on each unit may decrease;
•: the relative voting strength of each previously outstanding unit may be diminished; and
•: the market price of the units may decline.

Our limited liability company agreement provides for a limited call right that may require you to sell your units at an undesirable time or price.

If, at any time, any person owns more than 90% of the units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining units then outstanding at a price not less than the then-current market price of the units. As a result, you may be required to sell your units at an undesirable time or price and therefore may receive a lower or no return on your investment. You may also incur tax liability upon a sale of your units. For additional information about the call right, please read "The Limited Liability Company Agreement — Limited Call Right."

Unitholders may have limited liquidity for their units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price.

Prior to the offering, there has been no public market for the units. After the offering, there will be 11,750,000 publicly traded units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the units and limit the number of investors who are able to buy the units.

If our unit price declines after the initial public offering, you could lose a significant part of your investment.

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

•: changes in securities analysts' recommendations and their estimates of our financial performance;
•: the public's reaction to our press releases, announcements and our filings with the Securities and Exchange Commission;
•: fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly traded limited partnerships and limited liability companies;
•: changes in market valuations of similiar companies;
•: departures of key personnel;
•: commencement of or involvement in litigation;
•: variations in our quarterly results of operations or those of other natural gas and oil companies;
•: variations in the amount of our quarterly cash distributions;
•: future issuances and sales of our units; and
•: changes in general conditions in the U.S. economy, financial markets or the natural gas and oil industry.

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

Quantum Energy Partners may sell units in the future, which could reduce the market price of our outstanding units.

Following the completion of this offering, Quantum Energy Partners will control an aggregate of 10,914,228 units. In addition, we have agreed to register for sale units held by Quantum Energy Partners, non-affiliated investors and our management. These registration rights allow Quantum Energy Partners to request registration of their units and to include any of those units in a registration of other securities by us. If Quantum Energy Partners were to sell a substantial portion of their units, it could reduce the market price of our outstanding units. Please also read "Material Tax Consequences — Disposition of Units — Constructive Termination."

Tax Risks to Unitholders

You should read "Material Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level

taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the costs of any contest will reduce cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.

Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S.

persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

Because we cannot match transferors and transferees of units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of units and could have a negative impact on the value of our units or result in audits of and adjustments to our unitholders' tax returns. Please read "Material Tax Consequences — Uniformity of Units" for a further discussion of the effect of the depreciation and amortization positions we will adopt.

You may be subject to state and local taxes and return filing requirements.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if you do not reside in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially do business and own assets in Pennsylvania, West Virginia, New York and Virginia. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the units.

Tax gain or loss on the disposition of our units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your units.

If you sell any of your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Prior distributions to you in excess of the total net taxable income you were allocated for a unit, which decreased your tax basis in that unit, will, in effect, become taxable income to you if the unit is sold at a price greater than your tax basis in that unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

•: business strategy;
•: financial strategy;
•: drilling locations;
•: natural gas and oil reserves;
•: realized natural gas and oil prices;
•: production volumes;
•: lease operating expenses, general and administrative expenses and finding and development costs;
•: future operating results; and
•: plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the "Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business" and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "could," "should," "expect," "plan," "project," "intend," "anticipate," "believe," "estimate," "predict," "potential," "pursue," "target," "continue," the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the "Risk Factors" section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

USE OF PROCEEDS

We expect to receive net proceeds of $218.6 million from the sale of 11,750,000 units offered by this prospectus, after deducting estimated underwriting discounts. Our estimates assume an initial offering price of $20.00 per unit and no exercise of the underwriters' option to purchase additional units.

We anticipate using the net proceeds of this offering to:

•: repay $122.0 million of the currently outstanding $267.0 million of indebtedness under our revolving credit facility;
•: redeem $84.7 million of membership interests from Quantum Energy Partners;
•: redeem $2.2 million of membership interests from certain non-affiliated investors;
•: redeem $3.0 million of membership interests from Michael C. Linn; and
•: pay $6.7 million of expenses associated with this offering.

The $6.7 million of expenses associated with this offering include one-time bonuses payable to Michael C. Linn, our President and Chief Executive Officer, and Kolja Rockov, our Executive Vice President and Chief Financial Officer, upon completion of this offering. For a more detailed discussion of these bonuses, please read "Management — Employment Agreements."

As of November 30, 2005, we had $267.0 million outstanding under our credit facility and subordinated term loan. We used the borrowings under the credit facility and the new subordinated term loan to:

•: repay all outstanding amounts under our previous credit facility, which we used to finance our acquisitions and meet working capital requirements;
•: repay a $5.0 million subordinated term loan from First National Bank Albany Breckenridge;
•: pay expenses incurred in connection with the closing of the new credit facility in April 2005;
•: fund the $4.3 million purchase price of assets from Columbia Natural Resources, LLC;
•: fund the $5.4 million purchase price of GasSearch Corporation;
•: pay $38.3 million in connection with the cancelled (before their original settlement date) portion of out-of-the-money natural gas hedges; and
•: fund the $115.3 million purchase price of the assets from Exploration Partners, LLC.

We will use any net proceeds from the exercise of the underwriters' option to purchase additional units to redeem the number of units from Quantum Energy Partners and non-affiliated investors equal to the number of units issued upon exercise of that option. If the underwriters' option is exercised in full, Quantum Energy Partners' ownership of units will be reduced from 10,914,228 units to 9,195,973 units, reducing Quantum Energy Partners' ownership in us from 39.2% to 33.1%.

An affiliate of RBC Capital Markets Corporation, an underwriter for this offering, is a lender under our revolving credit facility and the new subordinated term loan and will be partially and fully, respectively, repaid with a portion of the net proceeds from this offering. Please read "Underwriting."

CAPITALIZATION

The following table shows:

•: our historical capitalization as of September 30, 2005;
•: our pro forma capitalization as of September 30, 2005, giving effect to the debt incurred in connection with the acquisition from Exploration Partners as described under "Use of Proceeds;" and
•: our pro forma capitalization as of September 30, 2005 adjusted to reflect the offering of the units and the application of the net proceeds we expect to receive as described under "Use of Proceeds."

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and unaudited consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

			As of September 30, 2005 (unaudited)
			Historical			Pro Forma			Pro Forma as adjusted
			(in thousands)
Cash and cash equivalents			$	2,977		$	2,977		$	2,977

	Credit facility		$	138,278		$	193,578	(1)	$	131,578	(2)
	Subordinated term loan			—			60,000	(1)		—
	Other long-term debt			697			697			697

		Total long-term debt and other obligations		138,975			254,275			132,275
	Total members' capital (deficit)(3)(4)			(52,145	)		(52,145	)		69,855

		Total capitalization	$	86,830		$	202,130		$	202,130

(1): Includes debt incurred in connection with the Exploration Partners acquisition.
(2): Historical balance reduced by $122.0 million of net proceeds from this offering which were used to repay debt.
(3): Includes realized loss of $38.3 million from cancelled natural gas swaps and unrealized loss of $26.8 million on natural gas swaps.
(4): The capital account on a historical basis increased by $122.0 million of net proceeds from this offering which were used to repay debt.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of units sold in this offering will exceed the net tangible book value per unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $20.00 per unit, on a pro forma basis as of September 30, 2005, after giving effect to the offering of units and the application of the related net proceeds, our net tangible book value was $69.8 million, or $2.51 per unit. Purchasers of units in this offering will experience substantial and immediate dilution in net tangible book value per unit for accounting purposes, as illustrated in the following table:

Assumed initial public offering price per unit					$	20.00
	Pro forma net tangible book value per unit before the offering(1)	$	(3.25	)
	Increase in net tangible book value per unit attributable to purchasers in the offering		5.76

Less: Pro forma net tangible book value per unit after the offering(2)						2.51

Immediate dilution in net tangible book value per unit to new investors					$	17.49

(1): Determined by dividing the total number of units to be issued to our management, Quantum Energy Partners and non-affiliated investors (16,062,500 units) in exchange for their membership interest into our net tangible book value.
(2): Determined by dividing the total number of units to be outstanding after this offering (27,812,500 units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of this offering.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our management, Quantum Energy Partners and non-affiliated investors upon consummation of the transactions contemplated by this prospectus:

		Units Acquired			Total Consideration
		Number	Percent		Amount (in millions)			Percent
Our management, Quantum Energy Partners and non-affiliated investors(1)		16,062,500	57.7	%	$	(52.1	)	(28.5	)%
New investors		11,750,000	42.3	%		235.0		128.5	%

	Total	27,812,500	100.0	%	$	182.9		100.0	%

(1): The total consideration is equal to the net tangible book value as of September 30, 2005 contributed by our management, Quantum Energy Partners and non-affiliated investors.

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please see "— Assumptions and Considerations" below.

General

Rationale for our Cash Distribution Policy

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it. The amount of available cash will be determined by our board of directors for each calendar quarter of our operations after the closing of this offering. Our cash distribution policy is consistent with the terms of our limited liability company agreement, which requires that we distribute all of our available cash on a quarterly basis. Please read "How We Make Cash Distributions." Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to such tax.

Limitations on Our Ability to Make Quarterly Distributions

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and may become subject to limitations and restrictions, including:

•: Our board of directors will have broad discretion to establish reserves for the prudent conduct of our business. The establishment of those reserves could result in a reduction in the amount of cash available to pay distributions.
•: Due to the nature of our business which requires a significant amount of capital expenditures to maintain and grow production levels combined with the potential volatility of realized natural gas prices, we may not be able to achieve a level of cash flow from operations that allows us to maintain a growth-oriented drilling program without incurring borrowings for such capital expenditures. Our ability to meet the initial quarterly distribution of $0.40 is primarily dependent on levels of production and the natural gas prices we are able to realize for such production. As a result, we expect not to be able to meet our expected distributions without continuing to borrow significant amounts under our credit facility for the foreseeable future. While we enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations, natural gas prices have been and are anticipated to be volatile.
•: Our ability to make distributions of available cash will depend primarily on our cash flow from operations which primarily depends on our level of production and our realized natural gas prices. Although our limited liability company agreement provides for quarterly distributions of available cash, we have no prior history of making distributions to our members.
•: We will be prohibited from borrowing under our credit facility to make distributions to unitholders if the amount of borrowing outstanding under our credit facility reaches or exceeds 90% of the borrowing base. Further, we may enter into future debt arrangements

that could subject our ability to pay distributions to compliance with certain tests or ratios or otherwise restrict our ability to pay distributions.

•: Since we have rapidly grown through acquisitions and development of our properties, we have a limited history of operating these newly acquired assets and therefore have a limited historical basis upon which to rely in our determination as to whether we will have sufficient available cash to pay the initial quarterly distribution.
•: Under Section 18-607 of the Delaware Limited Liability Company Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.
•: Although our limited liability company agreement requires us to distribute our available cash, our limited liability company agreement, including the provisions requiring us to make cash distributions contained therein, may be amended with the approval of a majority of the outstanding units. Following completion of this offering, our management and Quantum Energy Partners will own approximately 17.5% and 39.2%, respectively, of the outstanding units (17.5% and 33.1% respectively, assuming full exercise of the underwriters' option to purchase additional units) and acting jointly will therefore have the ability to amend the limited liability company agreement.

Our Cash Distribution Policy May Limit Our Ability to Grow

Because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. We generally intend to rely upon external financing sources, including borrowings and issuances of debt and equity securities, to fund a substantial portion of our acquisition and drilling capital expenditures. However, to the extent we are unable to finance these expenditures externally, our cash distribution policy will significantly impair our ability to grow.

Our Cash Distribution Policy

Our limited liability company agreement, as amended to be effective at the closing of this offering, provides for the distribution of available cash on a quarterly basis. Available cash, which is defined in the limited liability company agreement attached as Appendix A and the glossary attached as Appendix B hereto, for any quarter consists of cash on hand at the end of that quarter, plus working capital borrowings made after the end of the quarter, less cash reserves, which may include reserves to provide for our future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. Please read "How We Make Cash Distributions — Definition of Available Cash." The amount of available cash will be determined by our board of directors for each calendar quarter of our operations after the closing of this offering. Our limited liability company agreement may only be amended with the approval of a unit majority.

Cash Distributions

Overview

We expect that the amount of the initial quarterly distribution will be $0.40 per unit, or $1.60 per year. The amount of available cash, which we also refer to as cash available to pay

distributions, needed to pay the initial quarterly distribution on all of the units to be outstanding immediately after this offering for one quarter and for four quarters will be approximately:

		Initial Quarterly Distribution
	Number of Units	Initial Quarterly Distribution
	Number of Units	One Quarter		Four Quarters
Units	27,812,500	$	11,125,000	$	44,500,000

The amounts in the table above will not change upon any exercise by the underwriters of their option to purchase additional units.

The following table sets forth the assumed number of units outstanding upon closing of this offering and the estimated aggregate distribution amounts to be paid on such units with respect to the year ending December 31, 2006 at our annualized initial quarterly distribution of $1.60 per unit.

		Number of Units	Amount
Distributions to public unitholders		11,750,000	$	18,800,000
Distributions to non-affiliated equity investors		281,037		449,659
Distributions to Quantum Energy Partners		10,914,228		17,462,765
Distributions to management		4,867,235		7,787,576

	Total distributions paid	27,812,500	$	44,500,000

Our Initial Distribution Rate

We expect to pay the initial quarterly distribution on all of our outstanding units for each quarter through December 31, 2006. Within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2005, we will distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the initial quarterly distribution for the period from the closing of the offering through December 31, 2005 based on the actual length of the period.

In the sections that follow, we present in detail the basis for our belief that we will have sufficient available cash to pay the initial quarterly distribution on all of our outstanding units for each quarter through December 31, 2006. In those sections, we present two tables:

•: "Estimated Adjusted EBITDA," in which we present certain operating and financial assumptions for the year ending December 31, 2006; and
•: "Unaudited Pro Forma Cash Available to Pay Distributions," in which we present the amount of available cash we would have generated on a pro forma basis in 2004 and on a pro forma basis for the twelve-month period ended September 30, 2005.

Our pro forma available cash for 2004 and pro forma for the twelve-month period ended September 30, 2005 would not have been sufficient to pay the full annualized initial quarterly distribution of $1.60 per unit on all units to be outstanding following the completion of this offering.

If we had completed the transactions contemplated in this prospectus on January 1, 2004, pro forma cash available to pay distributions generated during 2004 would have been approximately $3.6 million. This figure also gives effect to the properties acquired from Mountain V Oil & Gas, Inc., Pentex Energy, Inc. and Exploration Partners, LLC as if they occurred on January 1, 2004 and the $122.0 million debt repayment from the proceeds of this offering. If we had completed the transactions contemplated in this prospectus on October 1, 2004, pro forma cash available to pay distributions generated during the twelve-month period ended September 30, 2005

would have been approximately $0.2 million. These amounts of pro forma cash available to pay distributions would not have been sufficient to allow us to pay the full annualized initial quarterly distribution on all of our units for 2004 or the twelve-month period ended September 30, 2005. For the year ending December 31, 2006, absent expected borrowings of $17.9 million under our credit facility, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash flow generated from operations, to fund our drilling program and to pay distributions at our initial distribution rate. The amount borrowed would constitute approximately 40.2% of our annual distribution for 2006. The amount of borrowings available is dependent on the borrowing base, which is in the sole discretion of the lenders. Please read "Risk Factors — Risks Related to Our Business — Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions" on page 26.

Pro forma cash available to pay distributions excludes any cash from working capital or other borrowings and cash on hand as of the closing date of this offering.

As a result of the factors described in "— Estimated Adjusted EBITDA" and "— Assumptions and Considerations" below, we believe we will be able to pay the initial quarterly distribution of $0.40 per unit on all units for each quarter from the closing of this offering through December 31, 2006.

Estimated Adjusted EBITDA

In order to fund the initial quarterly distribution of $0.40 per unit for the year ending December 31, 2006, our cash available to pay distributions must be at least $44.5 million over that period. We have calculated the estimated adjusted EBITDA for the year ending December 31, 2006, necessary to generate cash available to pay the initial quarterly distribution over that period, which we refer to as the Estimated Adjusted EBITDA.

We define adjusted EBITDA as net income (loss) plus:

•: Interest expense;
•: Depreciation, depletion and amortization;
•: Write-off of deferred financing fees;
•: (Gain) loss on sale of assets;
•: (Gain) loss from equity investment;
•: Accretion of asset retirement obligation;
•: Unrealized (gain) loss on natural gas swaps;
•: Realized (gain) loss on cancelled natural gas swaps; and
•: Income tax provision.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any reserves by our board of directors) the cash distributions we expect to pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

In the table below entitled "Estimated Adjusted EBITDA," we calculate that our Estimated Adjusted EBITDA must be approximately $69.9 million for the year ending December 31, 2006 for us to be able to generate cash available to pay distributions of $44.5 million assuming borrowings of $17.9 million. Absent those borrowings, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash generated from operations, to fund our drilling program and pay our annualized initial quarterly distribution. Although we believe that we will be able to achieve these results based on the assumptions and considerations set forth later in this section, we can give you no assurance that we will actually generate the Estimated Adjusted EBITDA and estimated cash available needed to pay the initial quarterly distribution through December 31, 2006. There will likely be differences between these amounts and our actual results and those differences could be material. If we are not able to achieve the Estimated Adjusted EBITDA described above, and if we are not able to borrow $17.9 million under our credit facility as contemplated, we may not be able to pay the full initial quarterly distribution or any amount on our outstanding units.

In calculating the Estimated Adjusted EBITDA, we have included estimates of drilling capital expenditures for the years ending December 31, 2005 and 2006. The Estimated Adjusted EBITDA includes our assumption that we will make $33.4 million of capital expenditures including the drilling of 139 gross (134 net) wells during the year ending December 31, 2006 that will be funded through a combination of cash flow from operations and borrowings under our credit facility. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business."

You should read "— Assumptions and Considerations" below for a discussion of the material assumptions underlying our belief that we will be able to generate the Estimated Adjusted EBITDA in the amount disclosed for the year ending December 31, 2006. Our belief is based on certain assumptions and reflects our judgment, as of the date of this prospectus, regarding conditions we expect to exist and the course of action we expect to take over the years ending December 31, 2005 and 2006. The assumptions we disclose are those that we believe are significant to our ability to generate the Estimated Adjusted EBITDA. If these estimates prove to be materially incorrect, we may not be able to pay the full initial quarterly distribution or any amount on our outstanding units.

Our calculation of Estimated Adjusted EBITDA for the year ending December 31, 2006 has been prepared by our management. Our independent auditors have not examined, compiled, or otherwise applied procedures to our Estimated Adjusted EBITDA for the year ending December 31, 2006 and, accordingly, do not express an opinion or any other form of assurance on this estimate.

When considering our Estimated Adjusted EBITDA for the year ending December 31, 2006, you should keep in mind the risk factors and other cautionary statements under the heading "Risk Factors" beginning on page 17. Any of the risk factors discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in the table below. In addition, we do not undertake any obligation to release publicly the results of any future revisions we may make to these estimates or to update these estimates to reflect events or circumstances after the date of this prospectus. Therefore, we caution you not to place undue reliance on this information.

Linn Energy, LLC
Estimated Adjusted EBITDA

		Year Ending December 31, 2006
		(in thousands, except per unit amounts)
Estimated Adjusted EBITDA		$	69,897
Less:
	Cash interest expense (a)		(9,897	)
	Capital expenditures (b)		(33,400	)
Plus:
	Borrowings (c)		17,900

Minimum cash available to pay distributions		$	44,500

Estimated cash distributions:
	Annualized initial quarterly distribution per unit	$	1.60

	Distributions to public unitholders	$	18,800
	Distributions to non-affiliated equity investors		448
	Distributions to Quantum Energy Partners		17,464
	Distributions to management		7,788

	Total estimated cash distributions	$	44,500

(a): Cash interest expense is based on our assumed average debt balance of $154.4 million (including the $17.9 million of borrowings described in footnote (c) below) to be outstanding during the period under our credit facility and related interest costs in accordance with the terms of the credit facility. The weighted average interest rate is assumed to be 6.4%. We do not intend to maintain cash reserves in excess of anticipated interest expense. We believe that the amount included in our forecast is sufficient. Should actual expenses be higher, we believe that we will have sufficient capacity under our credit facility.
(b): We expect to drill 139 gross (134 net) wells for the year ending December 31, 2006 at an average cost of $250,000 with expected reserves of 200 MMcfe per well. Total capital expenditures are expected to be $33.4 million. We expect to fund these capital expenditures with a combination of borrowings from our credit facility and $15.5 million from cash flow from operations. See footnote (c) below.
(c): We expect to borrow $17.9 million from our credit facility. Absent those borrowings, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash generated from operations, to fund our drilling program and to pay our annualized initial quarterly distribution.

The following table sets forth, on a quarterly basis, our historical results for the first three quarters of 2005, our forecast for the fourth quarter of 2005 and our forecast for each of the four quarters of 2006. Our forecasted levels of Estimated Adjusted EBITDA for each quarter of 2006 are based on the level of drilling activity and level of anticipated borrowings as set forth in the quarterly table on page 46. As further set forth in the table on page 46, we do not assume for purposes of our forecast that we will make any acquisitions in 2006, however, we assume a level of drilling activity which will be 26%, or 29 wells, higher than our 2005 drilling activity. As a result of our 2006 drilling program, we anticipate increasing our current average daily production of 21.6 MMcfe per day by 20% to a forecasted 26.2 MMcfe/d in the fourth quarter of 2006. Based on these current and expected production volumes, and absent any significant delays during the remainder of 2005 and our 2006 drilling program, and based on our forecasted production hedged at an average of 94%, we believe we will be able to make anticipated distributions in 2006 if we borrow $17.9 million under our credit facility. As long as our drilling capital expenditures are at a level intended to create growth in production, we do not anticipate that we will achieve levels of operating cash flows in the foreseeable future that absent significant borrowings under our credit facility will allow us to fund both our anticipated drilling capital expenditures and our anticipated cash distributions. We therefore anticipate aggregate borrowings of $17.9 million under our credit facility to cover the shortfall in the amount of cash necessary to fund both our 2006 drilling program and the full amount of our anticipated distributions for 2006. In addition, we expect that our estimated increases in our natural gas production and natural gas reserves will result in an increase in our borrowing base by at least the amount of the actual capital expenditures for drilling, which are estimated to be $33.4 million for the year ending December 31, 2006.


			Historical						Forecast
			Q1 2005		Q2 2005		Q3 2005		Q4 2005		Total 2005		Q1 2006		Q2 2006			Q3 2006			Q4 2006		Total 2006
Adjusted EBITDA			$	3,347	$	4,894	$	1,923	$	14,535	$	24,699	$	17,613	$	16,783		$	17,129		$	18,372	$	69,897
Less:
	Cash interest expense(a)			890		1,321		1,698		2,077		5,986		2,325		2,387			2,546			2,639		9,897
	Drilling capital expenditures(b)			1,753		6,747		7,500		6,202		22,202		3,315		10,735			15,240			4,110		33,400
Plus:
	(Borrowings)/Excess(c)			—		—		—		—		—		848		(7,464	)		(11,782	)		498		(17,900	)

Cash available to pay distributions				—		—		—		—		—	$	11,125	$	11,125		$	11,125		$	11,125	$	44,500

Estimated cash distributions:
	Distribution per unit			—		—		—		—		—	$	0.40	$	0.40		$	0.40		$	0.40	$	1.60
	Distributions to:
		Public unitholders		—		—		—		—		—	$	4,700	$	4,700		$	4,700		$	4,700	$	18,800
		Non-affiliated equity investors		—		—		—		—		—		112		112			112			112		448
		Quantum Energy Partners		—		—		—		—		—		4,366		4,366			4,366			4,366		17,464
		Management		—		—		—		—		—		1,947		1,947			1,947			1,947		7,788

	Total estimated cash distributions			—		—		—		—		—	$	11,125	$	11,125		$	11,125		$	11,125	$	44,500

(a): Cash interest expense is based on our assumed average debt balances of $145.0 million, $148.6 million, $158.2 million and $164.0 million during the first, second, third and fourth quarters of 2006, respectively, at a weighted average interest rate of 6.4% for the year ending December 31, 2006.
(b): We expect to drill 24, 42, 43 and 30 wells during the first, second, third and fourth quarters of 2006, respectively, at an assumed average cost per well of $250,000. While well costs are expected to vary on a quarterly and regional basis, well costs for 2006 are expected to average $250,000 per well, which assumption is based on historical results and current expectations. Further, these assumptions are based on our having 4 drilling rigs under contract for 2006 and no significant delays.
(c): During the second and third quarters of 2006, we expect to borrow $7.5 and $11.8 million, respectively, to cover the shortfalls between the amount of Estimated Adjusted EBITDA less cash interest expense and drilling capital expenditures and the amount of cash we need to pay our anticipated quarterly distributions payable in such quarter.

As reflected in the table below, to generate our Estimated Adjusted EBITDA for the year ending December 31, 2006, we have assumed the following regarding our operations, revenues and expenses:

	Year Ending December 31, 2006
Net Production:(a)
Total production (MMcfe)		8,655
Average daily production (Mcfe/d)		23,712
Average Natural Gas Sales Price per Mcf:(b)
Average NYMEX sales price (hedged volumes)	$	9.22
Average NYMEX sales price (unhedged volumes)	$	7.50
Percent of total production hedged		94%
Premium to NYMEX	$	0.50
Weighted average net sales price	$	9.62
Estimated Adjusted EBITDA:
Total revenue(c)	$	83,315
Operating expenses(d)		9,468
General and administrative expenses(e)		3,950

Estimated Adjusted EBITDA	$	69,897

(a): Net production volumes are based on historical production results and historical production curves. Our forecasted net production volumes for the year ending December 31, 2006 are slightly higher than the net production volumes for the same period reflected in the reserve report at September 30, 2005 prepared by Schlumberger Data and Consulting Services primarily due to our current expectation that we will drill twelve more development wells, consisting of four during the fourth quarter of 2005 and eight during the year ending December 31, 2006, than the estimated number of development wells assumed by Schlumberger Data and Consulting Services for their reserves and production estimates. The additional twelve wells do not increase the number of proved undeveloped drilling locations identified in Schlumberger Data and Consulting Services' report, but reflect an adjustment to the timing of the development of the proved undeveloped drilling locations included in the reserve report.
(b): Our weighted average net natural gas sales price of $9.62 is calculated by taking into account the volume of natural gas we have hedged for the forecast period (8,142 MMMBtu, or approximately 94% of total forecasted production volume) at a weighted average NYMEX price of $9.22 per MMBtu and unhedged natural gas production volumes at an assumed price of $7.50 per MMBtu. The price is adjusted by adding an assumed premium of $0.50 per Mcf, which accounts for our estimate of a positive Appalachian basis differential, positive Btu adjustments and gathering fees.
(c): Revenue is calculated by multiplying total net natural gas production by the weighted average net natural gas sales prices. Revenue is further adjusted for oil, which accounts for less than 1% of our production forecast and is assumed to have a net price of $55.00 per Bbl, after a negative basis differential and gathering fees.
(d): Operating expenses consist of the lease operating expenses, labor, field office rent, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, severance and ad valorem taxes and other customary charges. We do not intend to maintain cash reserves in excess of anticipated operating expenses. We believe that the amount included in our forecast is sufficient. Should actual expenses be higher, we believe that we will have sufficient capacity under our credit facility.

(e): General and administrative expenses are based on our estimate of the costs of our employees and executive officers, related benefits, office leases, professional fees, other costs not directly associated with field operations and the additional costs associated with being a public company. We do not intend to maintain cash reserves in excess of anticipated expenses. We believe that the amount included in our forecast is sufficient. Should actual expenses be higher, we believe that we will have sufficient capacity under our credit facility.

•

production, on a quarterly basis, from wells expected to be producing during the respective quarter at levels based on historical results for similar wells; and

•

weighted average natural gas sales prices based on:

•: hedged volumes for the respective quarter multiplied by the hedged sales prices;
•: unhedged volumes expected for such quarter at an assumed sales price of $7.50 per Mcf; and
•: an assumed premium of $0.50 per Mcf, which accounts for our estimate of a positive Appalachian basis differential, positive Btu adjustments and gathering fees.

We anticipate being able to pay the anticipated cash distributions in 2006 based on the level of drilling activity as well as the anticipated borrowings under our credit facility in such amounts and in the quarters as shown in the table below. Our forecasted levels of production do not assume that we will acquire any new wells.


	Historical									Forecast
	Q1 2005			Q2 2005			Q3 2005			Q4 2005		Total 2005			Q1 2006		Q2 2006		Q3 2006		Q4 2006		Total 2006
Net Production:(a)
Total production (MMcfe)		978			1,093			1,178			1,902		5,151			2,150		2,054		2,096		2,355		8,655
Average daily production (Mcfe/d)		10,862			12,144			13,089			20,674		14,112			23,893		22,816		23,289		26,164		23,712
Wells drilled:
Total wells (gross) drilled		6			33			39			32		110			24		42		43		30		139
Average cost per well(b)	$	214		$	204		$	232		$	235	$	225		$	250	$	250	$	250	$	250	$	250
Average Natural Gas Sales Price per Mcf:
Average NYMEX sales price (hedged volumes)	$	5.57		$	5.45		$	6.08		$	7.74	$	6.36		$	9.22	$	9.23	$	9.23	$	9.20	$	9.22
Average NYMEX sales price (unhedged volumes)	$	6.59		$	7.16		$	8.43		$	12.93	$	10.48		$	7.50	$	7.50	$	7.50	$	7.50	$	7.50
Percent of total production hedged		89%			83%			82%			68%		78%			94%		99%		94%		87%		94%
Weighted average net sales price(c)	$	5.96		$	6.16		$	5.72		$	9.56	$	6.81		$	9.68	$	9.68	$	9.63	$	9.49	$	9.62
Adjusted EBITDA:
Natural gas and oil sales	$	6,146		$	7,855		$	10,407		$	18,185	$	42,593		$	20,806	$	19,879	$	20,282	$	22,348	$	83,315
Realized (loss) on natural gas derivatives(d)		(598	)		(1,053	)		(5,889	)		—		(7,540	)		—		—		—		—		—
Other revenue		98			115			(115	)		—		98			—		—		—		—		—

Total revenue		5,646			6,917			4,403			18,185		35,151			20,806		19,879		20,282		22,348		83,315
Operating expenses		1,835			1,453			1,329			2,250		6,867			2,343		2,246		2,303		2,576		9,468
General and administrative expenses(e)		464			570			1,151			1,400		3,585			850		850		850		1,400		3,950

Adjusted EBITDA	$	3,347		$	4,894		$	1,923		$	14,535	$	24,699		$	17,613	$	16,783	$	17,129	$	18,372	$	69,897

(a): Net production for the forecast period is based on historical production results and historical production curves. Our forecast of production for 2006 assumes that we drill the number of wells for the fourth quarter of 2005

and for each quarter of 2006 as specified in this table under the caption "Wells drilled." Production from a newly drilled development well, if successful, typically commences within 60 days from the date the drilling of the well commenced, and our forecast of production assumes this schedule for each well expected to be drilled during the remainder of 2005 and during 2006. We expect to drill 24 wells in the first quarter of 2006 compared to 6 in the first quarter of 2005. In prior years, we did not commence our drilling program until late in the first quarter whereas our 2006 drilling program schedules wells to be drilled as early as the first week of January. Includes production from wells acquired since January 1, 2005. We acquired interests in 38 producing wells in April 2005 from Columbia Natural Resources, LLC, 130 producing wells in August 2005 from GasSearch Corporation, and 550 producing wells in October 2005 from Exploration Partners, LLC.

(b): While well costs are expected to vary on a quarterly and regional basis, well costs for 2006 are expected to average $250,000 per well, which assumption is based on historical results and current expectations.
(c): Quarterly weighted average net natural gas sales prices are calculated by multiplying hedged production for such quarter by the hedged sales price for such quarter and the unhedged volumes by the unhedged sales price. We estimate the unhedged sales price for the fourth quarter of 2005 will be $12.93 per Mcf based on actual prices and $7.50 per Mcf for each quarter of 2006. The price is adjusted by adding an assumed premium of $0.50 per Mcf, which accounts for our estimate of a positive Appalachian basis differential, positive Btu adjustments and gathering fees.
(d): Excludes realized losses of $38.3 million on canceled natural gas swaps.
(e): Excludes one-time cash bonuses in the amount of $1.8 million (based on an assumed per unit offering price of $20.00) granted to management upon successful completion of this offering since such bonuses are funded with proceeds from this offering.

Pro Forma Cash Available to Pay Distributions for the Year Ended December 31, 2004 and the Pro Forma Twelve-Month Period Ended September 30, 2005

The following table illustrates, on a pro forma basis, for the year ended December 31, 2004 and for the twelve-month period ended September 30, 2005, the amount of cash available to pay distributions to our unitholders, assuming, in each case, that the offering and the related transactions had been consummated at the beginning of such period. Pro forma cash available to pay distributions excludes any cash from working capital or other borrowings and cash on hand as of the closing date of this offering.

The year ended December 31, 2004 in the table below gives effect, on a pro forma basis, to the Mountain V, Pentex and Exploration Partners acquisitions as if they had occurred on January 1, 2004. The Mountain V, Pentex and Exploration Partners acquisitions were completed on May 7, 2004, September 30, 2004 and October 27, 2005, respectively. The pro forma twelve-month period ended September 30, 2005 in the table below gives effect to the Exploration Partners aquisition as if it occurred on October 1, 2004.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available to pay distributions only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.

Linn Energy, LLC
Unaudited Pro Forma Cash Available to Pay Distributions

		Pro Forma Year Ended December 31, 2004			Pro Forma Twelve-Month Period Ended September 30, 2005
		(in thousands, except per unit amounts)
Net (Loss)		$	(3,902	)	$	(55,804	)
Plus:
	Interest expense		8,866			8,591
	Depreciation, depletion and amortization		10,405			9,565
	Write-off of deferred financing fees		—			364
	Loss on sale of assets		32			65
	Loss from equity investment		56			31
	Accretion of asset retirement obligation		185			243
	Unrealized loss on natural gas derivatives		8,765			24,663
	Realized loss on cancelled natural gas derivatives		—			38,281
	Income tax provision		—			385

Adjusted EBITDA		$	24,407		$	26,384

Less:
	Cash interest expense(a)		7,484			7,837
	Pro forma additional expense of being a public company(b)		1,400			1,400
Plus:
	Pro forma adjustment to interest expense(c)		4,880			5,490

Pro forma cash flow from operations		$	20,403		$	22,637

Pro forma cash distributions
	Annualized initial quarterly distribution per unit	$	1.60		$	1.60

	Total distributions	$	44,500		$	44,500

Pro forma cash flow from operations (after distributions)		$	(24,097	)	$	(21,863	)

	Less: Drilling capital expenditures (d)	$	16,733		$	22,400

Shortfall		$	(40,830	)	$	(44,263	)

(a): Interest expense adjusted to exclude amortization of deferred financing fees and unrealized loss (gain) on interest rate swaps, which are non-cash items.
(b): We expect our incremental general and administrative expenses will include costs associated with annual and quarterly reports to unitholders, our annual meeting of unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, fees of independent directors, accounting fees and legal fees.
(c): Adjusted to reflect $122.0 million debt repayment from net proceeds of this offering.
(d): Funded with a combination of cash flows from operations and borrowings under our credit facility. Excludes capital expenditures related to acquisitions.

Assumptions and Considerations

Based on specific assumptions with respect to the year 2006 as outlined below, including drilling capital expenditures at a level intended to create growth in production and absent expected borrowings of $17.9 million under our credit facility, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash generated from operations, to fund our drilling program and to pay the initial quarterly distribution on all units for each quarter through December 31, 2006. Such borrowings would constitute approximately 40.2% of the $44.5 million required to pay the annual distribution for 2006. While we believe that these assumptions are reasonable in light of management's current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize or if we are not able to borrow the required amounts, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full initial quarterly distribution, or any amount, on all units, in which event the market price of our units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings "Risk Factors," and "Forward-Looking Statements." Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

•: We expect to drill 139 gross (134 net) wells for the year ending December 31, 2006, all of which we assume will be successful in producing natural gas in commercial quantities based on our past drilling performance. We expect to drill at least the same number of wells per year in the future and believe we have enough potential drilling locations and have taken steps sufficient to ensure adequate and timely supply of drilling equipment. Our drilling program for the year ending December 31, 2005 provides for us to drill 110 gross (105 net) wells. As of November 30, 2005, we had drilled 101 gross (97 net) wells, all of which are producing natural gas in commercial quantities. From our inception in March 2003 through November 30, 2005, we drilled 191 gross (179 net) wells, all of which produce natural gas in commercial quantities.
•: We estimate that our total net production will be 8,655 MMcfe for the year ending December 31, 2006. Our total net production pro forma for the twelve-month period ending September 30, 2005 and pro forma for the year ended December 31, 2004 was 6,522 MMcfe and 6,074 MMcfe, respectively. The increase in our estimate of total net production for the year ending December 31, 2006 compared to the pro forma twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004 is attributable to the additional production from our acquisitions of interests in 38 producing wells from Columbia Natural Resources, LLC in April 2005 and 130 producing wells from GasSearch Corporation in August 2005 and our drilling of 88 additional wells to date in 2005 and the additional wells we expect to drill during the remainder of 2005 and during the year ending December 31, 2006. Based on our historical experience, we expect that new wells will be producing and connected to a pipeline within 60 days after drilling has commenced, which assumption includes an allowance for unexpected delays.
•: We have hedged an average of approximately 94% of our forecasted production of 8,655 MMCfe for the year ending December 31, 2006. Approximately 86% of total production, or 7,412 MMcfe, is hedged using swap agreements, and the remaining 730 MMcfe (or 8% of total production) is hedged using put agreements. Since the swap agreements constitute only 86% of total forecasted production for 2006, we expect actual production to exceed the total amount of natural gas hedged with swaps.

•: We estimate that our average net daily production will be approximately 23.7 MMcfe for the year ending December 31, 2006. As of November 30, 2005, our average net daily production was 21.6 MMcfe from 2,105 producing wells. Pro forma for the twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004, our average net daily production was approximately 17.9 MMcfe and 16.6 MMcfe, respectively. The increase in our estimate of average net daily production for the year ending December 31, 2006 as compared to the pro forma twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004 is attributable to the additional production from our acquisitions of interests in 38 producing wells from Columbia Natural
Resources, LLC in April 2005 and 130 producing wells from GasSearch Corporation in August 2005 and our drilling of 101 additional wells to date in 2005 and the additional wells we expect to drill during the remainder of 2005 and during the year ending December 31, 2006.
•: We estimate that we will achieve a weighted average natural gas sales price of approximately $9.62 for the year ending December 31, 2006, based on the fact that we have hedged approximately 94% of our forecasted natural gas production for the period (8,142 MMMBtu) at a weighted average NYMEX natural gas price of $9.22 per MMBtu. We have assumed a NYMEX natural gas price of $7.50 per MMBtu for our unhedged volumes. Our estimated weighted average natural gas sales price also includes an assumed premium of $0.50 per Mcf, which accounts for our estimate of a positive Appalachian basis differential relative to the NYMEX price and positive Btu adjustments, less gathering fees. As of December 31, 2004, this premium was $0.67 per Mcf. Pro forma for the twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004 our average natural gas sales prices (including hedges) were $6.75 and $5.76 per Mcfe, respectively.
•: We estimate that we will generate revenues of approximately $83.3 million for the year ending December 31, 2006, which we have calculated by multiplying the total estimated net natural gas production by weighted average natural gas sales price estimates described above. Our revenue estimate is further adjusted for our expected net oil production, which accounts for less than 1% of our total net production estimate and is assumed to have a net price of $55.00 per barrel, after a negative basis differential and gathering fees. Pro forma for the twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004, we generated natural gas and oil sales of $46.6 and $36.9 million, respectively. The estimated increase in revenues for the year ending December 31, 2006 compared to the prior twelve-month periods is attributable to estimated increases in production, from the three acquisitions (including Exploration Partners) and new wells drilled in years 2004, 2005 and 2006, and increases in the average natural gas and oil sales prices. In addition, our revenues pro forma for the twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004 were reduced as a result of realized and unrealized hedging losses of $72.6 and $11.0 million, respectively.

Capital Expenditures and Expenses

•: We estimate that our drilling capital expenditures for the year ending December 31, 2006 will be approximately $33.4 million, based on our expectation of drilling 139 gross (134 net) wells during the year at an average cost of $250,000 per well. We expect to finance these capital expenditures through borrowings of approximately $17.9 million under our credit facility and $15.5 million with cash flow from operations. For the year ending December 31, 2005, we estimate that our drilling capital expenditures will be approximately $23.6 million, based on our expectation of drilling 110 gross (105 net) wells during the year at an average cost of $225,000 per well. Pro forma for the twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004, we drilled 96 gross (88 net) wells and 90 gross (82 net) wells, respectively, resulting in drilling capital expenditures of $22.4 and $16.7 million, respectively. The increase in estimated capital expenditures for the

year ending December 31, 2006 compared to the prior twelve-month periods is attributable to the drilling of more wells (139 as compared to 110 and 96, respectively) and the expected increase in drilling costs to $250,000 per well.

•: We estimate that our operating expenses for the year ending December 31, 2006 will be approximately $9.5 million. Pro forma for the twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004, our operating expenses were $8.9 and $8.9 million, respectively. The increase in estimated operating expenses for the year ending December 31, 2006 compared to the results for the prior twelve-month periods is attributable to the increase in our total number of wells as a result of acquisitions and the drilling of new wells.
•: We estimate that our general and administrative expenses for the year ending December 31, 2006 will be approximately $4.0 million. Pro forma for the twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004, our general and administrative expenses were $2.9 and $1.7 million, respectively. The increase in estimated general and administrative expenses for the year ending December 31, 2006 compared to the results for the prior twelve-month periods is attributable to the $1.4 million of pro forma additional expense of being a public company and increases in the cost of our employees, executive officer salaries and bonuses, and other unit-based compensation, related benefits, office leases, professional fees, and other costs not directly associated with field operations, excluding any effects of unit option grants. The executive bonuses based upon the success of this offering are included in our forecast assuming a $20.00 per unit price to the public. Future employee bonuses and unit-based compensation may adversely impact our cash available for distribution.
•: We estimate that our interest expense for the year ending December 31, 2006 will be approximately $9.9 million, based on our expected average debt balance of $154.4 million (including the $17.9 million of borrowings to fund capital expenditures described above) and an assumed interest rate of 6.4%. Pro forma for the twelve-month period ended September 30, 2005 and pro forma for the year ended December 31, 2004, our interest expense was $8.6 and $8.9 million, respectively. The increase in estimated interest expense for the year ending December 31, 2006 compared to the results for the prior twelve-month periods is attributable to an increase in the average interest rate. Our average debt balances pro forma for the twelve-month period ending September 30, 2005 and pro forma for the year ended December 31, 2004 were $170.0 and $199.1 million, respectively, and our average interest rates were 4.5% and 4.0%, respectively.

Other

•: As of November 30, 2005, we had $17.4 million available for borrowing under our credit facility. Giving effect to this offering and the application of the net proceeds therefrom, our borrowing capacity is expected to be $79.4 million, assuming the current borrowing base of $225.0 million. We estimate that we will have sufficient capacity under our credit facility for the year ending December 31, 2006 to borrow the $17.9 million we expect to fund capital expenditures and distributions. However, the amount of borrowing base and thus our ability to borrow is in the sole discretion of the lenders. Please read "Risk Factors — Risks Related to Our Business — Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions" on page 26. In addition, we expect that our estimated increases in our natural gas production and natural gas reserves will result in an increase in our borrowing base by at least the amount of the actual capital expenditures for drilling, which are estimated to be $33.4 million for the year ending December 31, 2006. As a result, we believe that the combination of cash reserves established by our board of directors and incremental borrowing capacity generated through drilling will be sufficient to fund our capital expenditures for the year ending December 31, 2006.

•: We assume no cash reserves in excess of anticipated interest expense, operating expenses and general and administrative expenses. We believe that the amount included in our forecast is sufficient. Should actual expenses be higher, we believe that we will have sufficient capacity under our credit facility.
•: We assume that there will be no material nonperformance or credit-related defaults by equipment suppliers, drillers or customers.
•: We assume that no material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated material events will occur in either our existing operations or our planned drilling program.
•: We assume that market, regulatory and overall economic conditions will not change substantially.

HOW WE MAKE CASH DISTRIBUTIONS

Definition of Available Cash

We define available cash in the glossary, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

•

less the amount of cash reserves established by our board of directors to:

—: provide for the proper conduct of our business (including reserves for future capital expenditures, future debt service requirements, and for our anticipated credit needs);
—: comply with applicable law, any of our debt instruments or other agreements; or
—: provide funds for distribution to our unitholders for any one or more of the next four quarters;

•

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with the limited liability company agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Adjustments to Capital Accounts

We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders in the same manner as we allocate gain or loss upon liquidation.

SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

Set forth below is our selected historical and pro forma consolidated financial data for the periods indicated for Linn Energy, LLC (Successor). The historical financial data for the periods ended December 31, 2003 and 2004 and the balance sheet data as of December 31, 2003 and 2004 have been derived from our audited financial statements. The historical financial data for the nine months ended September 30, 2004 and 2005 and the balance sheet information as of September 30, 2005 were derived from our unaudited financial statements included in this prospectus. The pro forma statement of operations data gives effect to the acquisitions of the properties acquired from Mountain V Oil & Gas, Inc., Pentex Energy, Inc. and Exploration Partners, LLC as if they occurred on January 1, 2004. The pro forma balance sheet data gives effect to the acquisition of the properties acquired from Exploration Partners, LLC and this offering as if they occurred on September 30, 2005.

On October 31, 2003, we completed a $31.0 million acquisition of natural gas and oil assets from Waco Oil & Gas (Predecessor). The historical financial data for the period from January 1, 2003 through October 31, 2003 and the year ended December 31, 2002 have been derived from the audited financial statements of the Predecessor entity. The historical financial data for the years ended December 31, 2000 and 2001 and the balance sheet data as of December 31, 2000, 2001 and 2002 have been derived from the unaudited financial statements of the Predecessor entity.

															Successor
			Predecessor												Successor
			Predecessor																					Nine Months Ended September 30,
												Period from January 1, 2003 through October 31, 2003			Period from March 14, 2003 (inception) through December 31, 2003
																		Year Ended December 31, 2004
			Year Ended December 31,															Year Ended December 31, 2004									2005
			2000			2001			2002									Historical			Pro Forma			2004			Historical			Pro Forma
			(unaudited)																		(unaudited)			(unaudited)
			(in thousands)															(in thousands)
Statement of Operations Data:
Revenues:
	Natural gas and oil sales		$	981		$	5,382		$	3,779		$	4,705		$	3,323		$	21,232		$	36,858		$	14,205		$	24,408		$	36,181
	Realized gain (loss) on natural gas derivatives(1)			—			—			—			—			163			(2,240	)		(2,240	)		(925	)		(45,822	)		(45,822	)
	Unrealized (loss) on natural gas derivatives(2)			—			—			—			—			(1,600	)		(8,765	)		(8,765	)		(10,890	)		(26,788	)		(26,788	)
	Natural gas marketing income			—			—			—			—			—			520			520			—			3,087			3,087
	Other income			660			1,488			698			788			4			160			160			86			158			158

		Total revenues		1,641			6,870			4,477			5,493			1,890			10,907			26,533			2,476			(44,957	)		(33,184	)

Expenses:
	Operating expenses			1,767			1,702			2,426			2,204			917			5,460			8,907			4,377			4,617			7,008
	Natural gas marketing expense			—			—			—			—			—			482			482			—			3,162			3,162
	General and administrative expenses			1,088			3,186			1,047			870			845			1,583			1,694			1,066			2,309			2,364
	Depreciation, depletion and amortization			964			1,152			1,494			1,185			972			3,749			10,405			2,408			3,736			8,196

		Total expenses		3,819			6,040			4,967			4,259			2,734			11,274			21,488			7,851			13,824			20,730

Other Income and (Expenses):
	Interest income			—			—			—			—			34			7			7			7			16			16
	Interest and financing expenses(3)			(392	)		(390	)		(352	)		(237	)		(517	)		(3,530	)		(8,866	)		(2,937	)		(3,282	)		(6,827	)
	Loss on equity investment			—			(57	)		(145	)		(63	)		(3	)		(56	)		(56	)		(42	)		(17	)		(17	)
	Write-off of deferred financing fees			—			—			—			—			—			—			—			—			(364	)		(364	)
	Gain (loss) on sale of assets			—			(111	)		(63	)		49			(5	)		(32	)		(32	)		(10	)		(43	)		(43	)

		Total other income and (expenses)		(392	)		(558	)		(560	)		(251	)		(491	)		(3,611	)		(8,947	)		(2,982	)		(3,690	)		(7,235	)

	Income (loss) before income taxes			(2,570	)		272			(1,050	)		983			(1,335	)		(3,978	)		(3,902	)		(8,357	)		(62,471	)		(61,149	)
	Income tax provision(4)			—			—			—			—			—			—			—			—			385			385
Income (loss) before cumulative effect of change in accounting principle				(2,570	)		272			(1,050	)		983			(1,335	)		(3,978	)		(3,902	)		(8,357	)		(62,856	)		(61,534	)
Cumulative effect of change in accounting principle				—			—			—			(757	)		—			—			—			—			—			—

Net income (loss)			$	(2,570	)	$	272		$	(1,050	)	$	226		$	(1,335	)	$	(3,978	)	$	(3,902	)	$	(8,357	)	$	(62,856	)	$	(61,534	)

(1): During the nine months ended September 30, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas hedges and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices.
(2): The natural gas swaps were not specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to changes in natural gas prices. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these amounts represent non-cash charges.
(3): Includes the unrealized gain (loss) on interest rate swaps that were not specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to changes in interest rates. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these amounts represent non-cash charges.
(4): Linn Operating, LLC was not subject to federal income tax before converting to a subchapter c-corporation on June 1, 2005. Prior to the conversion, there was no tax provision included in our consolidated financial statements because all of our taxable income or loss was included in the income tax returns of the individual members.


	Predecessor												Successor
										Period from January 1, 2003 through October 31, 2003			Period from March 14, 2003 (inception) through December 31, 2003
																			Nine Months Ended September 30,
	Year Ended December 31,
	Year Ended December 31,															Year Ended December 31, 2004
	2000			2001			2002									Year Ended December 31, 2004			2004			2005
	(unaudited)																		(unaudited)
	(in thousands)															(in thousands)
Cash Flow Data:
Net cash (used in) provided by operating activities(1)	$	(1,363	)	$	1,659		$	(40	)	$	1,826		$	929		$	11,381		$	7,018		$	(36,661	)
Net cash (used in) provided by investing activities		(1,687	)		(8,831	)		(1,480	)		10,880			(36,408	)		(62,402	)		(56,945	)		(28,309	)
Net cash provided by (used in) financing activities		2,829			7,473			1,056			(2,415	)		57,521			31,167			31,090			65,759
Capital expenditures	$	1,687		$	8,566		$	1,375		$	1,717		$	52,356		$	47,508		$	40,972		$	27,972
Other Financial Information (unaudited):
Adjusted EBITDA(2)													$	1,777		$	12,228		$	7,956		$	10,164


		Predecessor						Successor
		As of December 31,						As of December 31,				As of September 30, 2005
		2000		2001		2002		2003		2004		Historical			Pro Forma
		(unaudited)										(unaudited)
		(in thousands)						(in thousands)
Balance Sheet Data:
Cash and cash equivalents(3)		$	705	$	1,006	$	542	$	22,043	$	2,188	$	2,977		$	3,701
Other current assets			614		447		710		1,714		5,094		11,250			9,217
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization			5,844		12,831		12,829		53,036		97,123		121,178			237,517
Property, plant and equipment, net of accumulated depreciation			2,643		2,958		2,778		370		1,387		1,966			2,630
Other assets			—		208		168		2,486		542		6,216			6,216

	Total assets	$	9,806	$	17,450	$	17,027	$	79,649	$	106,334	$	143,587		$	259,281

Current liabilities		$	1,932	$	3,498	$	3,468	$	20,319	$	9,968	$	29,343		$	28,034
Long-term debt			3,388		2,686		1,919		41,518		72,750		138,975			132,275
Other long-term liabilities			—		—		—		3,123		12,905		27,414			29,117
Members' capital (deficit)			4,486		11,266		11,640		14,689		10,711		(52,145	)		69,855

	Total liabilities and members' capital	$	9,806	$	17,450	$	17,027	$	79,649	$	106,334	$	143,587		$	259,281

(1): During the nine months ended September 30, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas swaps and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices.
(2): See "Non-GAAP Financial Measure" on page 16.
(3): In December 2003, we borrowed approximately $18 million under our credit facility to pay the remaining purchase price for the Waco acquisition, which amount was paid to Waco on January 2, 2004.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the "Selected Historical Consolidated Financial and Operating Data" and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements," all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

Our proved reserves at September 30, 2005 were 189.6 Bcfe, of which approximately 99% were natural gas and 66% were classified as proved developed, with a Standardized Measure of $898.7 million. At November 30, 2005, we operated 1,913, or 91%, of our 2,105 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 29 years based on September 30, 2005 reserve report and annualized pro forma production for the nine months ended September 30, 2005. As of September 30, 2005, we had identified 362 proved undeveloped drilling locations and over 500 additional drilling locations. As of September 30, 2005, we had a leasehold interest in approximately 140,045 net acres in the Appalachian Basin. From inception through September 30, 2005, we added 27.2 Bcfe of proved reserves through our drilling activities, at a finding and development cost of $1.21 per Mcfe, which includes the estimated development costs for proved undeveloped reserves.

On October 27, 2005, we acquired from Exploration Partners and related working interest owners interests in 550 wells located in 12 counties in West Virginia and one county in Virginia. Most of the wells are located adjacent to our existing operations. We expect to operate 424, or 77%, of the total wells acquired. We also acquired approximately 250 miles of natural gas gathering systems, which deliver 6.7 MMcf per day to eight different purchasers through 110 delivery points, as well as related oilfield service equipment. The oilfield services will be conducted through our subsidiary Mid Atlantic Well Service, Inc. Additionally, we acquired, pursuant to a standard farm out agreement, the option to drill on approximately 10,000 undeveloped acres in northern West Virginia. As of November 30, 2005, we had identified 105 proved undeveloped drilling locations and 117 additional drilling locations on this acreage and currently expect to drill 25 wells annually.

We focus on acquisitions that allow us to:

•: Increase production through workovers, addition of equipment, improved field operations as well as additional infill drilling and other development activities; and
•: Implement efficiencies through operational and administrative consolidation.

Since inception, we have completed nine acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate purchase price of $203.2 million, with total proved reserves of 160.1 Bcfe, or an acquisition cost of $1.27 per Mcfe.

Date	Seller	Wells	Location	Purchase Price (in millions)
May 2003	Emax Oil Company	34	West Virginia	$	3.1
Aug 2003	Lenape Resources, Inc.	61	New York		2.0
Sep 2003	Cabot Oil & Gas Corporation	50	Pennsylvania		15.5
Oct 2003	Waco Oil & Gas Company	353	West Virginia and Virginia		31.0
May 2004	Mountain V Oil & Gas, Inc.	251	Pennsylvania		12.4
Sep 2004	Pentex Energy, Inc.	447	Pennsylvania		14.2
Apr 2005	Columbia Natural Resources, LLC	38	West Virginia and Virginia		4.3
Aug 2005	GasSearch Corporation	130	West Virginia		5.4
Oct 2005	Exploration Partners, LLC	550	West Virginia and Virginia		115.3

	Total	1,914		$	203.2

Our acquisitions were financed with a combination of private equity, proceeds from bank borrowings and cash flow from operations. Our activities are focused on evaluating and developing our asset base, increasing our acreage positions and evaluating potential acquisitions.

As of September 30, 2005, we had 189.6 Bcfe of estimated net proved reserves with a Standardized Measure of $898.7 million, a 58% increase over December 31, 2004, when we had 119.8 Bcfe of estimated net proved reserves with a Standardized Measure of $215.0 million. Our September 30, 2005 and December 31, 2004 Standardized Measure was determined using a price of $15.36 and $6.18 per Mcf of natural gas, respectively, and $66.21 and $43.00 per Bbl of oil, respectively. Oil accounts for less than 1% of our production.

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

We utilize the successful efforts method of accounting for our natural gas and oil properties. Leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Generally, if a

well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense.

Higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs. Given the inherent volatility of natural gas prices, which are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices received. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations is dependent on our ability to manage our overall cost structure.

We face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals.

Our Operations

Our revenues are highly sensitive to changes in natural gas prices and levels of production. As set forth in " — Cash Flow from Operations" below, we have hedged a significant portion of our expected production, which allows us to mitigate, but not eliminate, natural gas price risk. Our expected increase in levels of production as a result of the anticipated drilling of 110 wells during 2005 is dependent on our ability to quickly and efficiently bring the newly drilled wells online. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of increase in our production, which may have an adverse effect on our revenues and as a result, cash available for distribution. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in natural gas prices will affect the ability to drill additional wells and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in natural gas prices may have on the value of our proved reserves and their impact, if any, on any redetermination of the borrowing base under our credit facility.

Production and Operating Costs Reporting

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

Land and Lease Tracking System

As a significant amount of our growth is dependent on drilling new wells, we continuously monitor our lease agreements and our drilling locations to avoid delays. Our monitoring system matches our lease agreements to existing wells and sites for future development allowing

management to make real time decisions on what acreage to develop and at what point in time. We continually seek to acquire new lease positions to increase potential drilling locations.

Results of Operations

The following table sets forth selected financial and operating data for the periods indicated.

			Predecessor						Successor
						Period from January 1, 2003 through October 31, 2003			Period from March 14, 2003 (inception) through December 31, 2003
															Nine Months Ended September 30,
			Year Ended December 31, 2002									Year Ended December 31, 2004			Nine Months Ended September 30,
			Year Ended December 31, 2002									Year Ended December 31, 2004			2004			2005
															(unaudited)
			(in thousands, except production and price data)
Revenues:
	Natural gas and oil sales		$	3,779		$	4,705		$	3,323		$	21,232		$	14,205		$	24,408
	Realized gain (loss) on natural gas derivatives			—			—			163			(2,240	)		(925	)		(45,822	)
	Unrealized (loss) on natural gas derivatives			—			—			(1,600	)		(8,765	)		(10,890	)		(26,788	)
	Natural gas marketing income			—			—			—			520			—			3,087
	Other income			698			788			4			160			86			158

		Total revenue		4,477			5,493			1,890			10,907			2,476			(44,957	)
Expenses:
	Operating expenses		$	2,426		$	2,204		$	917		$	5,460		$	4,377		$	4,617
	Natural gas marketing expense			—			—			—			482			—			3,162
	General and administrative expenses			1,047			870			845			1,583			1,066			2,309
	Depreciation, depletion and amortization			1,494			1,185			972			3,749			2,408			3,736

		Total expenses		4,967			4,259			2,734			11,274			7,851			13,824
Other Income and (Expenses):
	Interest and financing expenses		$	(352	)	$	(237	)	$	(517	)	$	(3,530	)	$	(2,937	)	$	(3,282	)
Net Production:
	Total production (MMcfe)			1,195			919			802			3,385			2,288			3,240
	Average daily production (Mcfe/d)			3,274			3,023			3,748			9,274			8,350			11,868
Average Sales Prices per Mcfe:
	Average sales prices (including hedges)		$	3.16		$	5.12		$	5.07		$	5.74		$	5.54		$	6.27
	Average sales prices (excluding hedges)									4.87			6.43			5.95			7.62
Average Unit Costs per Mcfe:
	Operating expenses		$	2.03		$	2.40		$	1.14		$	1.61		$	1.91		$	1.43
	General and administrative expenses			0.88			0.95			1.05			0.47			0.47			0.71
	Depreciation, depletion and amortization			1.25			1.29			1.21			1.11			1.05			1.15

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Revenue

Natural gas and oil sales, before realized and unrealized gains and losses on natural gas derivatives, increased to approximately $24.4 million from $14.2 million during the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004. The key revenue measurements were as follows:

		Nine Months Ended September 30,
		Nine Months Ended September 30,				Percentage Increase
		2004		2005		Percentage Increase
Net Production:
	Total production (MMcfe)		2,288		3,240	42	%
	Average daily production (Mcfe/d)		8,350		11,868	42	%
Average Sales Prices per Mcfe:
	Average sales price (including hedges)	$	5.54	$	6.27	13	%
	Average sales price (excluding hedges)		5.95		7.62	28	%

The increase in revenue from natural gas and oil sales was due primarily to the increase in production to 3,165 MMcfe during the nine months ended September 30, 2005 from 2,240 MMcfe during the nine months ended September 30, 2004, due to the two acquisitions completed in 2004 and two acquisitions completed in 2005, as well as the drilling of 78 wells during the first nine months of 2005. In addition to the increase in production, the average natural gas sales price increased during the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004.

Hedging Activities

During the nine months ended September 30, 2005, we hedged approximately 82% of our production, which resulted in revenues that were $7.5 million less than we would have achieved at unhedged prices. During the nine months ended September 30, 2004, we hedged approximately 66% of our production, which resulted in revenues that were $0.9 million less then we would have achieved at unhedged prices. During the nine months ended September 30, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas hedges and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices.

Expenses

Operating expenses consist of the lease operating expenses, labor, field office rent, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, severance and ad valorem taxes and other customary charges. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state/county and are based on the value of our reserves. We assess our operating expenses by monitoring the expenses in relation to the amount of production and the number of wells operated. Operating expenses increased to $4.6 million for the nine months ended September 30, 2005 from $4.4 million for the nine months ended September 30, 2004, due to the increase in the number of wells as a result of the two acquisitions completed in both 2004 and 2005, as well as the drilling of 90 and 78 wells during 2004 and for the nine months ended September 30, 2005, respectively.

	Nine Months Ended September 30,
	Nine Months Ended September 30,				Percentage Increase (Decrease)
	2004		2005		Percentage Increase (Decrease)
Operating expenses per Mcfe	$	1.91	$	1.43	(25	)%

General and administrative expenses include the costs of our employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. We monitor general and administrative expenses in relation to the amount of production and the number of wells operated. General and administrative expenses increased to $2.3 million from $1.1 million during the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004. General and administrative expenses per Mcfe of production were as follows:

	Nine Months Ended September 30,
	Nine Months Ended September 30,				Percentage Increase (Decrease)
	2004		2005		Percentage Increase (Decrease)
General and administrative expenses per Mcfe	$	0.47	$	0.71	51	%

The increase in general and administrative expenses was due to our rapidly growing operations and increasing our staffing level to manage the additional wells acquired and drilled in

2004 and 2005. We are continuing to increase staffing levels to manage our active drilling program and to perform the functions associated with being a public company.

Depreciation, depletion and amortization increased to $3.7 million for the nine months ended September 30, 2005 from $2.4 million for the nine months ended September 30, 2004 due to the increase in the number of wells as a result of the two acquisitions completed in both 2004 and 2005, as well as the drilling of 90 and 78 wells during 2004 and 2005, respectively.

Interest and financing expenses were $3.3 million for the nine months ended September 30, 2005 compared to $2.9 million for the nine months ended September 30, 2004. The interest rate swaps that were established in 2003 and 2004 were not specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to changes in interest rates. Therefore, the mark to market of these instruments was recorded as a $0.8 million gain and a $1.5 million loss in our current earnings for the nine months ended September 30, 2005 and for the nine months ended September 30, 2004, respectively. Further, these amounts represent non-cash charges. Cash payments for interest expense increased to $3.6 million for the nine months ended September 30, 2005 from $1.2 million for the nine months ended September 30, 2004, primarily due to increased debt levels associated with the two acquisitions made in both 2004 and 2005.

The income tax provision was $0.4 million for the nine months ended September 30, 2005 compared to $0 for the nine months ended September 30, 2004 as Linn Operating, LLC was not subject to federal income tax before converting to a subchapter c-corporation on June 1, 2005. Prior to the conversion, there was no tax provision included in our consolidated financial statements because all of our taxable income or loss was included in the income tax returns of the individual members.

Year Ended December 31, 2004 Compared to the Period from March 14, 2003 (inception) through December 31, 2003

Revenue

Natural gas and oil sales, before realized and unrealized gains and losses on natural gas derivatives, increased to $21.2 million from $3.3 million for the year ended December 31, 2004 as compared to the period from March 14, 2003 (inception) through December 31, 2003. The key revenue measurements were as follows:

		Period from March 14, 2003 (inception) through December 31, 2003	Year Ended December 31, 2004	Percentage Increase (Decrease)
Net Production:
	Total production (MMcfe)	802	3,385	322	%
	Average daily production (Mcfe/d)	3,748	9,274	147	%
Average Sales Prices per Mcfe:
	Average sales prices (including hedges)	$5.07	$5.74	13	%
	Average sales prices (excluding hedges)	4.87	6.43	32	%

The increase in revenue from natural gas and oil sales was primarily due to the increase in production as a result of two acquisitions made in 2004, the drilling of 90 wells and the additional months of revenue reported in 2004.

Hedging Activities

We hedged approximately 68% of our 2004 production, which resulted in revenues that were $2.2 million less than we would have achieved at unhedged prices. We hedged approximately 31% of our 2003 production, which resulted in revenues that were $0.2 million higher than we would have achieved at unhedged prices. The loss in 2004 was due to the increase in natural gas prices from 2003 to 2004.

Expenses

Operating expenses increased to $5.5 million for the year ended December 31, 2004 from $0.9 million for the period from March 14, 2003 (inception) through December 31, 2003, due to the increase in the number of wells as a result of the two acquisitions completed in 2004, as well as the drilling of 90 wells during 2004.

		Period from March 14, 2003 (inception) through December 31, 2003			Year Ended December 31, 2004			Percentage Increase (Decrease)
Operating expenses per Mcfe		$	1.14		$	1.61		41	%

General and administrative expenses increased to $1.6 million from $0.8 million during the year ended December 31, 2004 as compared to the period from March 14, 2003 (inception) through December 31, 2003. General and administrative expenses per Mcfe of production were as follows:

		Period from March 14, 2003 (inception) through December 31, 2003			Year ended December 31, 2004			Percentage Increase (Decrease)
General and administrative expenses per Mcfe		$	1.05		$	0.47		(55	%)

The increase in general and administrative expenses was due to our rapidly growing operations and increasing our staffing level to manage the additional wells acquired and drilled in 2004. However, our production and well count increased at a rate higher than our general and administrative expenses for the year ended December 31, 2004. Further, we are continuing to increase staffing levels to manage the 110 wells we expect to drill in 2005 and to perform the functions associated with being a public company.

Depreciation, depletion and amortization increased to $3.7 million for the year ended December 31, 2004 from $1.0 million for the period from March 14, 2003 (inception) through December 31, 2003, due to the increase in the number of wells as a result of the two acquisitions completed in 2004, the full year impact in 2004 of the wells acquired in 2003, as well as the drilling of 90 wells during 2004.

Interest and financing expenses were $3.5 million for the year ended December 31, 2004 as compared to $0.5 million for the the period from March 14, 2003 (inception) through December 31, 2003. The interest rate swaps that were established in 2003 and 2004 were not

specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to changes in interest rates. Therefore, the mark to market of these instruments was recorded as a $1.3 million loss and a $0.2 million loss in our current earnings for the year ended December 31, 2004 and for the period from March 14, 2003 (inception) through December 31, 2003, respectively. Further, these amounts represent non-cash charges. Cash payments for interest expense increased to $2.0 million for the year ended December 31, 2004 from $84,907 for the period from March 14, 2003 (inception) through December 31, 2003, primarily due to increased debt levels associated with the two acquisitions made in 2004 and the four acquisitions made in 2003.

Period from January 1, 2003 through October 31, 2003 Compared to the Year Ended December 31, 2002 (Predecessor)

Revenue

Natural gas and oil sales increased to $4.7 million for the period from January 1, 2003 through October 31, 2003 from $3.8 million for the year ended December 31, 2002. The increase in revenue from natural gas and oil sales was due to the increase in natural gas prices. The key revenue measurements were as follows:

		Year Ended December 31, 2002		Period from January 1, 2003 through October 31, 2003		Percentage Increase (Decrease)
Net Production:
	Total production (MMcfe)		1,195		919	(23	)%
	Average daily production (Mcfe/d)		3,274		3,023	(8	)%
Average Sales Prices per Mcfe:
	Average sales prices (excluding hedges)	$	3.16	$	5.12	62	%

Expenses

Direct operating costs decreased to $2.2 million for the period from January 1, 2003 through October 31, 2003 from $2.4 million for the year ended December 31, 2002 and general and administrative expense decreased to $0.9 million for the period from January 1, 2003 through October 31, 2003 from $1.0 million for the year ended December 31, 2002. The decrease in expenses was due to the fact that the period from January 1, 2003 through October 31, 2003 represented only ten months of operations.

Depreciation, depletion and amortization decreased to $1.2 million for the period from January 1, 2003 through October 31, 2003 from $1.5 million for the year ended December 31, 2002. The decrease was due to lower production during the period from January 1, 2003 through October 31, 2003 and the fact that such period represented only ten months of operations.

Capital Resources and Liquidity

Our primary sources of capital and liquidity since our formation in March 2003 have been private equity, proceeds from bank borrowings and cash flow from operations. To date, our primary use of capital has been for the acquisition and development of natural gas properties. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and planned capital expenditures. Our future success in growing reserves and

production will be highly dependent on capital resources available to us and our success in drilling for or acquiring additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we would need to borrow additional amounts under our credit facility, if available, or obtain additional debt or equity financing. Our credit facility imposes certain restrictions on our ability to obtain additional debt financing. Based upon our current expectations, we believe our liquidity and capital resources will be sufficient for the conduct of our business and operations.

During the nine months ended September 30, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas hedges and realized a loss of $38.3 million. As a result, working capital and members' capital (deficit) were reduced by $38.3 million and were $(15.0) million and $(52.1) million, respectively, at September 30, 2005. We subsequently hedged similar volumes at higher prices, which will result in substantially higher cash flow from operations for future periods. At September 30, 2005, our working capital was $(15.1) million primarily due to unrealized losses on natural gas swaps of $22.3 million, which will not require expenditures of additional cash at maturity as they will be settled with proceeds from the sale of physical natural gas production in the future.

Cash Flow from Operations

Net cash (used in) provided by operating activities was $(36.7) million and $7.0 million for the nine months ended September 30, 2005 and 2004, respectively. The decrease in net cash provided by operating activities was due substantially to the realized hedging loss during the nine month period. During the nine months ended September 30, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money hedges and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices. Changes in assets and liabilities (reduced) increased cash flow from operations by $(4.3) million and $0.4 million for the nine months ended September 30, 2005 and 2004, respectively.

Net cash provided by operating activities was $11.4 million during the year ended December 31, 2004, compared to $0.9 million during the period from March 14, 2003 (inception) to December 31, 2003. The increase in net cash provided by operating activities in 2004 was substantially due to increased revenues, partially offset by increased expenses, as discussed above in " — Results of Operations." Changes in current assets and liabilities increased cash flow from operations by $1.3 million in 2004 and reduced cash flow from operations by $0.6 million in 2003.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of natural gas prices. Natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on our ability to maintain and increase production through our drilling program and acquisitions, as well as the prices of natural gas and oil.

We enter into hedging arrangements to reduce the impact of natural gas price volatility on our operations. Currently, we use fixed price swaps and puts to hedge NYMEX natural gas prices, which do not include the additional net premium we typically realize in the Appalachian Basin. At November 30, 2005, we had in place natural gas swap and put contracts covering significant portions of our estimated 2005 through 2009 natural gas production. For the year ending December 31, 2006, we currently have fixed price swaps and puts in place for a total hedged

amount of 8,142 MMMBtu, which represents approximately 94% of our total expected production volume of 8,655 MMcfe.

By removing the price volatility from a significant portion of our natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers.

The following table summarizes, for the periods indicated, our hedges currently in place through December 31, 2009. Currently, we use fixed price swaps and puts as our mechanism for hedging commodity prices. These transactions are settled based upon the NYMEX price of natural gas at Henry Hub on the final trading day of the month and settlement occurs on the 3^rd day of the production month.

	Fixed Price Swaps and Puts
Period	Hedged Volume (MMMBtu)	Average Price ($/MMBtu)
4^th Quarter 2005	1,344	$	7.74
Year 2006	8,142	$	9.22
Year 2007	7,898	$	8.60
Year 2008	6,904	$	7.89
Year 2009	5,125	$	7.25

Investing Activities — Acquisitions and Capital Expenditures

Our capital expenditures were $28.0 million and $41.0 million for the nine months ended September 30, 2005 and 2004, respectively. The total for the nine months ended September 30, 2005 includes $16.0 million for drilling, development and exploitation of natural gas properties, $4.3 million for the acquisition of wells from CNR, $5.2 million for GasSearch, $1.6 million for the acquisition of additional working interests in our current wells and $0.9 million for furniture, fixtures and equipment. The total for the nine months ended September 30, 2004 includes $13.3 million for drilling, development and exploitation of natural gas properties, $11.7 million for the acquisition of wells from Mountain V, $14.2 for the acquisition of wells from Pentex, $0.9 million for the acquisition of additional working interests in our current wells, and $0.9 million for furniture, fixtures and equipment.

Our capital expenditures were $47.5 million in the year ended December 31, 2004 and $52.3 million for the period from March 14, 2003 (inception) through December 31, 2003. The total for 2004 includes $29.3 million for acquisitions, $16.7 million for drilling, development and exploitation of natural gas properties, and $1.5 million for furniture, fixtures and equipment. The total for 2003 includes $51.7 million for acquisitions, $0.2 million for drilling (pre-payment for 2004 drilling), development and exploitation of natural gas properties, and $0.4 million for furniture, fixtures and equipment.

We currently anticipate that our drilling budget, which predominantly consists of drilling, infrastructure projects and equipment, will be $22.7 million for 2005. As of November 30, 2005, we had $17.4 million available for borrowing under our credit facility. Giving effect to this offering and the application of the net proceeds therefrom, our borrowing capacity is expected to be

$79.4 million, assuming the current borrowing base of $225.0 million. The amount and timing of our capital expenditures is largely discretionary and within our control. If natural gas prices decline below acceptable levels, we could choose to defer a portion of our planned capital expenditures until later periods. We routinely monitor and adjust our capital expenditures in response to changes in natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and crews. Based upon current natural gas price expectations for 2005, we anticipate that the proceeds of this offering, our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2005. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Sales and Issuances of Securities. During 2003, we raised $16.0 million, net of costs, from the sale of membership interests to members of management and private equity investors, including Quantum Energy Partners.

Credit Facility. On May 30, 2003, we entered into a $75.0 million senior secured credit facility (the prior credit agreement), which allowed us to borrow up to the determined amount of the borrowing base, which was based upon the loan collateral value assigned to our various natural gas and oil properties. A majority of our producing natural gas and oil properties served as collateral. The borrowing base was subject to semi-annual redetermination. The prior credit agreement was amended twice in 2003, increasing the borrowing base to $42.0 million. In 2004, the borrowing base was increased to $73.0 million.

Under the prior credit facility and as of December 31, 2004 and 2003, we had borrowed $72.6 million and $41.8 million, respectively. As of December 31, 2004, the applicable weighted average interest rate was 4.1%, and as of December 31, 2003, the applicable average interest rate was 3.2%.

The prior credit agreement required us, among other things, to maintain a minimum working capital balance and achieve certain earnings-related ratios and limited the amount of indebtedness and certain distributions. The working capital and earnings-related ratios were calculated based on tax basis financial statements. At December 31, 2004 and 2003, we were in compliance with all covenants.

On April 11, 2005, we entered into a new $200.0 million secured revolving credit facility with BNP Paribas, as administrative agent, RBC Capital Markets, as syndication agent, and other lenders which replaced our prior credit agreement. The new credit facility matures on April 11, 2009. The amount available for borrowing at any one time is limited to the borrowing base, which is currently set at $225.0 million. Our increased borrowing base takes into account the additional reserves acquired from Exploration Partners effective September 30, 2005. In connection with this acquisition, the aggregate commitments available under our credit facility were increased to $300.0 million. The borrowing base will be redetermined semi-annually by the lenders in their sole discretion, based on, among other things, reserve reports as prepared by reserve engineers taking into account the natural gas and oil prices at such time.

Our obligations under the new credit facility are secured by mortgages on our natural gas and oil properties as well as a pledge of all ownership interests in our operating subsidiaries. We are required to maintain the mortgages on properties representing at least 80% of our natural gas and oil properties. Additionally, the obligations under the new credit facility are guaranteed by all of our operating subsidiaries and may be guaranteed by any future subsidiaries.

As of November 30, 2005, we had borrowings of $267.0 million outstanding under our new credit facility and subordinated term loan. We used the borrowings under the new credit facility to:

•: repay all outstanding amounts under our previous credit facility, which we used to finance our acquisitions and meet working capital requirements;
•: repay a $5.0 million subordinated term loan from First National Bank Albany Breckenridge;
•: pay expenses incurred in connection with the closing of the new credit facility;
•: fund the $4.3 million purchase price of assets from Columbia Natural Resources, LLC;
•: fund the $5.4 million purchase price of GasSearch Corporation;
•: pay $38.3 million in connection with the cancelled (before their original settlement date) portion of out-of-the-money natural gas hedges; and
•: fund the $115.3 million purchase price of the assets from Exploration Partners, LLC.

We anticipate that $122.0 million of the proceeds from this offering will be used to reduce amounts outstanding under the new credit facility.

Borrowings under the new credit facility are available for development, exploitation and acquisition of natural gas and oil properties, working capital and general corporate purposes.

At our election, interest is determined by reference to:

•: the London interbank offered rate, or LIBOR, plus an applicable margin between 1.25% and 1.875% per annum; or
•: a domestic bank rate plus an applicable margin between 0% and 0.375% per annum.

Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans.

The new credit facility contains various covenants that limit our ability to:

•: incur indebtedness;
•: grant certain liens;
•: make certain loans, acquisitions, capital expenditures and investments;
•: make distributions other than from available cash;
•: merge or consolidate; or
•: engage in certain asset dispositions, including a sale of all or substantially all of our assets.

The new credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

•: consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0; and
•: consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under SFAS No. 133, which includes the current portion of natural gas and interest rate swaps.

Upon completion of this offering, we will have the ability to borrow under the new credit facility to pay distributions to unitholders as long as there has not been a default or event of default and if the amount of borrowings outstanding under our credit facility is less than 90% of the borrowing base.

We believe that we are in compliance with the terms of our new credit facility. If an event of default exists under the new credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

•: failure to pay any principal when due or any interest, fees or other amount within certain grace periods;
•: a representation or warranty is proven to be incorrect when made;
•: failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;
•: default by us on the payment of any other indebtedness in excess of $1.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;
•: bankruptcy or insolvency events involving us or our subsidiaries;
•: the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;
•: failure to pay in full, on or before March 31, 2006, all amounts owing on the subordinated term loan described below;
•: specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1.0 million in any year; and
•: a change of control, which includes (1) a decrease to 25% or less of our management's and Quantum Energy Partners' aggregate ownership in us combined with the acquisition by a third party of more than 35% of our units, or (2) the replacement of a majority of our directors by persons not approved by our board of directors.

Subordinated Term Loan. On October 27, 2005, we entered into a facility for a $60 million second lien senior subordinated term loan (subordinated term loan) with Royal Bank of Canada, as administrative agent, Societe Generale, as syndication agent, and other lenders.

Our obligations under the subordinated term loan are secured by second subordinated liens in the same collateral that secures our obligations under the new credit facility and guaranteed by all of our operating subsidiaries and may be guaranteed by any future subsidiaries.

The proceeds of the subordinated term loan were used to fund a portion of the purchase price for the acquisition of natural gas and oil properties from Exploration Partners.

We anticipate that $60.0 million of the proceeds from this offering will be used to pay in full all amounts owing on the subordinated term loan.

The terms of the subordinated term loan are the same as the new credit facility except as follows:

•: interest, at our election, is determined by either (i) the London interbank offered rate, or LIBOR, plus an applicable margin of 3.875% or (ii) a domestic bank rate plus an applicable margin of 2.375%;
•: interest is generally payable quarterly for domestic bank rate loans and at the sooner of the applicable maturity date or three-month intervals for LIBOR loans;
•: the maturity date of the subordinated term loan is April 30, 2006;
•: any principal amounts that are repaid on the subordinated term loan may not be reborrowed; and
•: the subordinated term loan was advanced on October 28, 2005 in a single $60 million advance and is not governed or affected by a borrowing base.

Contractual Obligations. A summary of our contractual obligations as of December 31, 2004 is provided in the following table.

		Payments Due By Year(1)(2)
		2005		2006		2007		2008		2009		After 2009		Total
		(in thousands)
Long-term notes payable		$	58	$	61	$	65	$	64	$	14	$	336	$	598
Management compensation(3)			345		357		368		380		393		—		1,843
Credit facility(4)			—		—		72,605		—		—		—		72,605
Office and office equipment leases(5)			116		115		87		89		38		—		445
Asset retirement obligation			—		—		—		—		—		3,857		3,857

	Total	$	519	$	533	$	73,125	$	533	$	445	$	4,193	$	79,348

(1): This table does not include any liability associated with derivatives.
(2): This table does not include any liability associated with the interest on the credit facility as interest rates are variable and principal balances fluctuate from period to period.
(3): This table does not include any liability associated with management compensation subsequent to 2009 as there is no estimated termination date of the employment agreements.
(4): On April 11, 2005, we entered into a new credit facility and used borrowings under the new credit facility to repay our old credit facility. As of November 30, 2005, $267.0 million was outstanding under our new credit facility and the subordinated term loan. For a description of our new credit facility, please read " — Financing Activities." Does not include interest as interest rates are

variable and principal balances fluctuate significantly from period to period. Based on the December 31, 2004 credit facility balance of $72.6 million, and a weighted average interest rate of 4.1%, the annual interest expense would be approximately $3.0 million.

(5): Represents potential continuing lease payments under our prior office lease. We moved our principal office to a new facility during September 2005. The lease on our prior office space, which expires in 2009, allows us to sublease that facility with the approval of the lessor. If we are unable to sublease that facility, we will be required to make lease payments until 2009 in an aggregate amount of approximately $373,000.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. After our initial public offering, we will discuss the development, selection and disclosure of each of these with our audit committee. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. Please read Note 1 of the Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.

Natural Gas and Oil Properties

We account for natural gas and oil properties by the successful efforts method. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depreciation and depletion of producing natural gas and oil properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Statement of Financial Accounting Standards (SFAS) No. 19 — Financial Accounting and Reporting for Oil and Gas Producing Companies requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described in Note 14 of the Notes to the Consolidated Financial Statements, proved reserves are estimated by an independent petroleum engineer, Schlumberger Data and Consulting Services, and are subject to future revisions based on availability of additional information. As described in Note 10 of the Notes to the Consolidated Financial

Statements, we follow SFAS No. 143 — Accounting for Asset Retirement Obligations. Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

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

Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is credited to income. On sale or retirement of an individual well the proceeds are credited to accumulated depreciation and depletion.

Natural gas and oil properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved natural gas and oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2003 and 2004, the estimated undiscounted future cash flows for our proved natural gas and oil properties exceeded the net capitalized costs, and no impairment was required to be recognized.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Property acquisition costs are capitalized when incurred.

Natural Gas and Oil Reserve Quantities

Our estimate of proved reserves is based on the quantities of natural gas and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Schlumberger Data and Consulting Services prepares a reserve and economic evaluation of all our properties on a well-by-well basis.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and oil eventually recovered.

Revenue Recognition

Sales of natural gas and oil are recognized when natural gas has been delivered to a 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 price is fixed or determinable. We sell natural gas on a monthly basis. Virtually all of our contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas contracts are customary in the industry.

We currently use the "Net-Back" method of accounting for transportation arrangements of our natural gas sales. We sell natural gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our customers and reflected in the wellhead price.

Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at December 31, 2004 or 2003.

Natural gas marketing is recorded on the gross accounting method. Chipperco, our marketing subsidiary which began operations effective November 1, 2004, purchases natural gas from many small producers and bundles the natural gas together to sell in larger amounts to purchasers of natural gas for a price advantage. Chipperco has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because Chipperco takes title to the natural gas it purchases from the various producers and bears the risks and enjoys the benefits of that ownership. Chipperco had natural gas marketing revenues of $520,340 and natural gas marketing expenses of $481,993 in 2004.

Natural gas gathering and transportation revenue is recognized when the gas has been delivered to a custody transfer point. We perform natural gas gathering activities pursuant to which we gather and transport third party gas to a downstream pipeline. We only transport, and do not take ownership of, such third party gas.

We are paid a monthly operating fee for each well we operate for outside owners. The fee covers monthly operating and accounting costs, insurance and other recurring costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted against general and administrative expense.

Derivative Instruments and Hedging Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas production by reducing our exposure to price fluctuations. Currently, these transactions are swaps and puts. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate our interest rate exposure. We account for these activities pursuant to SFAS No. 133 — Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. SFAS No. 133 requires that a company formally document, at the inception of a hedge, the hedging relationship and the company's risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

A put option requires us to pay the counterparty the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed floor over the floating market price. The costs incurred to enter into the transactions are expensed as incurred, and the change in fair market value of the instrument is reported in the statement of operations each period.

We did not specifically designate the derivative instruments we established in 2003 and 2004 as hedges under SFAS No. 133, even though they protected us from changes in commodity prices. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these amounts represent non-cash charges.

For derivative instruments designated as cash flow hedges, changes in fair market value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative instrument's fair market value. Any ineffective portion of the derivative instrument's change in fair market value is recognized immediately in earnings.

Acquisitions

The establishment of our initial asset base since inception in March 2003 has included eight acquisitions of natural gas and oil properties. These acquisitions have been accounted for using the purchase method of accounting.

Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company's assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. Goodwill is assessed for impairment at least annually. In each of our acquisitions it was determined that the purchase price did not exceed the fair value of the net assets acquired. Therefore, no goodwill was recorded.

There are various assumptions we make in determining the fair values of acquired assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the natural gas and oil properties acquired. To determine the fair values of these properties, we prepare estimates of natural gas and oil reserves. These estimates are based on work performed by our engineers and that of outside consultants. The fair value of reserves acquired in a business combination must be based on our estimates of future natural gas and oil prices and not the prices at the time of the acquisition. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They also are based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis.

Forecasts of future prices from independent third parties are noted when we make our pricing estimates.

We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the business combination based upon our cost of capital.

We also apply these same general principles in arriving at the fair value of unevaluated properties acquired in a business combination. These unevaluated properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing probable and possible reserves, we apply a risk-weighting factor to probable and possible volumes to reduce the estimated reserve volumes. Additionally, we increase the discount factor, compared to proved reserves, to recognize the additional uncertainties related to determining the value of probable and possible reserves.

Stock Based Compensation

We account for Stock Based Compensation pursuant to SFAS No. 123(R)—Share-Based Payment. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement and eliminates the alternative to use the intrinsic value method of accounting that was provided in SFAS No. 123, which generally resulted in no compensation expense recorded in the financial statements related to the issuance of equity awards to employees. It establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all companies to apply a fair-value-based measurement method in accounting for generally all share-based payment transactions with employees. On March 29, 2005, the SEC staff issued SAB No. 107, Share-Based Payment, to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff's views regarding the valuation of share-based payment arrangements for public companies.

New Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141 — Business Combinations, which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142 — Goodwill and Other Intangible Assets, which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. There had been industry wide uncertainty as to whether SFAS No. 142 required registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and natural gas property costs. However, in September 2004 the FASB issued FASB Staff Position (FSP) No. 142-2 — Application of FASB Statement No. 142, "Goodwill and Other Intangible Assets," to Oil- and Gas-Producing Entities, which clarifies that drilling and mineral rights of oil- and gas-producing entities that are within the scope of SFAS No. 19 — Financial Accounting and Reporting by Oil and Gas Producing Companies are tangible assets. Historically, we have included the costs of such mineral rights as a component of natural gas and

oil properties, which is consistent with FSP No. 142-2. As such, our consolidated financial statements were not affected.

In December 2003, the FASB issued FASB Interpretation (FIN) No. 46 (revised December 2003) — Consolidation of Variable Interest Entities, which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and, accordingly, should consolidate the entity. We apply FIN No. 46R to variable interests in variable interest entities created after December 31, 2003. For variable interests in variable interest entities created before January 1, 2004, this interpretation will be applied beginning on January 1, 2005. For any variable interest entities that must be consolidated under FIN No. 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the variable interest entity initially would be measured at their carrying amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect of an accounting change. If determining the carrying amounts is not practicable, fair value at the date FIN No. 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the variable interest entity. We have evaluated the impact of FIN No. 46R and have determined that there are no entities that qualify as variable interest entities.

On March 30, 2005, the FASB issued FIN No. 47 — Accounting for Conditional Asset Retirement Obligations. This interpretation clarifies that the term "conditional asset retirement obligation" as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 will be effective for us at the end of the fiscal year ended December 31, 2005. We do not expect the application of FIN No. 47 to have a significant impact on our financial position or results of operations.

On April 4, 2005, the FASB issued FSP No. 19-1 — Accounting for Suspended Well Costs. This staff position amends SFAS No. 19 — Financial Accounting and Reporting by Oil and Gas Producing Companies and provides guidance about exploratory well costs to companies which use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well's economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management's evaluation of capitalized exploratory well costs. In addition, FSP No. 19-1 requires annual disclosure of:

•: net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves;

•: the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling; and
•: an aging of exploratory well costs suspended for greater than one year with the number of wells it related to.

Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in FSP No. 19-1 is required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. We do not expect the application of FSP No. 19-1 to have a significant impact on our financial position or results of operations.

Quantitative and Qualitative Disclosure About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

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

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

Based on a natural gas price of $6.18 as of December 31, 2004, the fair value of our hedge positions for 2005 was a liability of $2.7 million, which we owe to the counterparty. A 10% increase in the index natural gas price above the December 31, 2004 price for 2005 would increase the liability by $1.4 million; conversely, a 10% decrease in the index natural gas price would decrease the liability by $1.4 million.

As of September 30, 2005, the fair market value of our derivative positions was a liability of $38.3 million, which we owe to the respective counterparties. The hedges for the remainder of 2005 and through December 2009 are summarized in the table presented above under " — Cash Flow from Operations."

Interest Rate Risks

At September 30, 2005, we had debt outstanding of $139.0 million, which incurred interest at floating rates in accordance with our revolving credit facility. The average annual interest rate incurred on this debt for the year ended December 31, 2004 was 3.6%. A 1% increase in LIBOR as of December 31, 2004 would result in an estimated $0.6 million increase in annual interest expense.

In 2003, we entered into two interest rate swap agreements to minimize the effect of fluctuation in interest rates. The agreements have a notional amount of $30 million each. The interest rate swap agreements settle quarterly in 2005 and 2006, and we are required to pay at a rate of 3.2% and 4.3%, respectively. In 2004, we entered into two additional interest rate swap agreements with a notional amount of $50 million each. The new interest rate swaps settle quarterly in 2007 and 2008, and we are required to pay a rate of 5.2% and 5.7%, respectively. In 2005, in connection with our new credit facility, we transferred these four interest rate swap agreements to a different third party financial institution. As a consequence of the transfer of these four agreements, the fixed interest rate we pay on each agreement increased by seven basis points.

Also in 2004, we entered into two interest rate swap agreements with a notional amount of $20 million each. The agreements are settled quarterly in 2005 and 2006. We are required to pay at a rate of 3.1% and 4.4%, respectively.

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

We did not specifically designate the interest rate swap agreements we entered into in 2003 and 2004 as hedges under SFAS No. 133, even though they protect us from changes in interest rates. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these amounts represent non-cash charges.

BUSINESS

Overview

Linn Energy, LLC is an independent natural gas company focused on the development, exploitation and acquisition of natural gas properties in the Appalachian Basin, primarily in Pennsylvania, West Virginia, New York and Virginia. Our goal is to provide stability and growth in distributions to our unitholders through a combination of continued successful drilling and acquisitions. Our company was formed in March 2003 by our President and Chief Executive Officer Michael C. Linn, Quantum Energy Partners and non-affiliated investors with an aggregate equity investment of $16.3 million. Since inception, we have made nine acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate purchase price of $203.2 million, with total proved reserves of 160.1 Bcfe, or an acquisition cost of $1.27 per Mcfe. Our nine acquisitions included 1,914 producing wells and we have drilled 191 wells since inception, 100% of which were successful in producing natural gas in commercial quantities. At November 30, 2005, our production was approximately 21.6 MMcfe per day from 2,105 wells.

Our proved reserves at September 30, 2005 were 189.6 Bcfe, of which approximately 99% were natural gas and 66% were classified as proved developed, with a Standardized Measure of $898.7 million. At November 30, 2005, we operated 1,913, or 91%, of our 2,105 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 29 years based on our September 30, 2005 reserve report and annualized pro forma production for the nine months ended September 30, 2005. As of September 30, 2005, we had identified 362 proved undeveloped drilling locations and over 500 additional drilling locations. As of September 30, 2005, we had a leasehold interest in 140,045 net acres in the Appalachian Basin. From inception through September 30, 2005, we added 27.2 Bcfe of proved natural gas and oil reserves through our drilling activities, at a finding and development cost of $1.21 per Mcfe, which includes the estimated development costs for proved undeveloped reserves.

Recent Developments

On October 27, 2005, we acquired from Exploration Partners, LLC and related working interest owners interests in 550 wells located in 12 counties in West Virginia and one county in Virginia. Most of the wells are located adjacent to our existing operations. We expect to operate 424, or 77%, of the total wells acquired. We also acquired approximately 250 miles of natural gas gathering systems, which deliver 6.7 MMcf/d to eight different purchasers through 110 delivery points, as well as related oilfield service equipment. The oilfield services will be conducted through our subsidiary Mid Atlantic Well Service, Inc. Additionally, we acquired, pursuant to a standard farm out agreement, the option to drill on approximately 10,000 undeveloped acres in northern West Virginia. As of November 30, 2005, we had identified 105 proved undeveloped drilling

locations and 117 additional drilling locations on this acreage and at this time expect to drill 25 wells there annually.

Acquisition History

We have focused on acquiring properties which provide the following characteristics: established production history, long reserve life, low finding and development expenditures, high drilling success rate and a high concentration of natural gas. We continuously evaluate our assets to maximize and exploit their value. We focus on acquisitions that allow us to:

•: Increase production through workovers, addition of equipment, improved field operations as well as additional infill drilling and other development activities; and
•: Implement efficiencies through operational and administrative consolidation.

Date	Seller	Wells	Location	Purchase Price (in millions)
May 2003	Emax Oil Company	34	West Virginia	$	3.1
Aug 2003	Lenape Resources, Inc.	61	New York		2.0
Sep 2003	Cabot Oil & Gas Corporation	50	Pennsylvania		15.5
Oct 2003	Waco Oil & Gas Company	353	West Virginia and Virginia		31.0
May 2004	Mountain V Oil & Gas, Inc.	251	Pennsylvania		12.4
Sep 2004	Pentex Energy, Inc.	447	Pennsylvania		14.2
Apr 2005	Columbia Natural Resources, LLC	38	West Virginia and Virginia		4.3
Aug 2005	GasSearch Corporation	130	West Virginia		5.4
Oct 2005	Exploration Partners, LLC	550	West Virginia and Virginia		115.3

	Total	1,914		$	203.2

Business Strategy

Our goal is to provide stability and growth in distributions to our unitholders through a combination of continued successful drilling, acquisitions, increasing production of existing wells and pursuing operational and administrative efficiencies. The key elements of our business strategy are:

•: Executing low risk, low cost exploitation drilling;
•: Focusing on acquisitions that increase cash available for distribution;
•: Creating additional value post-acquisition;
•: Maximizing the value and stability of our cash flows through operating control; and
•: Reducing commodity price risk through hedging.

Competitive Strengths

We believe our competitive strengths will result in a sufficient level of cash available for distribution and provide strong growth potential. Our competitive strengths are:

•: Low Risk, Low Cost Exploitation Drilling — From inception through November 30, 2005, we drilled 191 wells, 100% of which were successful in producing natural gas in commercial quantities. From inception through September 30, 2005, our finding and development cost was $1.21 per Mcfe, which includes the estimated development costs for proved undeveloped reserves. Our average well takes five days to drill and is expected to have an average cost of $225,000 in 2005. Most of our wells are producing and connected to a pipeline within 60 days (some as quickly as 11 days) after drilling has commenced.
•: Strong Acquisition Track Record — To date, we have made nine acquisitions with an average purchase price of $1.27 per Mcfe. In addition, we have focused on production enhancement and cost reductions with respect to the acquired properties. We achieve production increases through well workovers, by installing additional equipment such as pump jacks or by conducting minor repairs on gathering lines to return previously shut-in wells to production. We believe that there is significant potential for future acquisitions in the Appalachian Basin, which has several thousand independent operators.
•: Large Undeveloped Land Base — At September 30, 2005, we had leases totaling 140,045 net acres with 362 identified proved undeveloped drilling locations and over 500 additional identified drilling locations. We continually acquire new lease positions to increase potential drilling locations.
•: Operating Control — As of November 30, 2005, we operated 1,913, or 91%, of our total 2,105 producing wells and we will operate 104 of the 110 wells targeted to be drilled during 2005. During 2004, more than 98% of our revenues were derived from wells we operated. In addition, we gather more than 90% of our existing and expected production. We target acquisitions that allow us to consolidate operational and administrative functions.
•: Experienced Operator in the Appalachian Basin — Michael C. Linn, our President and Chief Executive Officer, and key members of our management team, Gerald W. Merriam and Roland "Chip" P. Keddie, have been involved in the natural gas and oil business in Appalachia for an average of 25 years and have a very successful track record of drilling and acquiring assets in the basin. We do not maintain key person insurance on members of our management team nor do we anticipate doing so.
•: Long Life Reserves — Our average reserve life is 29 years based on our September 30, 2005 proved reserves and annualized pro forma production for the nine months ended September 30, 2005.
•: Production Diversification — At November 30, 2005, our production was approximately 21.6 MMcfe per day from 2,105 producing wells from four states in the Appalachian Basin, including 798 wells in Pennsylvania, 1,234 wells in West Virginia, 61 wells in New York and 12 wells in Virginia. Our largest well accounts for less than 1% of our total production. As a result of the large number of wells, damage to any one well or group of wells or the curtailment of a gathering system in one particular area is not likely to have a material adverse effect on our cash available for distribution.

•: Premium Pricing — As of December 31, 2004, our average realized natural gas prices, net of gathering fees, represented a $0.67 per Mcf premium to NYMEX natural gas prices due to our proximity to major natural gas consuming markets in the northeastern United States and the relatively high Btu content associated with our production.

Drilling

Most of our wells are relatively shallow, ranging from 2,500 to 5,500 feet, and drill through as many as ten potential producing zones. Many of our wells are completed to multiple producing zones and production from these zones may be commingled. Our average well cost for 2005 is expected to be approximately $225,000, resulting in average net reserves of 200 MMcfe. In general, our producing wells have stable production profiles and long-lived production, often with total projected economic lives in excess of 50 years. Once drilled and completed, operating and maintenance requirements for producing wells in the Appalachian Basin are generally low and only minimal, if any, capital expenditures are required. Appalachian wells typically are drilled on relatively close spacing of between 20 to 40 acres per well due to the low permeability of the producing formations. Generally, the distance between wells is less than 1,500 feet and wells are located within 1,000 feet from the closest pipeline. As a result, most of our wells are producing and connected to a pipeline within 60 days (some as quickly as 11 days) after drilling has commenced.

Wells in the Appalachian Basin are typically drilled at relatively low cost due to the shallow drilling depths and the ability to use air drilling. Most of the drilling rigs are small pull-down type rigs that can be set up on very small locations that are typically 60 feet wide and 160 feet long. These small rigs can be transported to the drilling locations at relatively low cost. Further, the use of air drilling greatly reduces the size of any pits for drilling fluids needed on location.

From inception through September 30, 2005, we spent $32.9 million and drilled 168 wells, all of which produce natural gas in commercial quantities with an average finding and development cost of $1.21 per Mcfe, which includes the estimated development costs for proved undeveloped reserves. To carry out our active drilling program, we are currently utilizing three drilling rigs that are under contract for our 2005 drilling program. As of September 30, 2005, we had 362 proved undeveloped drilling locations (specific drilling locations as to which Schlumberger Data and Consulting Services assigned proved undeveloped reserves as of such date) and we had identified over 500 additional unproved drilling locations (specific drilling locations as to which Schlumberger Data and Consulting Services did not assign any proved reserves as of such date but as to which we have identified as future drilling locations that we expect to drill based on our current drilling schedule) on acreage that we have under existing leases. As successful development wells in the Appalachian Basin frequently result in the reclassification of adjacent lease acreage from unproved to proved, we expect that a significant number of our unproved drilling locations will be reclassified as proved drilling locations prior to the actual drilling of these locations. During 2005, we anticipate spending $23.6 million to drill 110 wells, 104 of which we will operate. As of November 30, 2005, we had drilled 101 out of our planned 110 wells.

Appalachian Basin

The Appalachian Basin is one of the country's oldest natural gas producing regions characterized by long-lived reserves and predictable decline rates. During the first several years of production, Appalachian Basin wells generally experience higher initial production rates and

decline rates which are followed by an extended period of significantly lower production rates and decline rates. For example, the initial production rate of our new wells may be as high as 80 to 100 Mcf per day while our average production rate during 2004 per well was 10.7 Mcf per day. The average well production in the Appalachian Basin is 10 Mcf per day or less and decline rates typically range from 2% to 6% per year.

The Appalachian Basin spans more than seven states in the largest natural gas consuming region of the United States. The close proximity to major natural gas consuming markets in the northeastern United States results in lower transportation costs to these markets relative to natural gas produced in other regions, contributing to the premium pricing for Appalachian production relative to NYMEX. Further, supply of natural gas from the Midwest, Rockies and Canadian regions may face transportation and storage capacity constraints during peak winter season.

Reserves in the Appalachian Basin typically have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

Our activities are concentrated in four major geologic formations within the Appalachian Basin: the Devonian Sands in north central West Virginia and southwestern Pennsylvania, the Mississippian Limestone and Sands in southern West Virginia, the Clinton/Medina Formation in western New York and the Oriskany Sands in southwestern Pennsylvania.

Natural Gas Prices

Natural gas produced in the Appalachian Basin typically sells for a premium to NYMEX natural gas prices due to the proximity to major consuming markets in the northeastern United States. For the year ended December 31, 2004, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin on the Columbia Gas Transmission Corp. Appalachia Pipeline and the Dominion Transmission Inc. Appalachia Pipeline was $0.26 and $0.35 per Mcf, respectively. In addition, most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices. As of December 31, 2004, our average realized natural gas prices, net of gathering fees, represented a $0.67 per Mcf premium to NYMEX natural gas prices.

We enter into derivative transactions in the form of hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use fixed price swaps and puts to hedge NYMEX natural gas prices. By removing the price volatility from a significant portion of our natural gas production, we have mitigated, but not eliminated, the potential effects of changing natural gas prices on our cash flow from operations for those periods.

Natural Gas and Oil Data

Proved Reserves

The following table presents our estimated net proved natural gas and oil reserves and the present value of our estimated proved reserves at December 31, 2003, December 31, 2004 and September 30, 2005, based on reserve reports prepared by Schlumberger Data and Consulting

Services. A copy of the reserve report related to estimated proved reserves at September 30, 2005 prepared by our independent petroleum engineers is attached as Appendix C. The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the Securities and Exchange Commission in connection with this offering. The Standardized Measure values shown in the table are not intended to represent the current market value of our estimated natural gas and oil reserves.

			As of December 31,				As of September 30,
			2003		2004		2005
Reserve Data:
Estimated net proved reserves:
	Natural gas (Bcf)			68.9		118.9		188.2
	Oil (MMBbls)			0.2		0.1		0.2
		Total (Bcfe)		69.8		119.8		189.6
Proved developed (Bcfe)				41.8		74.4		124.9
Proved undeveloped (Bcfe)				28.0		45.4		64.7
Proved developed reserves as % of total proved reserves				59.9%		62.1%		65.9%
Standardized Measure (in millions)(1)			$	126.3	$	215.0	$	898.7
Representative Natural Gas and Oil Prices(2):
	Natural gas — NYMEX Henry Hub per MMBtu		$	5.97	$	6.18	$	15.36
	Oil — NYMEX WTI per Bbl			32.76		43.00		66.21

(1): Does not give effect to hedging transactions. For a description of our hedging transactions, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations" beginning on page 64.
(2): Natural gas and oil prices as of each period end were based on NYMEX prices per MMBtu and Bbl at such date, with these representative prices adjusted by field to arrive at the appropriate net price. Due to NYMEX trading interruptions on September 30, 2005 as a result of Hurricane Katrina, natural gas prices were based on the Appalachian spot prices per MMBtu at such date.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

The data in the above table represents estimates only. Natural gas and oil reserve engineering is inherently a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of natural gas and oil that are ultimately recovered. Please read "Risk Factors."

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown should not be construed as the current market value of the reserves. The 10% discount factor

used to calculate present value, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage Schlumberger Data and Consulting Services to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither Schlumberger Data and Consulting Services nor any of their respective employees has any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties. During 2003 and 2004, we paid Schlumberger Data and Consulting Services $12,149 and $24,195, respectively, for all reserve and economic evaluations.

Production and Price History

The following table sets forth information regarding net production of natural gas and oil and certain price and cost information for each of the periods indicated:

		Period from March 14, 2003 (inception) through December 31, 2003(1)
						Nine Months Ended September 30,
				Year Ended December 31, 2004		Nine Months Ended September 30,
				Year Ended December 31, 2004		2004		2005
Net Production:
	Total production (MMcfe)		802		3,385		2,288		3,240
	Average daily production (Mcfe/d)		3,748		9,274		8,350		11,868
Average Sales Prices per Mcfe:
	Average sales prices (including hedges)	$	5.07	$	5.74	$	5.54	$	6.27
	Average sales prices (excluding hedges)		4.87		6.43		5.95		7.62
Average Unit Costs per Mcfe:
	Operating expenses	$	1.14	$	1.61	$	1.91	$	1.43
	General and administrative expenses		1.05		0.47		0.47		0.71
	Depreciation, depletion and amortization		1.21		1.11		1.05		1.15

(1): In the period ended December 31, 2003, production commenced on May 30, 2003 following the purchase of natural gas properties from Emax Oil Company.

Productive Wells

The following table sets forth information at December 31, 2004, relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the

total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

	Natural Gas Wells
	Gross	Net
Operated	1,232	955
Non-operated	54	13

Total	1,286	968

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2004 relating to our leasehold acreage.

	Developed Acreage(1)		Undeveloped Acreage(2)		Total Acreage
	Gross(3)	Net(4)	Gross(3)	Net(4)	Gross	Net
Operated	69,100	68,895	21,660	21,660	90,760	90,555
Non-operated	95,000	14,250	—	—	95,000	14,250

Total	164,100	83,145	21,660	21,660	185,760	104,805

(1): Developed acres are acres spaced or assigned to productive wells.
(2): Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(3): A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(4): A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Drilling Activity

We intend to concentrate our drilling activity on lower risk, development properties. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well and the estimated recoverable reserves attributable to each well.

The following table sets forth information with respect to wells completed during the year ended December 31, 2004 and for the nine months ended September 30, 2005. We did not complete any drilling operations in the period from March 14, 2003 (inception) through December 31, 2003. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those

that produce commercial quantities of natural gas, regardless of whether they produce a reasonable rate of return.

			Year Ended December 31, 2004	Nine Months Ended September 30, 2005
Gross wells:
	Productive		90	78
	Dry		—	—

		Total	90	78

Net Development wells:
	Productive		82	74
	Dry		—	—

		Total	82	74

Net Exploratory wells:
	Productive		—	—
	Dry		—	—

		Total	—	—

Summary of Exploitation Projects

We are currently pursuing an active exploitation strategy. For 2005, we have budgeted $23.6 million for development drilling, production facilities and other exploitation related projects to implement this strategy. We intend to drill 110 wells in 2005, 104 of which will be operated by us. Of those 104 wells, we estimate that 56 will be located in West Virginia and 48 will be located in Pennsylvania.

Natural Gas Gathering Activities

We own and operate an extensive network of natural gas gathering systems comprised of approximately 780 miles of pipeline and associated compression and metering facilities which connect to numerous sales outlets on eight interstate and eight intrastate pipelines, which allows us to more efficiently transport our gas to market. The interstate market outlets are Dominion Transmission Inc. (West Virginia and Pennsylvania), Columbia Gas Transmission Corp. (West Virginia and Pennsylvania), Cranberry Pipeline (West Virginia), Texas Eastern Pipeline (Pennsylvania), Transco Pipeline (Pennsylvania), Equitrans (West Virginia and Pennsylvania), Equitable Gas Company (West Virginia and Pennsylvania), and Carnegie Gas Company (West Virginia). The intrastate market outlets are Dominion Peoples (Pennsylvania), Dominion Hope (West Virginia), TW Phillips Oil & Gas Company, Inc. (Pennsylvania), Equitable Gas Company (West Virginia and Pennsylvania), Cabot Oil & Gas Corporation (West Virginia), Allegheny Power (West Virginia), National Fuel Gas Distribution (New York) and Lumberport Shinnston Gas Company (West Virginia).

We gather more than 90% of our current production and will gather 104 of the 110 wells we expect to drill in 2005. Our network of natural gas gathering systems permits us to transport

production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to realize:

•: faster connection of newly drilled wells to the existing system;
•: control pipeline operating pressures and capacity to maximize our production;
•: control compression costs and fuel use;
•: maintain system integrity;
•: control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and
•: closely track sales volumes and receipts to assure all production values are realized.

Natural Gas Gathering for Others

We perform limited natural gas gathering activities through our subsidiary Linn Operating on non-jurisdictional gathering systems. We gather for others primarily in Westmoreland and Indiana Counties, Pennsylvania. The fee charged to third party producers is set by contract and ranges from $0.10 to $0.25 per Mcf plus line loss and any compressor fuel. By agreement, Linn Operating does not take title to any third party natural gas. Linn Operating aggregates these volumes with our production and sells all natural gas through its meter(s) to the same purchasers. These revenues are collected and distributed to the third party producers in the normal course of our revenue distribution cycle. Linn Operating's natural gas gathering lines are subject to United States Department of Transportation (US DOT) safety regulations.

Commencing March 1, 2005, our subsidiary Chipperco began operating a new gathering system located in McDowell County, West Virginia and Tazewell County, Virginia with a current throughput volume of 1,200 Mcf/d, comprised of 50% company-owned and 50% third party natural gas. The gathering system is supported by agreements with four other producers pursuant to which Chipperco charges $0.38/dth plus fuel and line loss. Chipperco does not take title to the third party natural gas. Chipperco merely re-delivers this natural gas to a downstream pipeline owned and operated by Cranberry Pipeline, a subsidiary of Cabot Oil & Gas Corporation. As an open access carrier the line is subject to the West Virginia Public Service Commission regulation and US DOT safety standards.

Purchase for Resale

On November 1, 2004, Chipperco purchased the Bessie 8 Pipeline in Indiana County, Pennsylvania and began purchasing and re-selling approximately 600 Mcf/d from other producers connected to it. Chipperco buys this third party production at NYMEX natural gas prices plus $0.12/dth and resells this natural gas into a Dominion Peoples transmission line for NYMEX plus $0.49/dth. We intend to reconfigure other Linn Operating natural gas gathering systems to bring online additional volumes, both company owned and third party owned, to the Bessie 8 Pipeline to increase throughput volumes and revenues. This pipeline is subject to US DOT safety standards.

Operations

General

In general, we seek to be the operator of wells in which we have an interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ drilling, production and reservoir engineers, geologists and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our natural gas properties.

Natural Gas and Oil Leases

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the lease premises. In the Appalachian Basin this amount is typically 1/8^th (12.5%) resulting in a 87.5% net revenue interest to us for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6^th (16.66%) when leases are taken from larger landowners or mineral owners such as coal and timber companies.

Because the acquisition of natural gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32^nd to 1/16^th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%.

Sometimes these third party owners of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us. Normally the retained interest is a 25% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third party operator. In all other instances we anticipate owning a 100% working interest in newly drilled wells.

In almost all of the areas we operate in the Appalachian Basin, the surface owner is normally the natural gas and oil owner allowing us to deal with a single owner. This simplifies the research process required to identify the proper owners of the natural gas and oil rights and reduces the per acre lease acquisition cost and the time required to successfully acquire the desired leases.

Principal Customers

For the year ended December 31, 2004, sales of natural gas to Dominion Field Services, Inc., Cabot Oil & Gas Corporation, PG Energy Inc., Equitable Resources, Inc. and Amerada Hess Corporation accounted for approximately 33%, 19%, 16%, 13% and 9%, respectively, of our total volumes. Sales of natural gas to our top five purchasers during the year ended December 31, 2004, therefore accounted for 90% of our total volumes. For the nine months ended September 30, 2005, sales of natural gas to Dominion, Cabot, Equitable, UGI Energy Services and Amerada Hess accounted for approximately 46%, 21%, 11%, 8% and 6%, respectively, of our total volumes, or 92% in the aggregate. If we were to lose any one of our natural gas purchasers, the loss could temporarily cease or delay production and sale of our natural gas in that particular purchaser's

service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser. However, if one or more of these large natural gas purchasers ceased purchasing natural gas altogether, the loss of these large natural gas purchasers could have a detrimental effect on the natural gas market in general and on our ability to find purchasers for our natural gas.

Hedging Activity

We enter into hedging transactions with unaffiliated third parties with respect to natural gas prices and interest rates to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas prices and interest rates. For a more detailed discussion of our hedging activities, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Overview" and " — Quantitative and Qualitative Disclosures About Market Risk."

Competition

The natural gas and oil industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the natural gas and oil industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program. We are currently utilizing three drilling rigs that are under contract for our 2005 drilling program.

Competition is also strong for attractive natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

Title to Properties

As is customary in the natural gas and oil industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our natural gas properties are subject to customary royalty and other interests, liens for current taxes and other

burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region and, as a result, we generally perform the majority of our drilling during the summer months. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities. To protect against potential environmental risk, we typically obtained Phase I environmental assessment of the properties to be acquired prior to completing each acquisition.

General. Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. These laws and regulations may:

•: require the acquisition of various permits before drilling commences;
•: require the installation of expensive pollution control equipment;
•: restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
•: limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;
•: require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
•: impose substantial liabilities for pollution resulting from our operations; and
•: with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and

regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may impact our properties or operations. For the year ended December 31, 2004, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2005 or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry include the following:

National Environmental Policy Act. Natural gas and oil exploitation and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploitation and production activities, as well as proposed exploitation and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of "hazardous wastes" and the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploitation, development, and production of crude oil, natural gas, or geothermal energy constitute "solid wastes", which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of natural gas and oil exploitation and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the

"Superfund" law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for natural gas and oil exploitation and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe we are substantial compliance with the requirements of the Clean Water Act.

Air Emissions. The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. We believe that we are in substantial compliance with the requirements of the Clean Air Act.

Other Laws and Regulation. The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent

proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Other Regulation of the Natural Gas and Oil Industry

The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

•: the location of wells;
•: the method of drilling and casing wells;
•: the surface use and restoration of properties upon which wells are drilled;
•: the plugging and abandoning of wells; and
•: notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state

generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural Gas Regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission's regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, West Virginia currently imposes a 6% severance tax on natural gas and oil production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon the unitholders.

Employees

As of November 30, 2005, we had 101 full time employees, including two geologists, five petroleum engineers and eight land professionals. Of our 101 full time employees, 24 work in our Pittsburgh office, three in our Houston office and 74 are in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Offices

We currently lease approximately 13,000 square feet of office space in Pittsburgh, Pennsylvania at 650 Washington Road, 8^th Floor, where our principal offices are located. The lease for our Pittsburgh office expires in September 2012. We currently lease an additional 5,000 square

feet of office space in Pittsburgh, Pennsylvania, for which the lease expires in March 2009. We lease approximately 3,000 square feet of office space in Houston, Texas. The lease for our Houston office expires in April 2008. We have field offices in Glenville, West Virginia and Indiana, Pennsylvania.

Legal Proceedings

Effective September 30, 2003, we purchased interests in natural gas and oil wells from Cabot Oil & Gas Corporation for an aggregate purchase price of $15.5 million. On September 27, 2005, Power Gas Marketing & Transmission Inc. filed a complaint styled Power Gas Marketing & Transmission, Inc. v. Cabot Oil & Gas Corporation and Linn Energy in the court of common pleas of Indiana County, Pennsylvania against Cabot and Linn Energy alleging that Cabot conveyed such interests to us in breach of purported preferential purchase rights. Power Gas alleges that Linn Energy interfered with Power Gas' contract rights and demands the right to evaluate whether to exercise its purported preferential purchase rights. We believe that Power Gas' allegations are without merit, intend to vigorously defend the matter and do not believe that the outcome of the matter would have a material adverse effect on our financial position and results of operations.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

MANAGEMENT

Our Board of Directors

Upon completion of this offering, our board of directors will consist of five members, three of whom will satisfy the independence requirements of The Nasdaq National Market and SEC rules. Our current board of directors consists of two members, Messrs. Neugebauer and Linn. Our current board is expected to appoint Messrs. Alcorn, Jacobs and Swoveland as independent directors and as members of the audit committee, the compensation committee and the nominating committee immediately following the pricing of this offering. The current members and the independent members of the board expected to be appointed immediately following the pricing of this offering will be subject to re-election annually as described below. The board intends to appoint four functioning committees immediately following the pricing of this offering: an audit committee, a compensation committee, a conflicts committee and a nominating committee. The additional independent directors to be appointed following this offering are also expected to serve on one or more of the committees described below.

Audit Committee. We currently contemplate that the audit committee will consist of up to three directors. Immediately following the pricing of this offering, all members of the audit committee will be independent under the independence standards established by The Nasdaq National Market and SEC rules, and the committee expects to have an "audit committee financial expert," as defined under SEC rules. The audit committee will recommend to the board the independent public accountants to audit our financial statements and establish the scope of, and oversee, the annual audit. The committee also will approve any other services provided by public accounting firms. The audit committee will provide assistance to the board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor's qualifications and independence and the performance of our internal audit function. The audit committee will oversee our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the board have established. In doing so, it will be the responsibility of the audit committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and management of our company.

Compensation Committee. We currently contemplate that the compensation committee will consist of up to three directors. Immediately following the pricing of this offering, all members of the compensation committee will be independent under the independence standards established by The Nasdaq National Market and SEC rules. The compensation committee will review the compensation and benefits of our executive officers, establish and review general policies related to our compensation and benefits and administer our Long-Term Incentive Plan. The compensation committee will determine the compensation of our executive officers.

Conflicts Committee. We currently contemplate that the conflicts committee will consist of up to three directors. The conflicts committee will review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to our company. Our limited liability company agreement will provide that members of the committee may not be officers or employees of our company or directors, officers or employees of any of our affiliates and must meet the independence standards for service on an audit committee of a board of directors as established by The Nasdaq National

Market and SEC rules. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to our company and approved by all of our unitholders.

Nominating Committee. We currently contemplate that the nominating committee will consist of up to three directors. Immediately following the pricing of this offering, at least one member of the nominating committee will be independent under the independence standards established by The Nasdaq National Market and SEC rules. This committee will nominate candidates to serve on our board of directors and approve director compensation. The nominating committee also will be responsible for monitoring a process to assess director, board and committee effectiveness, developing and implementing our corporate governance guidelines and otherwise taking a leadership role in shaping the corporate governance of our company.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.

During fiscal year 2004, we had no compensation committee. Our board of directors determined executive compensation.

At our first annual meeting of unitholders following this offering, members of our board of directors will be elected by our unitholders and will be subject to re-election on an annual basis at each annual meeting of unitholders.

Our board will hold regular and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board from time to time. Special meetings of the board may be called with reasonable notice to each member upon request of the chairman of the board or upon the written request of any three board members. A quorum for a regular or special meeting will exist when a majority of the members are participating in the meeting either in person or by conference telephone. Any action required or permitted to be taken at a board meeting may be taken without a meeting, without prior notice and without a vote if all of the members sign a written consent authorizing the action.

Our Board of Directors and Executive Officers

The following table shows information for members of our board of directors and our executive officers. Members of our board of directors and our executive officers are elected for one-year terms.

Name	Age	Position with Our Company
Michael C. Linn	53	President and Chief Executive Officer and Director
Kolja Rockov	34	Executive Vice President and Chief Financial Officer
Gerald W. Merriam	47	Executive Vice President-Engineering Operations
Roland "Chip" P. Keddie	52	Executive Vice President-Secretary
Curtis L. Tipton	47	Vice President-Operations
Donald T. Robinson	30	Chief Accounting Officer
Toby R. Neugebauer	34	Chairman
George A. Alcorn	72	Independent Director Nominee
Terrence S. Jacobs	61	Independent Director Nominee
Jeffrey C. Swoveland	50	Independent Director Nominee

Michael C. Linn is the President and Chief Executive Officer and a Director of our company and has served in such capacity since March 2003. From April 1991 to March 2003, Mr. Linn was President of Allegheny Interests, Inc., a private natural gas and oil investment company. From 1980 to 1999, Mr. Linn served as General Counsel (1980-1982), Vice President (1982-1987), President (1987-1990) and CEO (1990-1999) of Meridian Exploration, a private Appalachian Basin natural gas and oil company which was sold to Columbia Natural Gas Company in 1999. Both Allegheny Interests and Meridian Exploration were wholly-owned by Mr. Linn and his family. Mr. Linn is a member of the Independent Petroleum Association of America (IPAA), the largest national trade association of independent natural gas and oil producers. The members of the IPAA elected Mr. Linn to be the Chairman for the 2005 to 2007 term. He currently serves as a member of the Natural Gas Council and the National Petroleum Council and sits on the board of the Natural Gas Supply Association.

Kolja Rockov is the Executive Vice President and Chief Financial Officer of our company. From October 2004 until he joined Linn Energy in March 2005, Mr. Rockov served as a Managing Director in the Energy Group at RBC Capital Markets, where he was primarily responsible for investment banking coverage of the U.S. exploration and production sector. From September 2000 until October 2004, Mr. Rockov was a Director at RBC Capital Markets. Prior to September 2000, Mr. Rockov held various senior positions with Dain Rauscher Wessels and Rauscher Pierce Refsnes, Inc., predecessors of RBC Capital Markets.

Gerald W. Merriam is the Executive Vice President-Engineering Operations of our company and has served in such capacity since April 2003. Prior to joining Linn Energy in April 2003, Mr. Merriam operated as a Senior Engineer for Schlumberger Holditch — Reservoir Technology, a natural gas and oil consulting company, conducting economic and reservoir evaluations of natural gas and oil properties, from March 2001 to March 2003. From January 2001 until March 2001, Mr. Merriam worked as a private consultant in the energy industry. From October 1999 to

January 2001 he was the Vice President of Exploration and Production at North Coast Energy, Inc., a publicly traded independent natural gas and oil exploration and production company. From 1982 to 1997 Mr. Merriam was a Drilling Engineer, Drilling Manager and Engineering Manager for Ashland Exploration, a subsidiary of Ashland Oil Inc. Mr. Merriam currently serves on the board of directors of the Independent Oil and Gas Association of West Virginia and is a member of the Society of Petroleum Engineers, the Independent Oil and Gas Association of Pennsylvania and the Independent Oil and Gas Association of New York.

Roland "Chip" P. Keddie is the Executive Vice President-Secretary of our company and has served in such capacity since April 2003. From January 2001 until April 2003, Mr. Keddie held the position of Project Landman with EOG Resources, Inc. and was responsible for various land services in the Appalachian Basin with a special emphasis on coalbed methane projects. Mr. Keddie formed Gateway Resources Management, LLC, a professional land services business, in October 1999 was its sole member and President until January 2001. He currently serves as a board member of the Independent Oil and Gas Association of Pennsylvania and is a member of the American Association of Petroleum Landmen, the Independent Oil and Gas Association of New York, the Independent Oil and Gas Association of West Virginia and the Independent Petroleum Association of America.

Curtis L. Tipton is the Vice President-Operations of our company. From December 2004 until he joined Linn Energy in April 2005, Mr. Tipton served as Manager of Producer Services for Equitable Gas Company. From January 2000 to December 2004, Mr. Tipton served as Vice President-Business Development of Equitable Field Services (a subsidiary of Equitable Production Company). From March 1997 to December 1999, Mr. Tipton served as Director-Business Development for Eastern States Oil & Gas (acquired by Equitable Production Company).

Donald T. Robinson is the Chief Accounting Officer of our company. Mr. Robinson joined Linn Energy in April 2005. From July 2004 until April 2005, Mr. Robinson was the partner-in-charge of the accounting and auditing department of Toothman Rice PLLC, an independent accounting firm which specializes in the natural gas and oil industry. Mr. Robinson was a manager with Toothman Rice from July 2002 to July 2004. Prior to joining Toothman Rice, Mr. Robinson was an assurance accountant with Arthur Andersen from August 1997 to July 2002. Mr. Robinson is a CPA and a member of the American Institute of Certified Public Accountants and the West Virginia Society of Certified Public Accountants.

Toby R. Neugebauer is the Chairman of our company. Mr. Neugebauer is a co-founder and since 1997 has been a Managing Partner of Quantum Energy Partners, a private equity fund specializing in the energy industry and an affiliate of Linn Energy. Prior to co-founding Quantum Energy Partners in 1997, Mr. Neugebauer co-founded Windrock Capital, Ltd., an energy investment banking firm specializing in raising private equity and providing merger, acquisition and divestiture advice for energy companies. Before co-founding Windrock Capital, Ltd. in 1994, Mr. Neugebauer was an investment banker in Kidder, Peabody & Co.'s Natural Resources Group. Mr. Neugebauer currently serves on the boards of Rockford Energy Partners II, LLC, Ensight Energy Partners, LP, Meritage Energy Partners, LLC, Meritage Energy Partners II, LLC, Denali Oil & Gas Partners, LP, Stratagem Energy Corp. and EnergyQuest Resources, LP., all of which are private energy companies.

George A. Alcorn will be appointed to our board of directors upon completion of this offering. Mr. Alcorn has served as President of Alcorn Exploration, Inc., a private exploration and production company, since 1982. Mr. Alcorn is also a member of the board of directors of EOG

Resources, Inc. He is a past chairman of the Independent Petroleum Association of America and a founding member and past chairman of the Natural Gas Council.

Terrence S. Jacobs will be appointed to our board of directors upon completion of this offering. Mr. Jacobs has served as President of Penneco Oil Company, which provides ongoing leasing, marketing, exploration and drilling operations for natural gas and crude oil in Western Pennsylvania and West Virginia, since 1995. Mr. Jacobs currently serves on the boards of directors of Penneco Oil Company and affiliates, Rockwood Casualty Insurance Company, Somerset Casualty Insurance Company and First Commonwealth Bank. Mr. Jacobs served as President of the Independent Oil and Gas Association of Pennsylvania from 1999 to 2001 and from 2003 to 2005 and has served as a director of the Independent Petroleum Association of America for the states of Delaware, Maryland, Pennsylvania and New York-West since 2000. Mr. Jacobs is a Certified Public Accountant in Pennsylvania.

Jeffrey C. Swoveland will be appointed to our board of directors upon completion of this offering. Mr. Swoveland has served as Chief Financial Officer of Body Media, a life-science company specializing in the design and development of wearable body monitoring products and services, since September 2000. Mr. Swoveland served as Vice President-Finance and Treasurer of Equitable Resources, Inc., a diversified natural gas company, from July 1999 to September 2000. He served as Interim Chief Financial Officer of Equitable Resources, Inc. from October 1997 to July 1999. Mr. Swoveland currently serves as a member of the board of directors of Petroleum Development Corporation.

Executive Compensation

The following table shows the aggregate compensation paid to our President and Chief Executive Officer and our two other most highly compensated executive officers during 2004. Kolja Rockov, our Executive Vice President and Chief Financial Officer, Donald T. Robinson, our Chief Accounting Officer, and Curtis L. Tipton, our Vice President-Operations, joined us in 2005.

								Long-Term Compensation
		Annual Compensation						Awards	Payouts
	Year	Salary ($)		Bonus ($)		Other Annual Compensation(1) ($)		Securities Underlying Options ($)	LTIP Payouts ($)	All Other Compensation ($)
Michael C. Linn President and Chief Executive Officer	2004	$	118,750	$	200,000	$	13,389	—	—	—
Gerald W. Merriam Executive Vice President-Engineering Operations	2004	$	115,572	$	50,000	$	11,811	—	—	—
Roland P. Keddie Executive Vice President-Secretary	2004	$	105,000	$	50,000	$	11,356	—	—	—

(1): Constitutes health insurance premiums.

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Compensation of Directors

Each independent member of our board of directors will receive compensation for attending meetings of the board of directors as well as committee meetings. The amount of compensation to be paid to the independent members of our board will be determined prior to completion of this offering. In addition, each independent member of our board will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a member of our board to the extent permitted under Delaware law.

Employment Agreements

We have agreed to enter into an employment agreement with Michael C. Linn, our President and Chief Executive Officer. Mr. Linn's employment agreement will be effective upon completion of this initial public offering. Mr. Linn's employment agreement provides for an annual base salary of $1.00 for the first 12 months and $250,000 thereafter subject to annual increase. Mr. Linn's employment agreement also provides for incentive compensation payable at the discretion of our board of directors. In addition, under his employment agreement and subject to completion of this offering, Mr. Linn is entitled to receive:

•: a unit option award equal to 0.4% of our outstanding equity interests following the completion of this offering at an exercise price equal to the price per unit in this offering;
•: a one-time cash bonus in the amount of $500,000; and
•: one year from completion of this offering, if Mr. Linn remains employed by us, a unit grant equal to 2.25% of our outstanding equity interests following the completion of this offering.

The unit grant will be fully vested upon issuance. The unit option award will vest in equal annual installments over three years and will vest in full upon a change of control or a termination without cause, with good reason or upon Mr. Linn's death or disability.

The employment agreement also provides for piggy back registration rights with respect to the units to be issued pursuant to the unit option and unit grant following the earlier to occur of 18 months after this offering or the date on which Quantum Energy Partners holds less than 50% of the units it will own immediately following this offering.

In the event of termination by us other than for cause or termination by Mr. Linn for good reason, his employment agreement provides for severance payments in 24 monthly installments at an annual base salary of $250,000 if his employment is terminated in the first 12 months and at his highest base salary in effect at any time during the 36 months prior to the date of termination if terminated thereafter. If, within one year of a change of control, we terminate his employment other than for cause or Mr. Linn terminates his employment for good reason, he will be entitled to receive a lump-sum payment equal to $750,000. The employment agreement prohibits Mr. Linn from soliciting any of our employees or customers as well as from competing with us for a period of two years. The non-compete provision will not be applicable if we terminate Mr. Linn within one year of a change of control.

We have entered into an employment agreement effective as of September 15, 2005 with Kolja Rockov, our Executive Vice President and Chief Financial Officer. Mr. Rockov's employment agreement provides for an annual base salary of $200,000 subject to annual increase, plus a guaranteed cash bonus of not less than $100,000 for the fiscal year ending December 31,

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2005, and incentive compensation payable at the discretion of our board of directors for the remainder of the term of employment.

Upon completion of this offering, Mr. Rockov is entitled to receive:

•

a unit grant and restricted unit award equal to an aggregate 1.25% of our outstanding equity interests following the completion of this offering,

•

a unit option award equal to 0.4% of our outstanding equity interests at an exercise price per unit equal to the price per unit in this offering; and

•

a one-time cash bonus in the amount of:

•: $400,000, if the sum of the net cash proceeds and the value of the units received by Quantum Energy Partners in the offering is less than $279 million;
•: $750,000, if the sum of the net cash proceeds and the value of the units received by Quantum Energy Partners in the offering is at least $279 million but less than $290 million;
•: $1 million, if the sum of the net cash proceeds and the value of the units received by Quantum Energy Partners in the offering is at least $290 million but less than $302 million;
•: $1.25 million, if the sum of the net cash proceeds and the value of the units received by Quantum Energy Partners in the offering is at least $302 million but less than $315 million; or
•: $1.5 million, if the sum of the net cash proceeds and the value of the units received by Quantum Energy Partners in the offering is greater than $315 million.

The restricted unit award will vest in equal installments over two years and the unit option award will vest in equal annual installments over three years. The restricted unit and the unit option award will vest in full upon a change of control or a termination without cause, with good reason or upon Mr. Rockov's death or disability.

The employment agreement also provides for piggy back registration rights with respect to the units to be issued pursuant to the unit option, unit grant and the restricted unit awards following the earlier to occur of 18 months after this offering or the date on which Quantum Energy Partners holds less than 50% of the units it will own immediately following this offering.

If a merger or sale of Linn Energy is consummated prior to the completion of this offering, Mr. Rockov is entitled to receive a one-time cash payment in an amount starting at $500,000 and up to $1,450,000, based upon the amount of the consideration paid for Linn Energy. If this offering is not completed and there has not been a merger or sale of Linn Energy before March 31, 2006, or if our board of directors determines before March 31, 2006 to abandon this offering, Mr. Rockov is entitled to a one-time cash payment in the amount of $500,000.

In the event of termination by us other than for cause or termination by Mr. Rockov for good reason, his employment agreement provides for severance payments in 24 monthly installments at his highest base salary in effect at any time during the 36 months prior to the date of termination. If, within one year of a change of control, we terminate Mr. Rockov's employment other than for cause or he terminates his employment for good reason, he will be entitled to receive a lump-sum payment equal to 36 months of his highest annual base salary during the prior 36 months.

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Mr. Rockov will not be entitled to any severance or change of control payments or benefits if, on or before the date his employment is terminated, he has become entitled to the one-time cash payment due to the merger or sale of Linn Energy prior to a successful initial public offering or the abandonment of this offering. The employment agreement prohibits Mr. Rockov from soliciting any of our employees or customers as well as from competing with us for a period of two years. The non-compete provision will not be applicable if we terminate Mr. Rockov within one year of a change of control.

Long-Term Incentive Plan

We expect to adopt a Linn Energy, LLC Long-Term Incentive Plan for employees, consultants and directors and employees of us and our affiliates who perform services for us. For purposes of the plan, our affiliates will include Linn Operating. The long-term incentive plan will consist of: unit grants, unit options, restricted units, phantom units and unit appreciation rights. The long-term incentive plan will limit the number of units that may be delivered pursuant to awards to 3.9 million units (which include all grants under their employment agreements to Mike Linn and Kolja Rockov equal to an aggregate of 2.65% and 1.65%, respectively, of the outstanding units following completion of this offering), provided that no more than 500,000 of such units (as adjusted) may be issued as restricted units. The plan will be administered by the compensation committee of our board of directors.

Our board of directors and the compensation committee of the board have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant.

Unit Grants. A unit grant is a unit that vests immediately upon issuance. The long-term incentive plan will permit the grant of units in addition to the unit grant at the closing of this offering to Mr. Rockov and the unit grant one year from the closing of the offering to Mr. Linn. Please read "— Employment Agreements" above. In the future, the compensation committee may determine to make grants under the plan to employees and members of our board.

Unit Options. A unit option is a right to purchase a unit at a specified price. The long-term incentive plan will permit the grant of options covering units. In the future, the compensation committee may determine to make grants under the plan to employees and members of our board containing such terms as the committee shall determine. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee, although vesting may accelerate upon the achievement of specified financial objectives. In addition, the unit options will become exercisable upon a change in control of our company, unless provided otherwise by the committee. If a grantee's employment, consulting relationship or membership on the board of directors terminates for any reason, the grantee's unvested unit options will be automatically forfeited unless, and to the extent, the option agreement or the compensation committee provides otherwise. Please read " — Employment Agreements" above for the two unit option grants we have agreed to make to Messrs. Linn and Rockov at closing of this offering.

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Upon exercise of a unit option (or a unit appreciation right settled in units), we will issue new units, acquire units on the open market or directly from any person or use any combination of the foregoing, in the compensation committee's discretion. If we issue new units upon exercise of the unit options (or a unit appreciation right settled in units), the total number of units outstanding will increase. The availability of unit options and unit appreciation rights is intended to furnish additional compensation to employees and members of our board of directors and to align their economic interests with those of unitholders.

Restricted Units. A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture. Initially, other than the restricted unit grants at closing of this offering to Mr. Rockov, our Executive Vice President and Chief Financial Officer, (please read " — Employment Agreements" above), we do not expect to grant restricted units to our employees or directors under the long-term incentive plan. In the future, the compensation committee may determine to make additional grants of restricted units under the plan to employees, consultants and directors containing such terms as the compensation committee shall determine. The compensation committee will determine the period over which restricted units (and distributions related to such units) granted to employees and members of our board will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of our company, as defined in the plan, unless provided otherwise by the committee.

If a grantee's employment, consulting relationship or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. Units to be delivered as restricted units may be units issued by us, units acquired by us in the open market, units already owned by us, units acquired by us from any other person or any combination of the foregoing. If we issue new units upon the grant of the restricted units, the total number of units outstanding will increase.

We intend the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our units. Therefore, plan participants will not pay any consideration for the units they receive, and we will receive no remuneration for the units.

Phantom Units. A phantom unit entitles the grantee to receive a unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a unit. Initially, we do not expect to grant phantom units under the long-term incentive plan. In the future, the compensation committee may determine to make grants of phantom units under the plan to employees, consultants and directors containing such terms as the compensation committee shall determine. The compensation committee will determine the period over which phantom units granted to employees and members of our board will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the phantom units will vest upon a change of control of our company, unless provided otherwise by the committee.

If a grantee's employment, consulting relationship or membership on the board of directors terminates for any reason, the grantee's phantom units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. Units to be delivered upon the vesting of phantom units may be units issued by us,

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units acquired by us in the open market, units already owned by us, units acquired by us from any other person or any combination of the foregoing. If we issue new units upon vesting of the phantom units, the total number of units outstanding will increase. The compensation committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units that entitle the holder to receive cash equal to any cash distributions made on units while the phantom units are outstanding.

We intend the issuance of any units upon vesting of the phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our units. Therefore, plan participants will not pay any consideration for the units they receive, and we will receive no remuneration for the units.

Unit Appreciation Rights. The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess may be paid in units, cash or a combination thereof, as determined by the compensation committee in its discretion. Initially, we do not expect to grant unit appreciation rights under our long-term incentive plan. In the future, the compensation committee may determine to make grants of unit appreciation rights under the plan to employees, consultants and directors containing such terms as the committee shall determine. Unit appreciation rights will have an exercise price that will not be less than the fair market value of the units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the compensation committee. In addition, the unit appreciation rights will become exercisable upon a change in control of our company, unless provided otherwise by the committee. If a grantee's employment, consulting relationship or membership on the board of directors terminates for any reason, the grantee's unvested unit appreciation rights will be automatically forfeited unless, and to the extent, the grant agreement or compensation committee provides otherwise.

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SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of our company that will be issued upon the consummation of this offering, assuming no exercise of the underwriters' option to purchase additional units, and the application of the related net proceeds and held by:

•: each person who will then beneficially own 5% or more of the then outstanding units;
•: each of the members of our board of directors;
•: each named executive officer of our company; and
•: all directors and executive officers as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner		Units to be Beneficially Owned	Percentage of Units to be Beneficially Owned
Quantum Energy Partners(1)		10,914,228	39.2	%
Michael C. Linn		3,589,097	12.9	%
Kolja Rockov(2)		343,364	1.2	%
Gerald W. Merriam		467,387	1.7	%
Roland P. Keddie		467,387	1.7	%
Toby R. Neugebauer(3)		10,914,228	39.2	%
George A. Alcorn		—	—
Terrence S. Jacobs		—	—
Jeffrey C. Swoveland		—	—
	All executive officers and directors as a group (10 persons)	15,781,463	56.7	%

(1): Quantum Energy Partners owns its units through Quantum Energy Partners II, LP. Quantum Energy Partners II, LP is controlled by its general partner, Quantum Energy Management II, LP, which is controlled by its general partner, Quantum Energy Management II, LLC, an affiliate of Quantum Energy Partners. Quantum Energy Partners II, LP can be contacted at the following address: 777 Walker Street, Suite 2530, Houston, Texas 77002.
(2): Includes 228,909 restricted units that vest in equal installments over a two-year period.
(3): Mr. Neugebauer, a principal of Quantum Energy Partners, could be deemed to beneficially own the membership interests in us held by Quantum Energy Partners II, LP. Mr. Neugebauer disclaims beneficial ownership in the reported securities in excess of his indirect pecuniary interest in the securities. Mr. Neugebauer can be contacted at the following address: 777 Walker Street, Suite 2530, Houston, Texas 77002.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Under the terms of the prior limited liability company agreement, we paid to Quantum Energy Partners and other non-affiliated investors a fee of 2.0% of each capital contribution made to us. Fees paid during the period from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004 were $300,000 and $0, respectively.

On December 1, 2003, we entered into an assignment and bill of sale with Linn Resources, LLC, a related party, for the purchase of all of Linn Resources' interests in two wells, equipment, leasehold and associated facilities. The purchase price for this transaction was approximately $150,000. The purchase price was determined based on the price paid for working interests from an unrelated third party during 2003.

The board of directors of Mid Atlantic Well Service, Inc. has appointed Mr. Eric P. Linn as President of Mid Atlantic, effective December 1, 2005. Mr. Linn's annual base salary will be $125,000 and he will be provided with use of a company vehicle. Mr. Linn is the brother of our President and Chief Executive Officer, Michael C. Linn.

Stakeholders' Agreement

Prior to filing our registration statement relating to this offering, we and all of the holders of membership interests in us, including Quantum Energy Partners, non-affiliated equity investors and members of our management, entered into an agreement relating to:

•: the redemption and/or exchange, as applicable, of their respective membership interests in us;
•: certain corporate governance matters; and
•: registration rights for the benefit of certain of our existing members.

We refer to this agreement as our "Stakeholders' Agreement" and have filed it as an exhibit to the registration statement of which this prospectus is a part. The Stakeholders' Agreement resulted from arm's-length negotiations among the parties, some of which are our affiliates.

Redemption and Equity Exchange. Pursuant to the terms of the Stakeholders' Agreement, at the closing of this offering, a portion of our existing members' membership interests will be redeemed for cash with proceeds from this offering, and immediately following such redemption, the remaining membership interests of all our existing members will be exchanged for units. Each existing member will be allocated cash and/or units based on a formula that is tied to the initial public offering price per unit. Specifically, the Stakeholders' Agreement provides that upon closing, a "residual equity value" of our company will be determined by subtracting from the total post-offering market capitalization of our company:

•: the amount of the proceeds that will be used to repay our outstanding indebtedness;
•: the offering expenses, which will include one-time bonus payments to be made upon completion of this offering to Messrs. Linn and Rockov; and
•: the value of the restricted units to be issued to members of our management upon completion of this offering. The residual equity value will be allocated to our existing members based on the liquidating distribution provisions of our limited liability company agreement prior to the amendment of that agreement concurrently with this offering. The

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residual equity value allocated to Quantum Energy Partners and non-affiliated equity investors will be adjusted by adding offering expenses associated with any exercise of the underwriters' option to purchase additional units in proportion to their respective initial investments in us.

Each existing member will receive for its membership interests cash and/or units with a value equal to such member's adjusted residual value allocation. Assuming no exercise of the underwriters' option to purchase additional units, we anticipate that we will redeem $84.7 million, $3.0 million and $2.2 million of membership interests from Quantum Energy Partners, Michael C. Linn and non-affiliated equity investors, respectively. The adjusted residual equity value allocated to each of the foregoing existing members will be reduced by the amount of any such cash payment. The remaining membership interests held by each of our existing members will be exchanged for a number of units equal to the residual equity value allocated to such member (as adjusted, if applicable) divided by the initial public offering price per unit. Following the redemption and exchange of our existing members' membership interests, assuming no exercise of the underwriters' option to purchase additional units, we anticipate that Quantum Energy Partners will own 10,914,228 units, Michael C. Linn, Gerald W. Merriam and Roland P. Keddie will own in the aggregate approximately 4,523,871 units and non-affiliated equity investors will own approximately 281,036 units. Any net proceeds from the exercise of the underwriters' option to purchase additional units will be used to redeem additional units from Quantum Energy Partners and non-affiliated equity investors. Please read "Our LLC Structure," "The Offering," "Use of Proceeds" and "Security Ownership of Certain Beneficial Owners and Management."

The following table sets forth the equity interests owned by our existing members prior to this offering and the aggregate consideration to be received by those members for their membership interests upon consummation of this offering.

Existing Member	Initial Investment		Consideration to be Received Upon Consummation of Offering(1)		Aggregate Value of Consideration to be Received Upon Consummation of Offering(2)
Quantum Energy Partners	$	15.0 million	$	84.7 million cash 10,914,228 units	$	303.0 million
Non-affiliated equity investors(3)	$	386,242	$	2.2 million cash 281,037 units	$	7.8 million
Michael C. Linn	$	737,500	$	3.0 million cash 3,589,097 units	$	74.8 million
Gerald W. Merriam	$	100,000		467,387 units	$	9.3 million
Roland P. Keddie	$	100,000		467,387 units	$	9.3 million

(1): Assuming no exercise of the underwriters' option to purchase additional units.
(2): Based upon an initial offering price of $20.00 per unit.
(3): Includes Clark Partners I, L.P., Kings Highway Investment, LLC and Wauwinet Energy Partners, LLC.

Corporate Governance. Pursuant to the Stakeholders' Agreement, our existing members agreed to amend and restate our limited liability company agreement simultaneously with the closing of this offering to do the following, among other things:

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•: establish a board of directors consisting of five members, three of whom will be independent and each of whom will be elected annually by our unitholders;
•: establish an audit committee, a compensation committee, a conflicts committee and a nominating committee; and
•: require us to purchase directors' and officers' liability insurance.

Please read "Management" and "The Limited Liability Company Agreement."

Registration Rights. Pursuant to the Stakeholders' Agreement, Quantum Energy Partners has the right to require, for the benefit of itself and non-affiliated equity investors, the registration of the units acquired by them upon consummation of this offering. Subject to the terms of the Stakeholders' Agreement, Quantum Energy Partners and/or certain of its permitted transferees are entitled to make three such demands for registration. In addition, Quantum Energy Partners, non-affiliated equity investors and/or their respective permitted transferees may include any of their units in a registration by us of other units, including units offered by us or any unitholder, subject to customary exceptions. Please read "Units Eligible for Future Sale."

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DESCRIPTION OF THE UNITS

The Units

The units represent limited liability company interests in us. The holders of units are entitled to participate in distributions and exercise the rights or privileges available to unitholders under our limited liability company agreement. For a description of the relative rights and preferences of holders of units in and to distributions, please read this section and "Cash Distribution Policy." For a description of the rights and privileges of unitholders under our limited liability company agreement, including voting rights, please read "The Limited Liability Company Agreement."

Transfer Agent and Registrar

ComputerShare will serve as registrar and transfer agent for the units. We pay all fees charged by the transfer agent for transfers of units, except the following fees that will be paid by unitholders:

•: surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
•: special charges for services requested by a holder of a unit; and
•: other similar fees or charges.

There will be no charge to holders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may at any time resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, we are authorized to act as the transfer agent and registrar until a successor is appointed.

Transfer of Units

By transfer of units in accordance with our limited liability company agreement, each transferee of units shall be admitted as a unitholder with respect to the units transferred when such transfer and admission is reflected on our books and records. Additionally, each transferee of units:

•: becomes the record holder of the units;
•: automatically agrees to be bound by the terms and conditions of, and is deemed to have executed our limited liability company agreement;
•: represents that the transferee has the capacity, power and authority to enter into the limited liability company agreement;
•: grants powers of attorney to our officers and any liquidator of our company as specified in the limited liability company agreement; and
•: makes the consents and waivers contained in our limited liability company agreement.

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An assignee will become a unitholder of our company for the transferred units upon the recording of the name of the assignee on our books and records.

Until a unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE LIMITED LIABILITY COMPANY AGREEMENT

The following is a summary of the material provisions of our limited liability company agreement. The form of the limited liability company agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of the form of this agreement upon request at no charge.

We summarize the following provisions of our limited liability company agreement elsewhere in this prospectus:

•: with regard to distributions of available cash, please read "How We Make Distributions."
•: with regard to the transfer of units, please read "Description of the Units — Transfer of Units."
•: with regard to the election of members of our board of directors, please read "Management — Our Board of Directors."
•: with regard to allocations of taxable income and taxable loss, please read "Material Tax Consequences."

Organization

Our company was formed in April 2005 and will remain in existence until dissolved in accordance with our limited liability company agreement.

Purpose

Under our limited liability company agreement, we are permitted to engage, directly or indirectly, in any activity that our board of directors approves and that a limited liability company organized under Delaware law lawfully may conduct; provided, that our board of directors shall not cause us to engage, directly or indirectly, in any business activities that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our board of directors has the ability to cause us and our operating subsidiaries to engage in activities other than the exploitation, development and production of natural gas reserves, our board of directors has no current plans to do so. Our board of directors is authorized in general to perform all acts it deems to be necessary or appropriate to carry out our purposes and to conduct our business.

Fiduciary Duties

Our limited liability company agreement provides that our business and affairs shall be managed under the direction of our board of directors, which shall have the power to appoint our officers. Our limited liability company agreement further provides that the authority and function of our board of directors and officers shall be identical to the authority and functions of a board of directors and officers of a corporation organized under the Delaware General Corporation Law, or DGCL. Finally, our limited liability company agreement provides that except as specifically provided therein, the fiduciary duties and obligations owed to our limited liability company and to our members shall be the same as the respective duties and obligations owed by officers and directors of a corporation organized under the DGCL to their corporation and stockholders, respectively. Our limited liability company agreement permits affiliates of our

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directors to invest or engage in other businesses or activities that compete with us. In addition, our limited liability company agreement establishes a conflicts committee of our board of directors, consisting solely of independent directors, which will be authorized to review transactions involving potential conflicts of interest. If the conflicts committee approves such a transaction, or if a transaction is on terms generally available from third parties or an action is taken that is fair and reasonable to the company, you will not be able to assert that such approval constituted a breach of fiduciary duties owed to you by our directors and officers.

Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney

By purchasing a unit in us, you will be admitted as a unitholder of our company and will be deemed to have agreed to be bound by the terms of our limited liability company agreement. Pursuant to this agreement, each unitholder and each person who acquires a unit from a unitholder grants to our board of directors (and, if appointed, a liquidator) a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our board of directors the authority to make certain amendments to, and to make consents and waivers under and in accordance with, our limited liability company agreement.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under " — Limited Liability."

Limited Liability

Unlawful Distributions. The Delaware Act provides that a unitholder who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the company for the amount of the distribution for three years. Under the Delaware Act, a limited liability company may not make a distribution to a unitholder if, after the distribution, all liabilities of the company, other than liabilities to unitholders on account of their membership interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the company. For the purpose of determining the fair value of the assets of a company, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the company only to the extent that the fair value of that property exceeds the nonrecourse liability. Under the Delaware Act, an assignee who becomes a substituted unitholder of a company is liable for the obligations of his assignor to make contributions to the company, except the assignee is not obligated for liabilities unknown to him at the time he became a unitholder and that could not be ascertained from the limited liability company agreement.

Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which We Do Business. Our subsidiaries will initially conduct business only in the States of Pennsylvania, West Virginia, New York and Virginia. We may decide to conduct business in other states, and maintenance of limited liability for us, as a member of our operating subsidiaries, may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there. Limitations on the liability of unitholders for the obligations of a limited liability company have not been clearly established in many jurisdictions. We will operate in a manner that our board of directors considers reasonable and necessary or appropriate to preserve the limited liability of our unitholders.

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Voting Rights

The following matters require the unitholder vote specified below:

Election of members of the board of directors		Following our initial public offering we will have five directors. Our limited liability company agreement provides that we will have a board of not less than three and no more than eleven members. Holders of our units, voting together as a single class, will elect our directors. Please read " — Election of Members of Our Board of Directors."
Issuance of additional units		No approval right.
Amendment of the limited liability company agreement		Certain amendments may be made by our board of directors without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read " — Amendment of Our Limited Liability Company Agreement."
Merger of our company or the sale of all or substantially all of our assets		Unit majority. Please read " — Merger, Sale or Other Disposition of Assets."
Dissolution of our company		Unit majority. Please read " — Termination and Dissolution."

Matters requiring the approval of a "unit majority" require the approval of a majority of the outstanding units.

Issuance of Additional Securities

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and authorizes us to buy securities for the consideration and on the terms and conditions determined by our board of directors without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of units in our distributions of available cash. In addition, the issuance of additional units or other equity securities may dilute the value of the interests of the then-existing holders of units in our net assets.

In accordance with Delaware law and the provisions of our limited liability company agreement, we may also issue additional securities that, as determined by our board of directors, may have special voting or other rights to which the units are not entitled.

The holders of units will not have preemptive or preferential rights to acquire additional units or other securities.

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Election of Members of Our Board of Directors

Removal of Members of Our Board of Directors

Any director may be removed, with or without cause, by the holders of a majority of the outstanding units then entitled to vote at an election of directors.

Amendment of Our Limited Liability Company Agreement

General. Amendments to our limited liability company agreement may be proposed only by or with the consent of our board of directors. To adopt a proposed amendment, other than the amendments discussed below, our board of directors is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our unitholders to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:

•: enlarge the obligations of any unitholder without its consent, unless approved by at least a majority of the type or class of member interests so affected;
•: provide that we are not dissolved upon an election to dissolve our company by our board of directors that is approved by a unit majority;
•: change the term of existence of our company; or
•: give any person the right to dissolve our company other than our board of directors' right to dissolve our company with the approval of a unit majority.

The provision of our limited liability company agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 75% of the outstanding units, voting together as a single class.

No Unitholder Approval. Our board of directors may generally make amendments to our limited liability company agreement without the approval of any unitholder or assignee to reflect:

•: a change in our name, the location of our principal place of our business, our registered agent or our registered office;
•: the admission, substitution, withdrawal or removal of members in accordance with our limited liability company agreement;
•: the merger of our company or any of its subsidiaries into, or the conveyance of all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity;
•: a change that our board of directors determines to be necessary or appropriate for us to qualify or continue our qualification as a company in which our members have limited liability under the laws of any state or to ensure that neither we, our operating subsidiaries nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

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•: an amendment that is necessary, in the opinion of our counsel, to prevent us, members of our board, or our officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;
•: an amendment that our board of directors determines to be necessary or appropriate for the authorization of additional securities or rights to acquire securities;
•: any amendment expressly permitted in our limited liability company agreement to be made by our board of directors acting alone;
•: an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our limited liability company agreement;
•: any amendment that our board of directors determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our limited liability company agreement;
•: a change in our fiscal year or taxable year and related changes;
•: a merger, conversion or conveyance effected in accordance with the limited liability company agreement; and
•: any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our board of directors may make amendments to our limited liability company agreement without the approval of any unitholder or assignee if our board of directors determines that those amendments:

•: do not adversely affect the unitholders (including any particular class of unitholders as compared to other classes of unitholders) in any material respect;
•: are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
•: are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the units are or will be listed for trading, compliance with any of which our board of directors deems to be in the best interests of us and our unitholders;
•: are necessary or appropriate for any action taken by our board of directors relating to splits or combinations of units under the provisions of our limited liability company agreement; or
•: are required to effect the intent expressed in this prospectus or the intent of the provisions of our limited liability company agreement or are otherwise contemplated by our limited liability company agreement.

Opinion of Counsel and Unitholder Approval. Our board of directors will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our unitholders or result in our being treated as an entity for federal income tax purposes if one of

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the amendments described above under " — No Unitholder Approval" should occur. No other amendments to our limited liability company agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any unitholder of our company.

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

Our board of directors is generally prohibited, without the prior approval of the holders of a unit majority from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries, provided that our board of directors may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our board of directors may also sell all or substantially all of our assets under a foreclosure or other realization upon the encumbrances above without that approval.

If the conditions specified in the limited liability company agreement are satisfied, our board of directors may merge our company or any of its subsidiaries into, or convey all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters' rights of appraisal under the limited liability company agreement or applicable Delaware law in the event of a merger or consolidation, a sale of all or substantially all of our assets or any other transaction or event.

Termination and Dissolution

We will continue as a company until terminated under our limited liability company agreement. We will dissolve upon: (1) the election of our board of directors to dissolve us, if approved by the holders of a unit majority; (2) the sale, exchange or other disposition of all or substantially all of the assets and properties of our company and our subsidiaries; or (3) the entry of a decree of judicial dissolution of our company.

Liquidation and Distribution of Proceeds

Upon our dissolution, the liquidator authorized to wind up our affairs will, acting with all of the powers of our board of directors that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in "Cash Distribution Policy — Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to unitholders in kind if it determines that a sale would be impractical or would cause undue loss to our unitholders.

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Anti-Takeover Provisions

Our limited liability company agreement contains specific provisions that are intended to discourage a person or group from attempting to take control of our company without the approval of our board of directors. Specifically, our limited liability company agreement provides that we will elect to have Section 203 of the Delaware General Corporation Law apply to transactions in which an interested unitholder (as described below) seeks to enter into a merger or business combination with us. Under this provision, such a holder will not be permitted to enter into a merger or business combination with us unless:

•

prior to such time, our board of directors approved either the business combination or the transaction that resulted in the unitholder's becoming an interested unitholder;

•

upon consummation of the transaction that resulted in the unitholder's becoming an interested unitholder, the interested unitholder owned at least 85% of our outstanding units at the time the transaction commenced, excluding for purposes of determining the number of units outstanding those units owned:

•: by persons who are directors and also officers; and
•: by employee unit plans in which employee participants do not have the right to determine confidentially whether units held subject to the plan will be tendered in a tender or exchange offer; or
•: at or subsequent to such time the business combination is approved by our board of directors and authorized at an annual or special meeting of our unitholders, and not by written consent, by the affirmative vote of at least a majority of our outstanding voting units that are not owned by the interested unitholder.

Section 203 defines "business combination" to include:

•: any merger or consolidation involving the company and the interested unitholder;
•: any sale, transfer, pledge or other disposition of 10% or more of the assets of the company involving the interested unitholder;
•: subject to certain exceptions, any transaction that results in the issuance or transfer by the company of any units of the company to the interested unitholder;
•: any transaction involving the company that has the effect of increasing the proportionate share of the units of any class or series of the company beneficially owned by the interested unitholder; or
•: the receipt by the interested unitholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the company.

In general, by reference to Section 203, an "interested unitholder" is any entity or person who or which beneficially owns (or within three years did own) 15% or more of the outstanding voting units of the company and any entity or person affiliated with or controlling or controlled by such entity or person.

The existence of this provision would be expected to have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging attempts that might result in a premium over the market price for units held by unitholders.

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Limited Call Right

If at any time any person owns more than 90% of the then-issued and outstanding membership interests of any class, such person will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by our management, on at least 10 but not more than 60 days' notice. The unitholders are not entitled to dissenters' rights of appraisal under the limited liability company agreement or applicable Delaware law if this limited call right is exercised. The purchase price in the event of this purchase is the greater of:

•: the highest cash price paid by such person for any membership interests of the class purchased within the 90 days preceding the date on which such person first mails notice of its election to purchase those membership interests; or
•: the closing market price as of the date three days before the date the notice is mailed.

As a result of this limited call right, a holder of membership interests in our company may have his membership interests purchased at an undesirable time or price. Please read "Risk Factors — Risks Related to Our Structure." The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read "Material Tax Consequences — Disposition of Units."

Meetings; Voting

All notices of meetings of unitholders shall be sent or otherwise given in accordance with Section 11.4 of our limited liability company agreement not less than 10 nor more than 60 days before the date of the meeting. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted (no business other than that specified in the notice may be transacted) or (ii) in the case of the annual meeting, those matters which the board of directors, at the time of giving the notice, intends to present for action by the unitholders (but any proper matter may be presented at the meeting for such action). The notice of any meeting at which directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the board of directors intends to present for election. Any previously scheduled meeting of the unitholders may be postponed, and any special meeting of the unitholders may be cancelled, by resolution of the board of directors upon public notice given prior to the date previously scheduled for such meeting of unitholders.

Units that are owned by an assignee who is a record holder, but who has not yet been admitted as a unitholder, shall be voted at the written direction of the record holder by a proxy designated by our board of directors. Absent direction of this kind, the units will not be voted, except that units held by us on behalf of non-citizen assignees shall be voted in the same ratios as the votes of unitholders on other units are cast.

Any action required or permitted to be taken by our unitholders must be effected at a duly called annual or special meeting of unitholders and may not be effected by any consent in writing by such unitholders.

Meetings of the unitholders may only be called by a majority of our board of directors. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person

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or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional units having special voting rights could be issued. Please read " — Issuance of Additional Securities." Units held in nominee or street name accounts will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our limited liability company agreement will be delivered to the record holder by us or by the transfer agent.

Non-Citizen Assignees; Redemption

If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any unitholder or assignee, we may redeem, upon 30 days' advance notice, the units held by the unitholder or assignee at their current market price. To avoid any cancellation or forfeiture, our board of directors may require each unitholder or assignee to furnish information about his nationality, citizenship or related status. If a unitholder or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our board of directors determines after receipt of the information that the unitholder or assignee is not an eligible citizen, the unitholder or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted unitholder, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Indemnification

Under our limited liability company agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any director or officer, or while serving as a director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of any or our affiliates. Additionally, we shall indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person is or was an employee (other than an officer) or agent of our company.

Any indemnification under our limited liability company agreement will only be out of our assets. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our limited liability company agreement.

Books and Reports

We are required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

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We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of unitholders can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right To Inspect Our Books and Records

Our limited liability company agreement provides that a unitholder can, for a purpose reasonably related to his interest as a unitholder, upon reasonable demand and at his own expense, have furnished to him:

•: a current list of the name and last known address of each unitholder;
•: a copy of our tax returns;
•: information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each unitholder and the date on which each became a unitholder;
•: copies of our limited liability company agreement, the certificate of formation of the company, related amendments and powers of attorney under which they have been executed;
•: information regarding the status of our business and financial condition; and
•: any other information regarding our affairs as is just and reasonable.

Our board of directors may, and intends to, keep confidential from our unitholders information that it believes to be in the nature of trade secrets or other information, the disclosure of which our board of directors believes in good faith is not in our best interests, information that could damage our company or our business, or information that we are required by law or by agreements with a third party to keep confidential.

Registration Rights

Quantum Energy Partners and non-affiliated equity investors are entitled under the Stakeholders' Agreement to registration rights with respect to the units acquired by them in connection with this offering. Please read "Certain Relationships and Related Party Transactions — Stakeholders' Agreement" and "Units Eligible for Future Sale."

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the units offered by this prospectus, and assuming that the underwriters' option to purchase additional units is not exercised, our management and Quantum Energy Partners will hold, directly and indirectly, an aggregate of 12,031,751 units. The sale of these units could have an adverse impact on the price of the units or on any trading market that may develop.

The units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•: 1% of the total number of the securities outstanding; or
•: the average weekly reported trading volume of the units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his units for are least two years, would be entitled to sell units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our limited liability company agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Our limited liability company agreement does not restrict our ability to issue equity securities ranking junior to the units at any time. Any issuance of additional units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, units then outstanding. Please read "The Limited Liability Company Agreement — Issuance of Additional Securities."

Pursuant to the Stakeholders' Agreement, Quantum Energy Partners has the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the Stakeholders' Agreement and our limited liability company agreement, these registration rights allow Quantum Energy Partners and/or certain of its permitted transferees to require registration of any of their units and and any units held by non-affiliated equity investors. In addition, Quantum Energy Partners, non-affiliated equity investors and/or their respective permitted transferees may include any of their units in a registration by us of other units, including units offered by us or by any unitholder. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our management, Quantum Energy Partners and non-affiliated equity investors may sell their units in private transactions at any time, subject to compliance with applicable laws. Please read "Certain Relationships and Related Party Transactions — Stakeholders' Agreement."

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We, our management and Quantum Energy Partners and its affiliates, including the members of the board of directors and executive officers of our company, have agreed not to sell any units for a period of 180 days from the date of this prospectus. Please read "Underwriting" for a description of these lock-up provisions.

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MATERIAL TAX CONSEQUENCES

This section is a discussion of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP, counsel to us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based on current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Linn Energy, LLC and our limited liability company operating subsidiaries.

This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of our units.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Andrews Kurth LLP. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our units and the prices at which our units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne directly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements regarding matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Andrews Kurth LLP and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Andrews Kurth LLP.

For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific federal income tax issues:

(1): the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read " — Tax Consequences of Unit Ownership — Treatment of Short Sales");
(2): whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury regulations (please read " — Disposition of Units — Allocations Between Transferors and Transferees");
(3): whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder (please read " — Tax Treatment of Operations — Depletion Deductions");

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(4): whether the deduction related to United States production activities will be available to a unitholder or the extent of such deduction to any unitholder (please read " — Tax Treatment of Operations — Deduction for United States Production Activities"); and
(5): whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read " — Tax Consequences of Unit Ownership — Section 754 Election" and " — Uniformity of Units").

Partnership Status

Except as discussed in the following paragraph, a limited liability company that has more than one member and that has not elected to be treated as a corporation is treated as a partnership for federal income tax purposes and, therefore, is not a taxable entity and incurs no federal income tax liability. Instead, each partner is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, even if no cash distributions are made to him. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the "Qualifying Income Exception," exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current income does not constitute qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP. Andrews Kurth LLP is of the opinion, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions and the representations described below, that we will be classified as a partnership, and each of our operating subsidiaries (other than Linn Operating, Inc. and Mid Atlantic Well Service, Inc.) will be disregarded as an entity separate from us, for federal income tax purposes.

In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us. The representations made by us upon which Andrews Kurth LLP has relied include:

(a): Neither we, nor any of our limited liability company subsidiaries, have elected nor will we elect to be treated as a corporation; and
(b): For each taxable year, more than 90% of our gross income will be income that Andrews Kurth LLP has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

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If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation would be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital to the extent of the unitholder's tax basis in his units, or taxable capital gain, after the unitholder's tax basis in his units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Andrews Kurth LLP's opinion that we will be classified as a partnership for federal income tax purposes.

Unitholder Status

Unitholders who become members of Linn Energy, LLC will be treated as partners of Linn Energy, LLC for federal income tax purposes. Also, assignees who have executed and delivered transfer applications, and are awaiting admission as members, and unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as partners of Linn Energy, LLC for federal income tax purposes.

Because there is no direct authority addressing the federal tax treatment of assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Andrews Kurth LLP does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.

A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read " — Tax Consequences of Unit Ownership — Treatment of Short Sales."

Items of our income, gain, loss, or deduction are not reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to their status as partners in us for federal income tax purposes.

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Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of his tax basis in his units generally will be considered to be gain from the sale or exchange of those units, taxable in accordance with the rules described under " — Disposition of Units" below. To the extent that cash distributions made by us cause a unitholder's "at risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read " — Limitations on Deductibility of Losses."

Any reduction in a unitholder's share of our liabilities for which no partner bears the economic risk of loss, known as "non-recourse liabilities," will be treated as a distribution of cash to that unitholder. A decrease in a unitholder's percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder's share of our "unrealized receivables," including recapture of intangible drilling costs, depletion and depreciation recapture, and/or substantially appreciated "inventory items," both as defined in Section 751 of the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of our units in this offering who holds those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2008, will be allocated an amount of federal taxable income for that period that will be less than 10% of the cash distributed to the unitholder with respect to that period. We anticipate that thereafter, the ratio of taxable income allocable to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will be sufficient to make estimated distributions on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory,

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competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the units.

Basis of Units

A unitholder's initial tax basis for his units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder's share of our nonrecourse liabilities will generally be based on his share of our profits. Please read " — Disposition of Units — Recognition of Gain or Loss."

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to his tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that amount is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of his tax basis in his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at-risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a unitholder's at risk amount will decrease by the amount of the unitholder's depletion deductions and will increase to the extent of the amount by which the unitholder's percentage depletion deductions with respect to our property exceed the unitholder's share of the basis of that property.

The at risk limitation applies on an activity-by-activity basis, and in the case of natural gas and oil properties, each property is treated as a separate activity. Thus, a taxpayer's interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for

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all the taxpayer's natural gas and oil properties. It is uncertain how this rule is implemented in the case of multiple natural gas and oil properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a unitholder's at risk limitation with respect to us. If a unitholder must compute his at risk amount separately with respect to each oil or gas property we own, he may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his units as a whole.

The passive loss limitation generally provides that individuals, estates, trusts and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitation is applied separately with respect to each publicly traded partnership. Consequently, any losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or a unitholder's salary or active business income. Moreover, although unclear, each oil or gas property may constitute a separate activity for purposes of the passive activity rules. Assuming that each oil or gas property is a separate activity, whenever we sell an oil or gas property to an unrelated party or abandon it, each unitholder will then be able to deduct any suspended passive activity losses attributable to that property, subject to the overall publicly traded partnership limitation. However, if we dispose of only part of our interest in a property, unitholders will be able to offset only their suspended passive activity losses attributable to that property against the gain on the disposition. Any remaining suspected passive activity losses will remain suspended. Notwithstanding whether a natural gas and oil property is a separate activity, passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitation on Interest Deductions

The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•: interest on indebtedness properly allocable to property held for investment;
•: our interest expense attributable to portfolio income; and
•: the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit.

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Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our limited liability company agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our limited liability company agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the unitholders in accordance with their percentage interests in us. At any time that distributions are made on the units in excess of distributions made on the subordinated units, gross income will be allocated to the recipients to the extent of those distributions. If we have a net loss for an entire year, the loss will be allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of our assets at the time of this offering, which assets are referred to in this discussion as "Contributed Property." These allocations are required to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and the "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "book-tax disparity." The effect of these allocations to a unitholder who purchases units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In the event we issue additional units or engage in certain other transactions in the future, Section 704(c) allocations will be made to all holders of partnership interests, including purchasers of units in this offering, to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts

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nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by Section 704(c), will generally be given effect for federal income tax purposes in determining a unitholder's share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a unitholder's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•: his relative contributions to us;
•: the interests of all the unitholders in profits and losses;
•: the interest of all the unitholders in cash flow; and
•: the rights of all the unitholders to distributions of capital upon liquidation.

Andrews Kurth LLP is of the opinion that, with the exception of the issues described in " — Tax Consequences of Unit Ownership — Section 754 Election," " — Uniformity of Units" and " — Disposition of Units — Allocations Between Transferors and Transferees," allocations under our limited liability company agreement will be given effect for federal income tax purposes in determining a unitholder's share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for tax purposes with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•: none of our income, gain, loss or deduction with respect to those units would be reportable by the unitholder;
•: any cash distributions received by the unitholder with respect to those units would be fully taxable; and
•: all of these distributions would appear to be ordinary income.

Andrews Kurth LLP has not rendered an opinion regarding the treatment of a unitholder whose units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read " — Disposition of Units — Recognition of Gain or Loss."

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult their tax advisors with respect to the impact of an investment in our units on their liability for the alternative minimum tax.

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Tax Rates

In general, the highest effective federal income tax rate for individuals currently is 35% and the maximum federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases units directly from us, and it belongs only to the purchaser and not to other unitholders. Please also read, however, " — Allocation of Income, Gain, Loss and Deduction" above. For purposes of this discussion, a unitholder's inside basis in our assets has two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that basis.

Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our limited liability company agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read " — Tax Treatment of Operations — Uniformity of Units."

Although Andrews Kurth LLP is unable to opine on the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent a Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read " — Tax Treatment of Operations — Uniformity of Units."

A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that

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case, as a result of the election, the transferee would have, among other items, a greater amount of depletion and depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read " — Disposition of Units — Allocations Between Transferors and Transferees."

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above, unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our natural gas and oil interests. Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For

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this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder's gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder's daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between natural gas and oil production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder's total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder's total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder's share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder's share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our natural gas and oil interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil,

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natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to natural gas and oil wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An "integrated oil company" is a taxpayer that has economic interests in crude oil deposits and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an "independent producer" that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of natural gas and oil products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any unrealized gain. See " — Disposition of Common Units — Recognition of Gain or Loss."

Deduction for United States Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentages are 3% for qualified production activities income generated in the years 2005 and 2006; 6% for the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production

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activities income allocated to him from us with the unitholder's qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder's share of losses and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read " — Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses."

The amount of a unitholder's Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages paid by the unitholder during the calendar year. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the lesser of either (i) the unitholder's allocable share of our wages, or (ii) two times the applicable Section 199 deduction percentage of our qualified production activities income allocated to the unitholder plus any expenses incurred directly by the unitholder that are allocated to our qualified production activities for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 Wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs. The cost of acquiring natural gas and oil leaseholder or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read "Tax Treatment of Operations — Depletion Deductions."

Geophysical Costs. The cost of geophysical exploration must be capitalized as a lease acquisition cost if a property is (or may be) acquired or retained on the basis of data from such exploration. Otherwise, such costs generally may be deducted as ordinary expenses.

Operating and Administrative Costs. Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses which are reasonable in amount.

Tax Basis, Depreciation and Amortization

The tax basis of our assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our existing unitholders, and (ii) any other offering will be borne by our unitholders as of that time. Please read " — Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction."

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To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read " — Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction" and " — Disposition of Units — Recognition of Gain or Loss."

The costs incurred in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the unitholder's amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder's tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder's tax basis in that unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. A portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code

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to the extent attributable to assets giving rise to "unrealized receivables" or "inventory items" that we own. The term "unrealized receivables" includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method. Treasury regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•: a short sale;
•: an offsetting notional principal contract; or
•: a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer who enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is

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recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury regulations. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A person who purchases units is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of substantial penalties.

Constructive Termination

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal

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application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read " — Tax Consequences of Unit Ownership — Section 754 Election."

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code. This method is consistent with the Treasury regulations applicable to property depreciable under the accelerated cost recovery system or the modified accelerated cost recovery system, which we expect will apply to substantially all, if not all, of our depreciable property. We also intend to use this method with respect to property that we own, if any, depreciable under Section 167 of the Internal Revenue Code, even though that position may be inconsistent with Treasury regulation Section 1.167(c)-1(a)(6). We do not expect Section 167 to apply to a material portion, if any, of our assets. Please read " — Tax Consequences of Unit Ownership — Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If we adopt this position, it may result in lower annual deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. We will not adopt this position if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. Our counsel, Andrews Kurth LLP, is unable to opine on the validity of any of these positions. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read " — Disposition of Units — Recognition of Gain or Loss."

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company, or "mutual fund," is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of units in a "qualified

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publicly traded partnership" is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded partnership.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," that is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling issued by the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent the gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction.

We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability and possibly may result in an audit of his own return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

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Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. The limited liability company agreement appoints Kolja Rockov as our Tax Matters Partner, subject to redetermination by our board of directors from time to time.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a)

the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b)

a statement regarding whether the beneficial owner is:

(1): a person that is not a United States person,
(2): a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or
(3): a tax-exempt entity;

(c)

the amount and description of units held, acquired or transferred for the beneficial owner; and

(d)

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to

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us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1): for which there is, or was, "substantial authority," or
(2): as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

We believe we will not be classified as a tax shelter. If any item of income, gain, loss or deduction included in the distributive shares of unitholders could result in that kind of an "understatement" of income for which no "substantial authority" exists, we would be required to disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules would apply to an understatement of tax resulting from ownership of units if we were classified as a "tax shelter."

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions

If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read " — Information Returns and Audit Procedures" above.

Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004:

•: accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at " — Accuracy-related Penalties,"

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•: for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and
•: in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

State, Local and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business and own property in Pennsylvania, West Virginia, New York and Virginia. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read " — Tax Consequences of Unit Ownership — Entity-Level Collections." Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Andrews Kurth LLP has not rendered an opinion on the state local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns, that may be required of him.

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INVESTMENT IN OUR COMPANY BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

•: whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
•: whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and
•: whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibits employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:

•: the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;
•: the entity is an "operating company," — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries; or
•: there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

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Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of our units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, the underwriters set forth below have agreed to purchase from us the number of units set forth opposite its name.

Name		Number of Units
RBC Capital Markets Corporation
Lehman Brothers Inc.
A.G. Edwards & Sons, Inc.
UBS Securities LLC
KeyBanc Capital Markets, a Division of McDonald Investments Inc.

	Total	11,750,000

The underwriting agreement provides that the underwriters' obligations to purchase the units depend on the satisfaction of the conditions contained in the underwriting agreement and that if any of our units are purchased by the underwriters, all of our units must be purchased. The conditions contained in the underwriting agreement include the condition that all the representations and warranties made by us to the underwriters are true, that there has been no material adverse change in the condition of us or in the financial markets and that we deliver to the underwriters customary closing documents.

The following table shows the underwriting fees to be paid to the underwriters by us in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional units. This underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us to purchase the units. On a per unit basis, the underwriting fee is 7% of the initial price to the public.

	Paid by Us
	No Exercise	Full Exercise
Per unit	$	$
Total	$	$

We estimate that total remaining expenses of the offering, other than underwriting discounts and commissions, will be approximately $6.7 million.

We have been advised by the underwriters that the underwriters propose to offer our units directly to the public at the initial price to the public set forth on the cover page of this prospectus and to dealers (who may include the underwriters) at this price to the public less a concession not in excess of $ per unit. The underwriters may allow, and the dealers may reallow, a concession not in excess of $ per unit to certain brokers and dealers. After the offering, the underwriters may change the offering price and other selling terms.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act or to contribute to payments that may be required to be made with respect to these liabilities.

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We have granted to the underwriters an option to purchase up to an aggregate of 1,762,500 additional units at the initial price to the public less the underwriting discount set forth on the cover page of this prospectus exercisable solely to cover over-allotments, if any. Such option may be exercised in whole or in part at any time until 30 days after the date of this prospectus. If this option is exercised, each underwriter will be committed, subject to satisfaction of the conditions specified in the underwriting agreement, to purchase a number of additional units proportionate to the underwriter's initial commitment as indicated in the preceding table, and we will be obligated, pursuant to the option, to sell these units to the underwriters.

We, our management, Quantum Energy Partners and its affiliates, and members of our board of directors and our executive officers have agreed that we will not, directly or indirectly, sell, offer or otherwise dispose of any units or enter into any derivative transaction with similar effect as a sale of units for a period of 180 days after the date of this prospectus without the prior written consent of RBC Capital Markets Corporation and Lehman Brothers Inc. The restrictions described in this paragraph do not apply to:

•: The sale of units to the underwriters; or
•: Restricted units issued by us under the long-term incentive plan or upon the exercise of options issued under the long-term incentive plan.

The 180-day restricted period described in the preceding paragraphs will be extended if:

•: During the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or
•: Prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period;

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

RBC Capital Markets Corporation and Lehman Brothers Inc., in their sole discretion, may release the units subject to lock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release units from lock-up agreements, RBC Capital Markets Corporation and Lehman Brothers Inc. will consider, among other factors, the unitholders' reasons for requesting the release, the number of units for which the release is being requested and market conditions at the time.

At our request, the underwriters have reserved up to 7.5% of the total underwritten units offered by this prospectus as part of our Directed Unit Program. These units will be offered at the initial public offering price to certain of our officers, directors, employees and certain other persons associated with us. The number of units available for sale to the general public will be reduced to the extent such persons purchase such reserved units. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered hereby. The Directed Unit Program will be arranged through one of our underwriters, Lehman Brothers Inc.

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.

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•: Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
•: Over-allotment transactions involve sales by the underwriters of the units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in their option to purchase additional units. In a naked short position, the number of units involved is greater than the number of units in the underwriters' option to purchase additional units. The underwriters may close out any short position by either exercising their option and/or purchasing units in the open market.
•: Syndicate covering transactions involve purchases of the units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the units to close out the short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through their option. If the underwriters sell more units than could be covered by their option to purchase additional units, which we refer to in this prospectus as a naked short position, the position can only be closed out by buying units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the units in the open market after pricing that could adversely affect investors who purchase in the offering.
•: Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

Similar to other purchase transactions, the underwriters' purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the units or preventing or retarding a decline in the market price of the units. As a result, the price of the units may be higher than the price that might otherwise exist in the open market.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our units or preventing or retarding a decline in the market price of the units. As a result, the price of the units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The Nasdaq National Market or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, if commenced, will not be discontinued without notice.

We intend to list our units on The Nasdaq National Market under the symbol "LINE."

149

Prior to this offering, there has been no public market for the units. The initial public offering price was determined by negotiation between us and the underwriters. The principal factors considered in determining the public offering price included the following:

•: the information set forth in this prospectus and otherwise available to the underwriters;
•: our history and prospects and the history and prospects for the industry in which we will compete;
•: the ability of our management;
•: our prospects for future cash flow;
•: the present state of our development and our current financial condition;
•: market conditions for initial public offerings and the general condition of the securities markets at the time of this offering; and
•: the recent market prices of, and the demand for, publicly traded units of generally comparable entities.

Some of the underwriters and their affiliates may in the future perform various financial advisory, investment banking and other commercial banking services in the ordinary course of business for us for which they will receive customary compensation. RBC Capital Markets Corporation will receive a $400,000 structuring fee in connection with this offering.

Because the National Association of Securities Dealers, Inc. views the units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD's Conduct Rules. Investor suitability with respect to the units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

No sales to accounts over which any underwriter exercises discretionary authority in excess of 5% of the shares offered by them may be made without the prior written approval of the customer.

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, information contained in any other web site maintained by an underwriter or selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase any units. The underwriters and selling group members are not responsible for information contained in web sites that they do not maintain.

150

VALIDITY OF THE UNITS

The validity of the units will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with the units offered by us will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of Linn Energy, LLC as of December 31, 2003 and 2004 and for the period March 14, 2003 (inception) through December 31, 2003 and for the year ended December 31, 2004 have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The statements of operations and cash flows of Waco Properties for the year ended December 31, 2002 and the period January 1, 2003 through October 31, 2003 have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses for the acquisition from Emax Oil Company for the year ended December 31, 2002 and for the period from January 1, 2003 through May 31, 2003, the acquisition from Lenape Resources, Inc. for the period from April 1, 2003 through July 31, 2003, the acquisition from Mountain V Oil & Gas, Inc. for the periods from April 1, 2003 through December 31, 2003 and from January 1, 2004 through May 7, 2004 and the acquisition from Cabot Oil & Gas Corporation for the year ended December 31, 2002 and for the period from January 1, 2003 through September 30, 2003 have been included herein and in the registration statement in reliance upon the respective reports of Toothman Rice, PLLC, independent accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses for the acquisition from Westar Energy, Inc., Pentex Energy, Inc., and Seahorse Exploration, Inc. for the nine month period from April 1, 2003 through December 31, 2003 and the nine month period from January 1, 2004 through September 30, 2004 have been included herein and in the registration statement in reliance upon the report of Elms, Faris & Co., LP, independent accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses for the acquisition from Exploration Partners, LLC for the years ended December 31, 2003 and 2004 have been included herein and in the registration statement in reliance upon the report of Hantzmon Wiebel LLP, independent accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

Information included in this prospectus regarding our estimated quantities of natural gas and oil reserves was prepared by Schlumberger Data and Consulting Services, independent petroleum engineers, as stated in their reserve report with respect thereto. The reserve report of Schlumberger Data and Consulting Services for our reserves as of December 31, 2004 is attached hereto as Appendix D, in reliance upon the authority of said firm as experts with respect to the matters covered by their report and the giving of their report.

151

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S-l regarding the units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC's web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

152

INDEX TO FINANCIAL STATEMENTS


Linn Energy, LLC and Subsidiaries
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, as of December 31, 2003 and 2004 and September 30, 2005
Consolidated Statements of Operations, for the period from March 14, 2003 (Inception) to December 31, 2003 and year ended December 31, 2004 and for the nine month periods ended September 30, 2004 and 2005
Consolidated Statements of Members' Capital (Deficit), for the period from March 14, 2003 (Inception) to December 31, 2003 and year ended December 31, 2004 and for the nine month period ended September 30, 2005
Consolidated Statements of Cash Flows, for the period from March 14, 2003 (Inception) to December 31, 2003 and year ended December 31, 2004 and for the nine month periods ended September 30, 2004 and 2005
Notes to Consolidated Financial Statements, December 31, 2003 and 2004 and for the nine month periods ended September 30, 2004 and 2005 (unaudited)
Waco Properties
Report of Independent Registered Public Accounting Firm
Statements of Operations, year ended December 31, 2002 and period from January 1, 2003 through October 31, 2003
Statements of Cash Flows, year ended December 31, 2002 and period from January 1, 2003 through October 31, 2003
Notes to Financial Statements, December 31, 2002 and October 31, 2003
Natural Gas and Oil Property Acquired from Emax Oil Company
Independent Auditors' Report
Statements of Revenues and Direct Operating Expenses, for the period January 1, 2003 through May 31, 2003 and the year ended December 31, 2002
Notes to Financial Statements, for the period January 1, 2003 through May 30, 2003 and for the year ended December 31, 2002
Natural Gas and Oil Property Acquired from Lenape Resources, Inc.
Independent Auditors' Report
Statements of Revenues and Direct Operating Expenses, for the period April 1, 2003 through July 31, 2003
Notes to Consolidated Financial Statements, for the period April 1, 2003 through July 31, 2003
Natural Gas and Oil Property Acquired from Cabot Oil & Gas Corporation
Independent Auditors' Report
Statements of Revenues and Direct Operating Expenses, for the period January 1, 2003 through September 30, 2003 and the year ended December 31, 2002
Notes to Financial Statements, for the period January 1, 2003 through September 30, 2003 and for the year ended December 31, 2002
Natural Gas and Oil Property Acquired from Mountain V Oil & Gas, Inc.
Independent Auditors' Report

F-1

Statements of Revenues and Direct Operating Expenses, for the periods January 1, 2004 through May 7, 2004 and April 1, 2003 through December 31, 2003

Notes to Financial Statements, for the periods January 1, 2004 through May 7, 2004 and April 1, 2003 through December 31, 2003

Natural Gas and Oil Property Acquired from Westar Energy, Inc., Pentex Energy, Inc. and Seahorse Exploration, Inc.

Independent Auditors' Report

Statements of Revenues and Direct Operating Expenses, nine month periods ended December 31, 2003 and September 30, 2004

Notes to Financial Statements, April 1, 2003 through September 30, 2004

Natural Gas and Oil Property Acquired from Exploration Partners, LLC

Independent Auditors' Report

Statements of Revenues and Direct Operating Expenses, for the years ended December 31, 2004 and 2003 and nine months ended September 30, 2005 and 2004

Notes to Financial Statements, for the years ended December 31, 2004 and 2003

Linn Energy, LLC

Unaudited Pro Forma Combined Financial Statements, year ended December 31, 2004 and nine months ended September 30, 2005

Notes to Unaudited Pro Forma Combined Financial Statements, year ended December 31, 2004 and nine months ended September 30, 2005

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members
Linn Energy, LLC and Subsidiaries:

We have audited the accompanying consolidated balance sheets of Linn Energy, LLC and subsidiaries as of December 31, 2003 and 2004 and the related consolidated statements of operations, members' capital and cash flows for the period from March 14, 2003 (inception) to December 31, 2003 and for the year ended December 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Linn Energy, LLC and subsidiaries as of December 31, 2003 and 2004, and the results of their operations and their cash flows for the period from March 14, 2003 (inception) to December 31, 2003 and for the year ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Pittsburgh, Pennsylvania
May 12, 2005

F-3

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2003 AND 2004 AND SEPTEMBER 30, 2005

				As of December 31,
				As of December 31,				As of September 30, 2005
				2003		2004		As of September 30, 2005
								(unaudited)
Assets
Current assets:
	Cash and cash equivalents			$	22,042,504	$	2,188,244	$	2,977,390
	Receivables:
		Natural gas and oil, net of allowance for doubtful accounts of $50,000 in 2003 and 2004 and $100,000 in 2005			1,316,273		4,807,196		7,893,926
		Fair value of natural gas and interest rate swaps (note 3 and 7)			27,700		—		183,385
		Other			207,198		82,539		130,536
	Inventory				63,806		109,985		119,691
	Current portion of natural gas derivatives				—		—		612,504
	Prepaid expenses and other current assets				98,972		93,782		2,309,875

			Total current assets		23,756,453		7,281,746		14,227,307

Natural gas and oil properties (successful efforts accounting method) (note 12):
	Natural gas and oil properties and related equipment				53,982,147		101,682,305		129,254,857
		Less accumulated depreciation, depletion, and amortization			946,123		4,559,714		8,077,152

					53,036,024		97,122,591		121,177,705

Property, plant, and equipment:
	Land				45,000		47,500		47,500
	Buildings and leasehold improvements				39,138		468,600		539,729
	Vehicles				184,453		689,892		935,590
	Furniture and equipment				127,522		342,487		810,734

					396,113		1,548,479		2,333,553
	Less accumulated depreciation				25,996		161,724		367,433

					370,117		1,386,755		1,966,120

Other assets:
	Prepaid drilling costs				2,300,643		362,095		727,896
	Equity investment				110,313		69,685		—
	Long-term portion of natural gas derivatives				—		—		5,326,884
	Operating bonds				75,342		110,699		160,820

					2,486,298		542,479		6,215,600

			Total assets	$	79,648,892	$	106,333,571	$	143,586,732

See accompanying notes to consolidated financial statements.

F-4

									As of
			As of December 31,						As of
			As of December 31,						September 30, 2005			September 30, 2005 Pro Forma
			2003			2004			September 30, 2005			September 30, 2005 Pro Forma
									(unaudited)
Liabilities and Members' Capital (Deficit)
Current liabilities:
	Current portion of long-term notes payable (note 9)		$	—		$	58,113		$	104,930
	Current portion of interest rate swaps (note 3)			—			38,933			—
	Property acquisition payable (note 2)			18,009,338			—			—
	Accounts payable and accrued expenses			784,310			3,027,201			2,993,730
	Current portion of natural gas derivatives (note 7)			718,901			3,456,944			22,288,417
	Revenue distribution			583,794			2,493,145			1,801,233
	Accrued interest payable (note 3)			222,594			411,245			699,652
	Gas purchases payable			—			481,993			1,104,617
	Other current liabilities		—			—			350,625
		Total current liabilities	20,318,937			9,967,574			29,343,204
Long-term liabilities:
	Long-term portion of notes payable (notes 9 and 16)			—			539,867			697,191
	Credit facility (note 3)			41,517,954			72,210,107			138,278,187
	Long-term portion of interest rate swaps (note 3)			188,928			1,408,629			855,225
	Asset retirement obligation (note 10)			2,053,077			3,856,584			4,418,209
	Long-term portion of natural gas derivatives (note 7)			880,953			7,639,555			21,937,866
	Other long-term liabilities		—			—			201,592
		Total long-term liabilities	44,640,912			85,654,742			166,388,270
		Total liabilities		64,959,849			95,622,316			195,731,474
Members' capital (deficit):
	Members' capital (note 17)			16,023,743			16,023,743			16,023,743		$	139,773,743
	Accumulated loss			(1,334,700	)		(5,312,488	)		(68,168,485	)		(69,918,485	)

				14,689,043			10,711,255			(52,144,742	)		69,855,258

		Total liabilities and members' capital (deficit)	79,648,892			106,333,571			143,586,732

See accompanying notes to consolidated financial statements.

F-5

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE PERIOD
FROM MARCH 14, 2003 (INCEPTION) TO DECEMBER 31, 2003
AND YEAR ENDED DECEMBER 31, 2004
AND FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 2004 AND 2005

			Period from March 14, 2003 (inception) to December 31, 2003
									Nine Month Period Ended September 30,
						Year Ended December 31, 2004			Nine Month Period Ended September 30,
						Year Ended December 31, 2004			2004			2005
									(unaudited)
Revenues:
	Natural gas and oil sales		$	3,323,465		$	21,231,640		$	14,205,439		$	24,408,270
	Realized gain (loss) on natural gas derivatives (note 7)			162,890			(2,239,506	)		(925,575	)		(45,821,646	)
	Unrealized (loss) on natural gas derivatives (note 7)			(1,599,854	)		(8,764,855	)		(10,890,534	)		(26,788,755	)
	Natural gas marketing income			—			520,340			—			3,087,106
	Other income			3,778			160,131			86,280			158,418

				1,890,279			10,907,750			2,475,610			(44,956,607	)

Expenses:
	Operating expenses			916,638			5,459,503			4,376,894			4,617,088
	Natural gas marketing expense			—			481,993			—			3,161,930
	General and administrative expenses			845,633			1,583,054			1,065,655			2,309,315
	Depreciation, depletion and amortization			972,119			3,749,318			2,408,498			3,736,002

				2,734,390			11,273,868			7,851,047			13,824,335

				(844,111	)		(366,118	)		(5,375,437	)		(58,780,942	)

Other income and (expenses):
	Interest income			34,139			7,379			6,610			15,985
	Interest and financing expense (note 3)			(516,883	)		(3,530,360	)		(2,936,213	)		(3,282,352	)
	Loss from equity investment			(2,929	)		(56,126	)		(42,095	)		(16,714	)
	Write-off of deferred financing fees (note 16)			—			—			—			(364,166	)
	(Loss) on sale of assets			(4,916	)		(32,563	)		(10,163	)		(43,016	)

				(490,589	)		(3,611,670	)		(2,981,861	)		(3,690,263	)

Loss before income taxes				(1,334,700	)		(3,977,788	)		(8,357,298	)		(62,471,205	)
	Income tax provision			—			—			—			384,792

		Net (loss)	$	(1,334,700	)	$	(3,977,788	)	$	(8,357,298	)	$	(62,855,997	)

		Year Ended December 31, 2004			Nine Month Period Ended September 30, 2005
Pro forma (loss) per unit (unaudited)(note 17)
	Pro forma (loss) per unit	$	(0.14	)	$	(2.26	)
	Pro forma units outstanding		27,812,500			27,812,500

See accompanying notes to consolidated financial statements.

F-6

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS' CAPITAL (DEFICIT)

FOR THE PERIOD
FROM MARCH 14, 2003 (INCEPTION) TO DECEMBER 31, 2003
AND YEAR ENDED DECEMBER 31, 2004
AND FOR THE NINE MONTH PERIOD ENDED SEPTEMBER 30, 2005

	Members' Capital			Accumulated Loss			Total Members' Capital (Deficit)
Contributions	$	16,323,743		$	—		$	16,323,743
Return of capital (note 4)		(300,000	)		—			(300,000	)
Net loss for period from March 14, 2003 (inception) to December 31, 2003		—			(1,334,700	)		(1,334,700	)

Balance as of December 31, 2003		16,023,743			(1,334,700	)		14,689,043
Net loss for year ended December 31, 2004		—			(3,977,788	)		(3,977,788	)

Balance as of December 31, 2004		16,023,743			(5,312,488	)		10,711,255
Net loss for the nine months ended September 30, 2005 (unaudited)		—			(62,855,997	)		(62,855,997	)

Balance as of September 30, 2005 (unaudited)	$	16,023,743		$	(68,168,485	)	$	(52,144,742	)

See accompanying notes to consolidated financial statements.

F-7

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE PERIOD FROM MARCH 14, 2003 (INCEPTION) TO

DECEMBER 31, 2003 AND YEAR ENDED DECEMBER 31, 2004

AND FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 2004 AND 2005

					Period from March 14, 2003 (inception) to December 31, 2003						Nine Month Period Ended September 30,
								Year Ended December 31, 2004			Nine Month Period Ended September 30,
								Year Ended December 31, 2004			2004			2005
											(unaudited)
Cash flow from operating activities:
	Net (loss)				$	(1,334,700	)	$	(3,977,788	)	$	(8,357,298	)	$	(62,855,997	)
	Adjustments to reconcile net (loss) to net cash provided by (used in) operating activities:
		Depreciation, depletion and amortization				972,119			3,749,318			2,408,498			3,736,002
		Amortization of deferred financing fees				20,454			123,403			81,875			148,845
		Write-off of deferred financing fees				—			—			—			364,166
		Loss on sale of assets				4,916			32,563			10,163			43,016
		Loss from equity investment				2,929			56,126			42,095			16,714
		Accretion of asset retirement obligation				14,683			73,501			50,699			124,403
		Unrealized loss on natural gas derivatives				1,599,854			8,764,855			10,890,534			26,788,755
		Unrealized loss (gain) on interest rate swaps				188,928			1,258,634			1,471,306			(775,722	)
		Changes in assets and liabilities:
			(Increase) in accounts receivable			(1,523,471	)		(3,366,264	)		(1,678,780	)		(3,134,727	)
			(Increase) in inventory			—			(179	)		(157	)		(9,706	)
			(Increase) in gas options			—			—			—			(1,627,900	)
			(Increase) decrease in prepaid expenses and other assets			(98,972	)		5,190			54,717			(2,216,093	)
			(Increase) in operating bonds			(75,342	)		(35,357	)		(21,055	)		(50,121	)
			Increase (decrease) in accounts payable and accrued expenses			376,471			1,338,981			1,081,971			(33,471	)
			(Decrease) increase in natural gas derivatives receivable/payable			(27,700	)		759,490			(40,250	)		2,029,541
			Increase (decrease) in revenue distribution			583,794			1,909,351			802,159			(691,912	)
			Increase in asset retirement obligation			2,299			18,754			26,407			20,151
			Increase in accrued interest payable			222,594			188,651			195,165			288,407
			Increase in other liabilities			—			—			—			552,217
			Increase in gas purchases payable			—			481,993			—			622,624

				Net cash provided by (used in) operating activities		928,856			11,381,222			7,018,049			(36,660,808	)

Cash flow from investing activities:
	(Decrease) in property acquisition payable					—			(18,009,338	)		(18,009,338	)		—
	Acquisition of natural gas and oil properties and related equipment					(33,592,681	)		(45,130,995	)		(40,085,980	)		(27,098,019	)
	Purchases of property and equipment					(409,613	)		(1,518,966	)		(886,129	)		(874,277	)
	Proceeds from sale of assets					8,584			334,037			19,837			32,464
	(Increase) decrease in prepaid drilling cost					(2,300,643	)		1,938,548			2,031,871			(365,801	)
	Purchase of equity investment					(113,242	)		(15,498	)		(15,499	)		(3,625	)

				Net cash (used in) investing activities		(36,407,595	)		(62,402,212	)		(56,945,238	)		(28,309,258	)

Cash flow from financing activities:
	Proceeds from notes payable					—			604,358			400,000			5,262,205
	Principal payments on notes payable					—			(6,378	)		—			(5,058,064	)
	Principal payment on credit facility					—			—			—			(75,605,000	)
	Proceeds from credit facility					41,800,000			30,805,000			30,805,000			142,000,000
	Deferred financing fees					(302,500	)		(236,250	)		(115,000	)		(839,929	)
	Capital contributions by members					16,323,743			—			—			—
	Return on capital					(300,000	)		—			—			—

				Net cash provided by financing activities		57,521,243			31,166,730			31,090,000			65,759,212

				Net increase (decrease) in cash		22,042,504			(19,854,260	)		(18,837,189	)		789,146
Cash and cash equivalents:
	Beginning					—			22,042,504			22,042,504			2,188,244

	Ending				$	22,042,504		$	2,188,244		$	3,205,315		$	2,977,390

		Cash payments for interest			$	84,907		$	1,959,672		$	1,187,867		$	3,595,822
Supplemental disclosures of noncash flow information:
	Increase in accounts payable related to acquisitions				$	407,839		$	903,910		$	903,910		$	—
	Increase in property acquisition payable					18,009,338			—			—			—
	Increase in inventory related to acquisitions					63,806			46,000			46,000			—
	Increase in natural gas and oil properties and related asset retirement obligation due to acquisitions and new drilling					2,036,095			1,711,252			1,688,574			417,071

See accompanying notes to consolidated financial statements.

F-8

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2004 AND FOR THE NINE MONTH PERIODS ENDED
SEPTEMBER 30, 2004 AND 2005 (UNAUDITED)

(1) Summary of Significant Accounting Policies

(a): Organization and Description of Business

Linn Energy, LLC (Linn or the Company) was organized as a limited liability company March 14, 2003 under the laws of the State of Delaware. Linn began its primary operations effective April 1, 2003. The Company owns 100% of Linn Operating, LLC (Operating) and Chipperco, LLC (Chipperco). Operating was organized effective August 27, 2003 under the laws of the State of Delaware and began its primary operations effective September 1, 2003. Chipperco was organized effective September 13, 2004 under the laws of the State of Delaware and began its primary operations effective November 1, 2004. The Company is an independent natural gas company focused on the development, exploitation and acquisition of natural gas properties in the Appalachian Basin, primarily in Pennsylvania, West Virginia, New York and Virginia. The Company was formed in March 2003 by its President and Chief Executive Officer Michael C. Linn, Quantum Energy Partners and non-affiliated investors with an aggregate equity investment of $16.3 million.

(b): Basis of Presentation

The accompanying consolidated financial statements include the accounts of Linn Energy, LLC and its wholly owned operating subsidiaries, Operating and Chipperco. All significant intercompany accounts and transactions have been eliminated in consolidation. The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. As used herein, the terms Linn Energy, LLC and the Company refer to Linn Energy, LLC and its wholly owned subsidiaries unless the context specifies otherwise.

(c): Cash Equivalents

For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.

(d): Trade Accounts Receivable

Trade account receivables are recorded at the invoiced amount and do not bear interest. The Company routinely assesses the financial strength of its customers and, bad debts are recorded based on an account-by-account review after all means of collection have been exhausted, and the potential recovery is considered remote. The Company does not have any off-balance-sheet credit exposure related to its customers.

(e): Inventory

Inventory of well equipment, parts, and supplies are valued at cost, determined by the first-in-first-out method.

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(f): Natural Gas and Oil Properties

The Company accounts for natural gas and oil properties by the successful efforts method. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depreciation and depletion of producing natural gas and oil properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Statement of Financial Accounting Standards (SFAS) No. 19 requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described in note 14, proved reserves are estimated by an independent petroleum engineer, Schlumberger Data and Consulting Services, Inc., and are subject to future revisions based on availability of additional information. As described in note 10, the Company follows SFAS No. 143. Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by the Company's engineers using existing regulatory requirements and anticipated future inflation rates.

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

Natural gas and oil properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Company assesses impairment of capitalized costs of proved natural gas and oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2003 and 2004, the estimated undiscounted future cash flows for the Company's proved natural gas and oil properties exceeded the net capitalized costs, and no impairment was required to be recognized.

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Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Property acquisition costs are capitalized when incurred.

(g): Natural Gas and Oil Reserve Quantities

The Company's estimate of proved reserves is based on the quantities of natural gas and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Schlumberger Data and Consulting Services prepares a reserve and economic evaluation of all the Company's properties on a well-by-well basis.

Reserves and their relation to estimated future net cash flows impact the Company's depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company's reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

The Company's proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and oil eventually recovered.

(h): Property, Plant and Equipment

Property, plant and equipment other than natural gas and oil properties is carried at cost. Depreciation is provided principally on the straight-line method over useful lives as follows:

Buildings and leasehold improvements		7-39 years
Furniture and equipment		5-7 years
Vehicles		5 years

Long-lived assets, such as property and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds

F-11

its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, depletion, and amortization are removed from the accounts, the proceeds applied thereto, and any resulting gain or loss is reflected in income for the period.

(i): Income Taxes

No provision for income taxes is made in the Company's consolidated financial statements because the taxable income or loss of the Company is included in the income tax returns of the individual members. As of December 31, 2003 and 2004, the income tax basis of the Company's assets was $75,689,613 and $80,510,331, respectively.

(j): Derivative Instruments and Hedging Activities

The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its natural gas production by reducing its exposure to price fluctuations. Currently, these transactions are swaps. Additionally, the Company uses derivative financial instruments in the form of interest rate swaps to mitigate its interest rate exposure. The Company accounts for these activities pursuant to SFAS No. 133 — Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. SFAS No. 133 requires that a company formally document, at the inception of a hedge, the hedging relationship and the entity's risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative's fair value. Any ineffective portion of the derivative instrument's change in fair value is recognized immediately in earnings.

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(k): Use of Estimates

Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates, which are particularly significant to the financial statements, include estimates of natural gas and oil reserves, future cash flows from natural gas and oil properties, and depreciation, depletion and amortization.

(l): Revenue Recognition

Sales of natural gas and oil are recognized when natural gas has been delivered to a 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 price is fixed or determinable. Natural gas is sold by the Company on a monthly basis. Virtually all of the Company's contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry.

Gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total gas production. Any amount received in excess of the Company's share is treated as a liability. If the Company receives less than its entitled share the underproduction is recorded as a receivable. The Company did not have any significant gas imbalance positions at December 31, 2003 or 2004.

Natural gas marketing is recorded on the gross accounting method. Chipperco, the Company's marketing subsidiary which began operations effective November 1, 2004, purchases natural gas from many small producers and bundles the natural gas together to sell in larger amounts to purchasers of natural gas for a price advantage. Chipperco has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because Chipperco takes title to the natural gas it purchases from the various producers and bears the risks and enjoys the benefits of that ownership. Chipperco had natural gas marketing revenues of $520,340 and natural gas marketing expenses of $481,993 in 2004.

The Company currently uses the "Net-Back" method of accounting for transportation arrangements of its natural gas sales. The Company sells natural gas at the wellhead and

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collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by its customers and reflected in the wellhead price.

The Company is paid a monthly operating fee for each well it operates for outside owners. The fee covers monthly operating and accounting costs, insurance, and other recurring costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted against general and administrative expense.

(m): Fair Value of Financial Instruments

The carrying values of the Company's receivables, payables and debt are estimated to be substantially the same as their fair values as of December 31, 2003 and 2004. Please read note 7 for discussion related to derivative financial instruments.

(n): Deferred Financing Fees

The Company incurred legal and bank fees related to the issuance of debt (note 3). The financing fees incurred for the period from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004 were $302,500 and $236,250, respectively. These debt issuance costs are amortized over the life of the credit facility, which is 36 months. For the period from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004, amortization expense of $20,454 and $123,403, respectively, is included in interest expense.

(o): Investment

The Company has a 33% interest in Big Creek Pipeline, a partnership that is primarily involved in the transportation of natural gas. The investment is accounted for using the equity method; therefore, the Company's portion of income is recognized in the accompanying consolidated statements of operations.

(p): Members' Capital

The operations of the Company are governed by the provisions of a limited liability company agreement executed by and among its members. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of Linn's members. The total capital contributed by the members as of December 31, 2003 and 2004 was $16,323,743, of which Quantum's share was $15,000,000.

(q): Advertising Costs

Advertising costs have been expensed as incurred. For the period from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004, $2,406 and $14,722, respectively, of advertising costs were expensed.

F-14

(r): Revenue Distribution

Revenue distribution on the consolidated balance sheet of $583,794 and $2,493,145 represents amounts owed to other working interest and royalty interest owners as of December 31, 2003 and 2004, respectively.

(s): Deferred Offering Costs

Prepaid expenses include costs incurred in connection with the Company's planned initial public offering (IPO). The Company will reclassify these deferred offering costs to members' capital upon receipt of the proceeds from the IPO, or expense them if an IPO is not sucessfully completed. As of September 30, 2005, prepaid expenses included $2.1 million (unaudited) in deferred offering costs.

(t): Stock Based Compensation

We account for Stock Based Compensation pursuant to SFAS No. 123(R)—Share-Based Payment. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement and eliminates the alternative to use the intrinsic value method of accounting that was provided in SFAS No. 123, which generally resulted in no compensation expense recorded in the financial statements related to the issuance of equity awards to employees. It establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all companies to apply a fair-value-based measurement method in accounting for generally all share- based payment transactions with employees. On March 29, 2005, the SEC staff issued SAB No. 107, Share-Based Payment, to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff's views regarding the valuation of share-based payment arrangements for public companies.

(u): Recently Issued Accounting Standards

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mineral rights of oil- and gas-producing entities that are within the scope of SFAS No. 19 — Financial Accounting and Reporting by Oil and Gas Producing Companies, are tangible assets. Historically, the Company has included the costs of such mineral rights as a component of natural gas and oil properties, which is consistent with the FSP. As such, the Company's consolidated financial statements were not affected.

In December 2003, the FASB issued FASB Interpretation (FIN) No. 46 (revised December 2003) — Consolidation of Variable Interest Entities, which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and, accordingly, should consolidate the entity. The Company applies FIN No. 46R to variable interests in VIEs created after December 31, 2003. For variable interests in VIEs created before January 1, 2004, the Interpretation will be applied beginning on January 1, 2005. For any VIEs that must be consolidated under FIN No. 46R that were created before January 1, 2004, the assets, liabilities, and noncontrolling interests of the VIE initially would be measured at their carrying amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect of an accounting change. If determining the carrying amounts is not practicable, fair value at the date FIN No. 46R first applies may be used to measure the assets, liabilities, and noncontrolling interest of the VIE. The Company has evaluated the impact of FIN No. 46R and has determined that there are no entities that qualify as VIEs.

On March 30, 2005, the FASB issued FIN No. 47 — Accounting for Conditional Asset Retirement Obligations. This interpretation clarifies that the term "conditional asset retirement obligation" as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 will be effective for the Company at the end of the fiscal year ended December 31, 2005. The Company does not expect the application of FIN No. 47 to have a significant impact on the Company's financial position or results of operations.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1 — Accounting for Suspended Well Costs. This staff position amends SFAS No. 19 — Financial Accounting and Reporting by Oil and Gas Producing Companies and provides guidance about

F-16

exploratory well costs to companies which use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well's economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management's evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in the FSP is required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The Company does not expect the application of this FSP to have a significant impact on the Company's financial position or results of operations.

(2) Major Acquisitions

The Company consummated the following acquisitions of natural gas and oil properties:

•: On May 30, 2003, from Emax Oil Company, 34 producing wells in southern West Virginia for a purchase price of $3.1 million;
•: On August 1, 2003, from Lenape Resources, Inc., 61 producing wells in Chautauqua County, New York, for a purchase price of $2.0 million.
•: On September 30, 2003, from Cabot Oil & Gas Corporation, 50 producing wells in western Pennsylvania, for a purchase price of $15.5 million.
•: On October 31, 2003, from Waco Oil & Gas Company (Waco), 353 producing wells in West Virginia and western Virginia for a purchase price of $31.0 million. Of this amount, $18 million was payable to Waco as of December 31, 2003. The outstanding balance was remitted on January 2, 2004 pursuant to the terms of the promissory note.
•: On May 7, 2004, from Mountain V Oil and Gas, Inc., 251 producing wells, tangible wellhead equipment, production facilities, and real estate in western Pennsylvania, for a purchase price of $12.4 million.

F-17

•: On September 30, 2004, from Pentex Energy, Inc., 447 producing wells, operating rights, oil field equipment, vehicles, inventory, office equipment, furniture and fixtures, and real estate in western Pennsylvania, for a purchase price of $14.2 million.

The following unaudited pro forma information presents the financial information of the Company as if all the acquisitions had occurred on March 14, 2003.

	Period from March 14, 2003 (inception) through December 31, 2003					Year ended December 31, 2004
	As reported			Pro forma		As reported			Pro forma
	(in thousands)					(in thousands)
Natural gas and oil revenue	$	3,323		$	13,270	$	21,232		$	24,154

Net (loss) income	$	(1,335	)	$	911	$	(3,978	)	$	(3,125	)

(3) Credit Facility

On May 30, 2003, the Company entered into a $75 million Senior Secured Credit Facility (the Agreement), which allowed the Company to borrow up to the determined amount of the borrowing base, which was based upon the loan collateral value assigned to the various natural gas and oil properties of the Company. A majority of Linn's producing natural gas and oil properties served as collateral. The borrowing base was subject to semi-annual redetermination. The Agreement was amended twice in 2003, increasing the borrowing base to $42 million. In 2004, the borrowing base was increased to $73 million. See note 16, Subsequent Events, for a description of the terms of the new credit facility.

Under the Agreement and as of December 31, 2003 and 2004, the Company had borrowed $41.8 million and $72.6 million, respectively, on the credit facility. As of December 31, 2003, the applicable interest rate was 3.2%, and as of December 31, 2004, the applicable weighted average interest rate was 4.1%. As of June 30, 2005, the Company had borrowed $98.5 million (unaudited). As of June 30, 2005, the applicable weighted average interest rate was 5.1% (unaudited).

The Agreement required the Company to, among other things, maintain a minimum working capital balance and achieve certain earnings-related ratios, and limited the amount of indebtedness and certain distributions. The working capital and earnings-related ratio were calculated based on tax basis financial statements. At December 31, 2003 and 2004, the Company was in compliance with the Agreement's covenants.

In 2003, the Company entered into two interest rate swap agreements with a financial institution to minimize the effect of fluctuations in interest rates. Each agreement had a notional amount of $30,000,000. The agreements were effective and matured in 2005 and 2006. The Company was required to pay interest quarterly at a rate of 3.17% and 4.33%, respectively. The Company received quarterly payments based on the three-month LIBOR

F-18

rate. As of December 31, 2003, the fair value of the interest rate swap agreements was $(188,928).

In 2004, the Company entered into two additional interest rate swap agreements with the same financial institution. Each agreement had a notional amount of $50,000,000. The agreements were effective and matured in 2007 and 2008. The Company was required to pay quarterly interest at a rate of 5.23% and 5.72%, respectively. The Company received quarterly payments based on the three-month LIBOR rate.

Additionally in 2004, the Company entered into two interest rate swap agreements with a financial institution to minimize the effect of fluctuations in interest rates. Each agreement has a notional amount of $20,000,000. The interest rate swap agreements are effective and mature in 2005 and 2006, and the Company is required to pay quarterly interest payments at a rate of 3.08% and 4.42%, respectively. The Company receives quarterly payments base on the three-month LIBOR rate.

As of December 31, 2004, the total fair value of the interest rate swap agreements was a liability of $1,447,562. The current portion of interest swaps was a liability of $38,933 and is recorded as a separate account on the balance sheet. Losses due to the change in the fair value of $188,928 in 2003 and $1,258,634 in 2004 are recorded in interest and financing expense in the accompanying consolidated statements of operations.

As of September 30, 2005, the total fair value of the interest rate swap agreement was a liability of $671,840. The current portion of $183,385 is recorded as a receivable on the balance sheet. (Losses) gains due to changes in the fair value of $(1,471,306) and $775,722 for the nine months ended September 30, 2004 and 2005, respectively, are recorded in interest and financing expense on the accompanying consolidated statements of operations (unaudited).

As of December 31, 2003 and 2004 and September 30, 2005, the credit facility consists of the following:

	December 31, 2003			December 31, 2004			September 30, 2005 (unaudited)
Outstanding balance	$	41,800,000		$	72,605,000		$	139,000,000
Less deferred financing fees, net of amortization of $20,454, $143,857 and $103,116 (unaudited)		(282,046	)		(394,893	)		(721,813	)

	$	41,517,954		$	72,210,107		$	138,278,187

Accrued interest was $222,594, $411,245 and $699,652 (unaudited) at December 31, 2003 and 2004, and September 30, 2005, respectively.

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(4) Related Party Transactions

Under the terms of the limited liability company agreement, Linn pays to Quantum, the majority member, a fee of 2.0% of each capital contribution made to the Company by Quantum. Management believes the 2% fee was fair value. The 2% fee was initially negotiated on an arms-length basis among unrelated third parties. Fees paid during the period from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004 were $300,000 and $0, respectively. The payments were recognized as a return of capital on the consolidated statements of members' capital.

On December 1, 2003, the Company entered into an assignment and bill of sale with Linn Resources, LLC, a related party, for the purchase of all of Linn Resources' interests in 2 wells and related equipment. The purchase price for this transaction was approximately $150,000. The purchase price was determined based on the price paid for working interests from an unrelated third party during 2003 and thus management believes this transaction was conducted at fair value.

(5) Commitments and Contingencies

The Company would be exposed to natural gas price fluctuations on underlying sale contracts should the counterparties to the Company's derivative instruments or the counterparties to the Company's natural gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses during the period from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004.

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

(6) Business and Credit Concentrations

Cash

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

Revenue and Trade Receivables

The Company has a concentration of customers who are engaged in natural gas and oil production within the Appalachian region. This concentration of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company performs ongoing credit evaluations of its customers and generally does not require collateral.

F-20

The Company's largest customers are natural gas producers and suppliers located within the Appalachian region. For the period from March 14, 2003 (inception) through December 31, 2003, the Company's four largest customers represented 25%, 17%, 14%, and 11% of the Company's sales. The Company's four largest customers represented approximately 33%, 19%, 16%, and 13% of the Company's sales for the year ended December 31, 2004.

Trade accounts receivable from gas sales from four customers accounted for more than 10% of the Company's trade accounts receivable. As of December 31, 2003, trade accounts receivable from these customers represented approximately 24%, 29%, 9%, and 19% of the Company's receivables. Trade accounts receivables for the four largest customers represented approximately 17%, 17%, 11%, and 29% of the Company's receivables as of December 31, 2004.

(7) Natural Gas Derivatives

The Company sells natural gas in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in natural gas. The Company enters into derivative instruments such as swap contracts and put options to hedge a portion of its forecasted natural gas sales.

The natural gas derivatives are not designated as hedges and, accordingly, the changes in fair value were recorded in current period earnings:

	December 31
	December 31						September 30, 2005
	2003			2004			September 30, 2005
							(unaudited)
Net unrealized gain (loss) at balance sheet date expected to be settled within next 12 months	$	(718,901	)	$	(2,725,154	)	$	(18,914,582	)
Net unrealized gain (loss) at balance sheet date expected to be settled beyond next 12 months		(880,953	)		(7,639,555	)		(16,610,982	)
Outstanding notional amounts of hedges (MMMBtu)		5,625			12,628			23,653
Maximum number of months hedges outstanding		58			61			51

In addition to the short-term unrealized amounts above, the Company also has recorded a current asset of $27,700 and current liabilities of $731,790 and $2,761,331 as of December 31, 2003 and 2004, and September 30, 2005 respectively, for realized gains or losses which were not paid or received as of period-end.

By using derivative instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates repayment

F-21

risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

(8) Operating Lease for Office Space

The Company leases its headquarters office space under a lease agreement for a period of 60 months. For the period from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004, the Company recognized expense under the operating lease of $30,854 and $66,499, respectively.

The Company leases its field office in Glenville, West Virginia, under a lease agreement for a period of 36 months. For the period from March 14, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004, the Company recognized expense of $0 and $33,000, respectively.

As of December 31, 2004, future lease payments are as follows:

2005	$	115,715
2006		114,731
2007		87,184
2008		89,385
2009		37,625

	$	444,640

The above table includes potential continuing lease payments under the Company's existing office lease. The Company anticipates moving its principal office to a new facility during the third quarter in 2005. The existing lease, which expires in 2009, allows the Company to sublease its existing facility with the approval of the lessor. If the Company is unable to sublease its existing facility, it will be required to make lease payments until 2009 in an aggregate amount of approximately $373,000.

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(9) Long-term Notes Payable

As of December 31, 2004, the Company has the following long-term notes payable outstanding:

Note payable to a bank with an interest rate of 6.14%, payable in monthly installments of $2,918, including interest, through September, 2024. The notes are secured by an office building	$	397,439
Various notes for the purchase of vehicles, payable in monthly installments totaling $4,752, including interest at 5.49%. The notes are secured by the vehicles purchased and expire in 2008		200,541

		597,980
Less current portion		58,113

	$	539,867

As of December 31, 2004, maturities on the aforementioned long-term debt are as follows:

December 31:
	2005	$	58,113
	2006		61,461
	2007		65,001
	2008		63,930
	2009		13,957
Thereafter			335,518

		$	597,980

(10) Asset Retirement Obligation

The Company follows Statement of Financial Accounting Standards (SFAS) No. 143 — Accounting for Asset Retirement Obligations. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the assets' useful life. The asset retirement obligations recorded by the Company relate to the plugging and abandonment of natural gas and oil wells.

At December 31, 2003 and 2004, there were no assets legally restricted for purposes of settling asset retirement obligations. Additional retirement obligations increase the liability associated with new natural gas and oil wells and other facilities as these obligations are incurred. Under certain operating agreements, the Company withholds funds from the working interest owners for future plugging costs. These liabilities from the amounts withheld

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are included in the total asset retirement obligation on the accompanying consolidated balance sheets.

The following table reflects the changes of the asset retirement obligations during the period from March 14, 2003 (inception) through December 31, 2003, the year ended December 31, 2004 and the nine months ended September 30, 2005:

	December 31, 2003		December 31, 2004		September 30, 2005
					(unaudited)
Carrying amount of asset retirement obligation at beginning of year/period	$	—	$	2,053,077	$	3,856,584
Liabilities added during the current period related to acquisitions or drilling of additional wells		2,036,095		1,711,252		417,071
Cash withheld during the current period from unrelated third parties who own working interests		2,299		18,754		20,151
Current period accretion expense		14,683		73,501		124,403

Carrying amount of asset retirement obligations at December 31	$	2,053,077	$	3,856,584	$	4,418,209

The discount rate used in calculating the asset retirement obligation was 3.2%, 4.3% and 5.0% (unaudited) in 2003, 2004 and 2005, respectively. These notes approximate the Company's borrowing rates. Please see Note 3.

(11) Costs Incurred in Natural Gas and Oil Property Acquisition and Development Activities

Costs incurred by the Company in natural gas and oil property acquisition and development are presented below:

	March 14, 2003 (inception) to December 31, 2003		Year Ended December 31, 2004
Property acquisition costs, proved	$	51,659,634	$	29,256,320
Development costs		286,418		16,732,586
Company's share of equity investee's costs of property acquisition, exploration, and development		—		15,498

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The proved reserves attributable to the development costs in the above table were 0 and 5,566,000 Mcf, respectively, for the period from March 14, 2003 to December 31, 2003 and the year ended December 31, 2004 (amounts unaudited). Of the above development costs incurred in 2003 and 2004, the amounts of $0 and $14,771,402, respectively, were incurred to develop proved undeveloped properties from the prior period-end.

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas.

(12) Natural Gas and Oil Capitalized Costs

Aggregate capitalized costs for the Company related to natural gas and oil production activities with applicable accumulated depreciation, depletion, and amortization are presented below:

		December 31
		2003		2004
Proved natural gas and oil properties		$	53,982,147	$	101,682,305
Unproved natural gas and oil properties			—		—

			53,982,147		101,682,305
Less accumulated depreciation, depletion, and amortization			946,123		4,559,714

	Net capitalized costs	$	53,036,024	$	97,122,591

Company's share of equity method investee's net capitalized costs		$	110,313	$	69,685

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(13) Results of Natural Gas and Oil Producing Activities

The results of operations for natural gas and oil producing activities (excluding corporate overhead and interest costs) are presented below:

			Period from March 14, 2003 (inception) to December 31, 2003			Year Ended December 31, 2004
Revenue:
	Natural gas and oil sales, excluding Chipperco marketing sales of $0 and $520,340 in 2003 and 2004, respectively		$	3,323,465		$	21,231,640
	Less: Realized losses (gains) on natural gas derivatives			(162,890	)		2,239,506
	Unrealized losses on natural gas derivatives			1,599,854			8,764,855

		Net natural gas and oil sales		1,886,501			10,227,279

Expenses:
	Production costs			916,638			5,459,503
	Depreciation, depletion, and amortization			946,123			3,613,591

		Total expenses		1,862,761			9,073,094

		Results of operations for natural gas and oil producing activities (excluding corporate overhead and interest costs)	$	23,740		$	1,154,185

		Company's share of equity method investee's results of operations for producing activities	$	(2,929	)	$	(56,126	)

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities.

Depreciation, depletion, and amortization expense includes those costs associated with capitalized acquisition and development costs and support equipment.

There is no provision for income taxes because the Company is a nontaxable entity.

(14) Net Proved Natural Gas Reserves (Unaudited)

The proved reserves of natural gas of the Company have been estimated by an independent petroleum engineer, Schlumberger Data and Consulting Services, at December 31, 2003 and

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2004. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices. An analysis of the change in estimated quantities of natural gas and oil reserves, all of which are located within the United States, is shown below:

		2003		2004
		(Mcfe)
Proved developed and undeveloped reserves:
	Beginning of year	—		69,805,000
	Revisions of previous estimates	—		754,946
	Purchase of minerals in place	70,607,481		36,100,000
	Extensions and discoveries	—		16,484,959
	Production	(802,481	)	(3,384,905	)

	End of year	69,805,000		119,760,000

Proved developed reserves:
	Beginning of year	—		41,760,059

	End of year	41,760,059		74,365,863

The above table includes changes in estimated quantities of oil reserves shown in Mcf equivalents at a rate of six barrels per Mcf. Net oil production included above represents approximately 1% and 2% of total production in 2003 and 2004, respectively.

The 754,946 Mcfe increase in revisions of previous estimates was due to the increase in natural gas prices and the addition of another year of projections to support the maximum economic life of 50 years.

With respect to extensions and discoveries, 10,918,959 Mcfe are upward changes resulting from an increase in the Company's proved undeveloped acreage. An additional 5,566,000 Mcfe of new discoveries and extensions resulted from drilling 10 wells on unproved acreage. The drilling of these wells added reserves for these 10 wells and from an additional 14 proved undeveloped locations that the 10 drilled wells proved up.

Linn Energy, LLC made two acquisitions in 2004 with total proved reserves of 36,100,000 Mcfe.

(15) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)

Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future

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cash inflows are computed by applying year-end prices relating to the Company's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is a nontaxable entity.

		December 31
		2003			2004
Future estimated revenues		$	462,420,073		$	840,126,938
Future estimated production costs			(79,798,024	)		(146,672,338	)
Future estimated development costs			(24,076,000	)		(41,417,000	)

	Future net cash flows		358,546,049			652,037,600
10% annual discount for estimated timing of cash flows			(232,204,590	)		(437,003,850	)

	Standardized measure of discounted future estimated net cash flows	$	126,341,459		$	215,033,750

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:

	Period from March 14, 2003 (inception) to December 31, 2003			Year Ended December 31, 2004
Sales of natural gas and oil production, net of production costs	$	(2,527,810	)	$	(16,608,151	)
Changes in estimated future development costs		24,076,000			17,341,000
Net changes in prices and production costs		—			15,008,075
Acquisitions		336,711,441			176,970,232
Extensions, discoveries, and improved recovery, less related cost		—			80,376,427
Development costs incurred during the period		286,418			16,732,586
Revisions of previous quantity estimates		—			3,671,382
Less change in discount		(232,204,590	)		(204,799,260	)

	$	126,341,459		$	88,692,291

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It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand, and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

(16) Subsequent Events

In the first quarter of 2005, the Company entered into a letter of intent with Columbia Natural Resources, LLC for the acquisition of 38 wells in West Virginia and western Virginia. The purchase price was $4.3 million, and the transaction closed on April 27, 2005.

On April 11, 2005, the Company entered into a $200 million secured revolving credit agreement with a group of banks including BNP Paribas and RBC Capital Markets. The funds from the new credit facility were used to pay off the balance outstanding on the old credit facility in place as of December 31, 2004. The new credit facility matures on April 11, 2009. The outstanding balance on the new credit facility accrues interest at a rate of LIBOR plus an applicable margin of between 1.25% and 1.875% or the prime rate plus an applicable margin between 0.00% to 0.375%. Interest is payable quarterly and at the maturity date. The new credit facility also contains covenants requiring the Company to maintain the following ratios:

•: consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization and other similar charges, minus all noncash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0; and
•: consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under SFAS No. 133, which includes the current portion of natural gas and interest rate swaps.

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In connection with the new credit facility, the Company converted its initial four interest rate swap agreements to a new third party financial institution. The terms of the new four interest rate swap agreements are as follows:

•: Agreement effective in April 2005 for $30 million. The Company is required to make quarterly interest payments during 2005 at a rate of 3.24%. The agreement matures in January 2006.
•: Agreement effective in January 2006 for $30 million. The Company is required to make quarterly interest payments during 2006 at a rate of 4.4%. The agreement matures in January 2007.
•: Agreement effective in January 2007 for $50 million. The Company is required to make quarterly interest payments during 2007 at a rate of 5.3%. The agreement matures in December 2007.
•: Agreement effective in January 2008 for $50 million. The Company is required to make quarterly interest payments during 2008 at a rate of 5.79%. The agreement matures in December 2008.

The Company received quarterly interest payments at the three month LIBOR rate.

As a result of the new credit facility, the Company will write off approximately $360,000 of deferred financing cost related to the old credit agreement to be reflected in the income statement for the second quarter of 2005.

In 2005, the Company cancelled natural gas swaps with total volumes of 6,999 MMMBtu related to swaps originally scheduled to be settled from October 2005 through December 2007. These settled swaps had a weighted average contract price of $5.11 per MMBtu. In connection with the cancellation (before their original settlement date) of the swap agreements, the Company paid $15.1 million, of which $8.0 million was paid in the first quarter of 2005 and $7.1 million was paid in the second quarter of 2005.

The Company also entered into new swaps with total volumes of 6,999 MMMBtus related to contracts scheduled to be settled from October 2005 through December 2007. The new swaps have a weighted average contract price of $7.31 per Mcf.

In January 2005, the Company obtained a $5 million note payable. The proceeds from the note were used to pay for the rehedging of a portion of our natural gas sales. The note accrued interest at 5.25% and was scheduled to mature on September 15, 2005. The note was paid in April 2005 with proceeds from the new revolving credit facility.

Linn Energy, LLC (f/k/a Linn Energy Holdings, LLC) was formed in April 2005. Linn Energy, LLC owns 100% of Linn Energy Holdings, LLC (f/k/a Linn Energy, L.L.C.), Linn Operating, Inc., and Chipperco, LLC and has no other operations. Linn Energy Holdings, LLC was formed as Linn Energy, L.L.C. on March 14, 2003. Its wholly owned subsidiaries were Linn Operating, LLC and Chipperco, LLC. On April 6, 2005, Linn Energy, LLC was formed as a holding company. As a result of a holding company reorganization on April 8, 2005, Linn Energy Holdings, LLC became

F-30

the wholly owned subsidiary of Linn Energy, LLC, with Linn Operating, LLC and Chipperco, LLC remaining as wholly owned subsidiaries of Linn Energy Holdings, LLC. Effective May 31, 2005, all of Linn Energy Holdings, LLC's ownership interests in Linn Operating, LLC and Chipperco, LLC were transferred to Linn Energy, LLC. As a result, each of Linn Energy Holdings, LLC, Linn Operating, LLC and Chipperco, LLC are now wholly owned subsidiaries of Linn Energy, LLC. On June 1, 2005, Linn Operating, LLC was converted into a Subchapter C-corporation. The historical income tax expense was not material to the financial statements. Due to the conversion, an income tax provision of $384,792 was recorded during the nine months ended September 30, 2005.

(17) September 30, 2005 Pro Forma Members' Capital (unaudited)

The pro forma members' capital gives effect to the proposed initial public offering. The Company proposes to sell 11,750,000 units at an assumed price of $20 per unit, for proceeds net of underwriters' fees of $218.6 million. Upon completion of the offering the Company will have 27,812,500 units outstanding. The offering proceeds are expected to be utilized to repay $122 million in debt, redeem $89.9 million in membership interests, and pay offering expenses of $6.7 million, which offering expenses include $1.8 million in one-time bonuses payable upon completion of the offering. The net proceeds from the offering will increase the Company's members' capital account by an aggregate of $123.8 million. As the Company has historically reported losses, the repayment of debt and redemption of membership units could not be paid out of the current year's income. The Company would need to sell 6.77 million and 4.98 million units, respectively, at an assumed price to the public of $20 per unit, in order to repay $122 million in debt and redeem $89.9 million in membership interests, respectively.

The pro forma members' capital does not give effect to the $115.3 million acquisition of Exploration Partners.

F-31

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members
Linn Energy, LLC and Subsidiaries:

We have audited the accompanying statements of operations and cash flows for the year ended December 31, 2002 and for the period from January 1, 2003 through October 31, 2003 (acquisition date) of Waco Properties as defined in Note 1 to the financial statements (Waco Properties). These financial statements are the responsibility of the Waco Properties' management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Waco Properties for the year ended December 31, 2002 and for the period from January 1, 2003 through October 31, 2003 (acquisition date), in conformity with U.S. generally accepted accounting principles.

As discussed in Note 5 to the financial statements, Waco Properties adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in 2003.

/s/ KPMG LLP

Pittsburgh, PA
September 12, 2005

F-32

WACO PROPERTIES

STATEMENTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2002

AND PERIOD FROM JANUARY 1, 2003 THROUGH OCTOBER 31, 2003

		Year Ended December 31, 2002			Period January 1, 2003 through October 31, 2003
Revenues
	Well service income	$	683,466		$	763,133
	Natural gas and oil income		3,778,606			4,704,693
	Other operating income		14,898			25,433

			4,476,970			5,493,259

Operating costs and expenses
	Direct operating costs		2,426,136			2,204,345
	General and administrative		1,046,984			870,213
	Depreciation, depletion and amortization		1,493,960			1,184,358

			4,967,080			4,258,916

Other income (expense)
	Interest expense		(351,951	)		(237,313	)
	(Loss) gain on sale of assets		(63,420	)		48,789
	Loss from equity investment		(144,783	)		(62,917	)

			(560,154	)		(251,441	)

(Loss) income before cumulative effect of change in accounting principle			(1,050,264	)		982,902
Cumulative effect of change in accounting principle (Note 5)			—			(757,398	)

	Net (loss) income	$	(1,050,264	)	$	225,504

The Notes to Financial Statements are an integral part of these statements.

F-33

WACO PROPERTIES

STATEMENTS OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2002

AND PERIOD FROM JANUARY 1, 2003 THROUGH OCTOBER 31, 2003

					Year Ended December 31, 2002			Period January 1, 2003 through October 31, 2003
CASH FLOWS FROM OPERATING ACTIVITIES
	Net (loss) income				$	(1,050,264	)	$	225,504
	Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities:
		Cumulative effect of change in accounting principle				—			757,398
		Depreciation, depletion and amortization				1,493,960			1,184,358
		Loss (gain) on sale of assets				63,420			(48,789	)
		Loss from equity investment				144,783			62,917
		Accretion of asset retirement obligation				—			35,154
		Changes in assets and liabilities:
			(Increase) in trade accounts receivable			(272,224	)		(121,288	)
			Decrease in other assets			9,426			7,719
			Increase (decrease) in trade accounts payable and accrued expenses			30,372			(76,023	)
			(Decrease) in revenue distribution payable			(459,706	)		(200,991	)

				Net cash (used in) provided by operating activities		(40,233	)		1,825,959

CASH FLOWS FROM INVESTING ACTIVITIES
	Additional equity investment					(105,151	)		(12,321	)
	Increase in acquisition payable					—			12,308,924
	Proceeds from sale of property and equipment					—			300,000
	Expenditures for property and equipment					(27,938	)		(98,852	)
	Expenditures for natural gas and oil properties					(1,346,622	)		(1,617,912	)

				Net cash (used in) provided by investing activities		(1,479,711	)		10,879,839

CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds (payments) from bank line of credit, net					160,209			(1,766,120	)
	Borrowings from affiliates					1,424,366			143,486
	Repayments of long-term notes payable					(528,279	)		(792,304	)

				Net cash provided by (used in) financing activities		1,056,296			(2,414,938	)

				Net (decrease) increase in cash		(463,648	)		10,290,860
Cash
	Beginning					1,005,690			542,042

	Ending				$	542,042		$	10,832,902

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
	Cash paid during the period for interest				$	351,951		$	237,313

SUPPLEMENTAL DISCLOSURES OF NONCASH FLOW INFORMATION
	Increase in natural gas and oil properties for asset retirement obligations				$	—		$	365,452

	Increase in asset retirement obligation payable				$	—		$	900,744

The Notes to Financial Statements are an integral part of these statements.

F-34

WACO PROPERTIES

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2002 AND OCTOBER 31, 2003

NOTE 1. NATURE OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Nature of Business and Basis of Presentation

Effective October 31, 2003, Waco Oil and Gas, Inc. (the Company) sold essentially all of its natural gas and oil properties (the Waco Properties) to Linn Energy, L.L.C. The accompanying financial statements present the results of operations and cash flows of Waco Properties, which was deemed to be the predecessor entity to Linn Energy, L.L.C. The financial statements are presented under the requirements of Item 3-02 of the Securities and Exchange Commission Regulation S-X. The accompanying financial statements do not include operations of the Company that did not pertain to the assets acquired by Linn Energy, L.L.C. The excluded balances related to the Company's car wash, rock quarry, undeveloped mineral interests, drilling, real estate investment and paving operations. For the purpose of allocating property taxes and business franchise taxes to Waco Properties, the Company calculated the expenses by multiplying the applicable tax rates to the property and equity included in the Waco Properties' financial statements. All other revenues and expenses were specifically identified. Changes in stockholder's equity have been reflected as borrowings from these affiliated entities for purposes of presenting the statement of cash flows.

The Waco Properties' operations consist of the exploration, development and production of natural gas and oil reserves located primarily in West Virginia. Waco Properties also performs well services for established fees on natural gas and oil properties located in West Virginia.

The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred.

Use of Estimates

Management of the Company has made a number of estimates and assumptions relating to the reporting of revenue and expenses and disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. The estimates which are particularly significant to the financial statements include estimates of natural gas and oil reserves, future cash flows from natural gas and oil properties, and depreciation, depletion and amortization.

Cash Equivalents

For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.

Trade Accounts Receivable

Trade account receivables are recorded at the invoiced amount and do not bear interest. The Company routinely assesses the financial strength of its customers, and bad debts are recorded based on an account-by-account review after all means of collection have been exhausted and the potential recovery is considered remote. The Company does not have any off-balance-sheet credit exposure related to its customers.

Natural Gas and Oil Properties

The Company accounts for natural gas and oil properties by the successful efforts method. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped

F-35

property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depreciation and depletion of producing natural gas and oil properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Statement of Financial Accounting Standards (SFAS) No. 19 requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described in Note 10, proved reserves are estimated by an independent petroleum engineer, Schlumberger Data and Consulting Services, and are subject to future revisions based on availability of additional information. As described in Note 5, the Company follows SFAS No. 143. Under SFAS No. 143, estimated asset retirement costs are generally recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by the Company's engineers using existing regulatory requirements and anticipated future inflation rates.

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

Natural gas and oil properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Company assesses the impairment of capitalized costs of proved natural gas and oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2002 and October 31, 2003, the estimated undiscounted future cash flows for the Company's proved natural gas and oil properties exceeded the net capitalized costs, and no impairment was required to be recognized.

Unproved properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Property acquisition costs are capitalized when incurred.

Natural Gas and Oil Reserve Quantities

Reserves and their relation to estimated future net cash flows impact the Company's depletion and impairment calculations. As a result, adjustments to depletion and impairment

F-36

are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with Securities and Exchange Commission guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of the Company's reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Property, Plant and Equipment

Property, plant and equipment other than natural gas and oil properties is carried at cost. Depreciation is provided using the straight-line and accelerated methods over the estimated useful lives of the related assets.

Building and leasehold improvements		15-30 years
Furniture and equipment		5-10 years
Vehicles		5 years

Revenue Recognition

Sales of natural gas and oil are recognized when natural gas and oil have been delivered to a 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 price is fixed or determinable. Natural gas and oil are sold by the Company on a monthly basis. Virtually all of the Company's contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and oil, and prevailing supply and demand conditions, so that the prices of the natural gas and oil fluctuate to remain competitive with other available natural gas and oil supplies. As a result, the Company's revenues from the sale of natural gas and oil will suffer if market prices

F-37

decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas and oil contracts are customary in the industry.

Income Taxes

The Company has elected to be taxed as a Subchapter S corporation under the Internal Revenue Code. The taxable income or loss of the Company is included in the income tax return of its shareholder, and there would be no income tax expense in the accompanying financial statements if it was determined on a separate income tax return basis.

Investment

Waco Properties has a 33% interest in Big Creek Pipeline, a partnership that is primarily involved in the transportation of natural gas. The investment is accounted for using the equity method; therefore, Waco Properties' portion of income or loss is recognized in the accompanying statements of operations.

Revenue Distribution

Revenue distribution represents amounts owed to other working interests and royalty interests as of December 31, 2002 and October 31, 2003.

NOTE 2. BUSINESS AND CREDIT CONCENTRATIONS

Financial instruments which potentially subject the Company to credit risk consist of the following:

Cash

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

Trade Accounts Receivable

The Company sells a majority of its natural gas and oil production and provides well maintenance services to customers who are also engaged in natural gas and oil production. This concentration of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company performs ongoing credit evaluations of its customers and generally does not require collateral.

F-38

Major Customers

The Company's largest customer is a natural gas producer and supplier located within the Appalachian region. For the year ended December 31, 2002, the Company's largest customer represented 45.8% of the Company's sales. The Company's largest customer represented approximately 50.3% of the Company's sales for the period January 1, 2003 through October 31, 2003.

NOTE 3. DEFINED CONTRIBUTION PLAN

The Company has instituted a defined contribution plan under Section 401(k) of the Internal Revenue Code of 1986. Employees may contribute up to 15% of their earnings to the plan with a maximum of $11,000 per year. The plan is available to all full-time employees who have attained the age of 18 and have one year of service. Total employer contributions were $58,405 and $37,104 for the year ended December 31, 2002 and the period January 1, 2003 through October 31, 2003, respectively.

NOTE 4. CONTINGENCIES

The Company is a defendant in various legal actions arising in the ordinary course of its business. In the opinion of the Company's management, these suits should not result in judgments which in the aggregate would have a material adverse effect on the accompanying financial statements.

NOTE 5. ASSET RETIREMENT OBLIGATION

In June 2001, the Financial Accounting Standard Board issued SFAS No. 143, Accounting for Asset Retirement Obligations, that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset's useful life. The asset retirement obligations recorded by the Company relate to the plugging and abandonment of natural gas and oil wells. Additional retirement obligations increase the liability associated with new natural gas and oil wells and other facilities as these obligations are incurred.

The Company adopted SFAS No. 143 on January 1, 2003 and recorded an asset of $450,117 and a related liability of $992,593 (using a 4.25% discount rate) and a cumulative effect of change in accounting principle on prior years of $757,398. During 2003 the liability increased $35,154 due to the accretion of the discount of the liability and $14,108 for the additional wells drilled during the period.

NOTE 6. RELATED PARTY TRANSACTIONS

The Company purchased a portion of the gathering pipelines used for the Company's wells from a vendor owned by the stockholder of the Company. For the year ended December 31, 2002 and the period January 1, 2003 through October 31, 2003, the Company paid the related party approximately $24,000 and $19,000, respectively.

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NOTE 7. COSTS INCURRED IN NATURAL GAS AND OIL PROPERTY ACQUISITION AND DEVELOPMENT ACTIVITIES

Costs incurred by the Company in natural gas and oil property acquisition and development are presented below:

	Year Ended December 31, 2002		Period January 1, 2003 through October 31, 2003
Property acquisition costs, proved	$	—	$	—
Development costs		1,346,622		1,617,912
Company's share of equity method investee's costs of property acquisition, exploration and development		105,151		12,321

The proved reserves attributable to the development costs in the above table were 1,295,125 and 1,691,553 Mcfe for year ended December 31, 2002 and the period January 1, 2003 through October 31, 2003, respectively (amounts unaudited). The above development costs incurred in 2002 and 2003 were incurred to develop proved undeveloped properties from the prior period-end.

NOTE 8. NATURAL GAS AND OIL CAPITALIZED COSTS

Aggregate capitalized costs for the Company related to natural gas and oil production activities with applicable accumulated depreciation, depletion, and amortization are presented below:

		Year Ended December 31, 2002		Period January 1, 2003 through October 31, 2003
Proved natural gas and oil properties		$	24,873,665	$	26,725,087
Unproved natural gas and oil properties			—		—

			24,873,665		26,725,087
Less accumulated depreciation, depletion, and amortization			12,044,981		13,173,276

	Net capitalized costs	$	12,828,684	$	13,551,811

Company's share of equity method investee's net capitalized costs		$	168,373	$	117,777

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NOTE 9. RESULTS OF NATURAL GAS AND OIL PRODUCING ACTIVITES

The results of operations for natural gas and oil producing activities (excluding corporate overhead and interest costs) are presented below:

			Year Ended December 31, 2002			Period January 1, 2003 through October 31, 2003
Natural gas and oil sales			$	3,778,606		$	4,704,693
Expenses:
	Production costs			2,426,136			2,204,345
	Depreciation, depletion and amortization			1,311,908			1,092,874

		Total expenses		3,738,044			3,297,219

		Results of operations for natural gas and oil producing activities (excluding corporate overhead and interest costs)	$	40,562		$	1,407,474

		Company's share of equity method investee's results of operations for producing activities	$	(144,783	)	$	(62,917	)

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and production taxes. In addition, production costs include administrative expenses applicable to support equipment associated with these activities. Depreciation, depletion, and amortization expense includes those costs associated with capitalized acquisition and development costs.

There is no provision for income taxes because the Company is a nontaxable entity.

NOTE 10. NET PROVED NATURAL GAS AND OIL RESERVES (UNAUDITED)

The proved reserves of natural gas and oil of the Company have been estimated by an independent petroleum engineer, Schlumberger Data and Consulting Services, at December 31, 2002 and October 31, 2003. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices. An

F-41

analysis of the change in estimated quantities of natural gas and oil reserves, all of which are located within the United States, is shown below:

		Year Ended December 31, 2002		Period January 1, 2003 through October 31, 2003
		(Mcfe)
Proved developed and undeveloped reserves:
	Beginning of period	40,723,700		42,390,310
	Revisions of previous estimates	2,861,880		9,463
	Production	(1,195,270	)	(919,263	)

	End of period	42,390,310		41,480,510

Proved developed reserves:
	Beginning of period	22,965,240		24,099,110

	End of period	24,099,110		23,817,840

For the year ended December 31, 2002, the revisions to previous estimates of 2,861,880 Mcfe were due primarily to the increase in natural gas prices from $2.56/MMBtu to $4.99/MMBtu and in oil prices from $19.36/Bbl to $30.56/Bbl. These price increases had the effect of increasing the number of economic total proved wells from 420 to 440 and increasing the economic life of some wells. For the period January 1, 2003 through October 31, 2003, the revisions to previous estimates of 9,463 Mcfe were due primarily to the maintenance of the maximum fifty-year economic reserve life.

The above table includes changes in estimated quantities of oil reserves shown in Mcf equivalents at a rate of six barrels per Mcf. Net oil production included above represents less than 1% of total production in 2002 and 2003.

NOTE 11. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN RELATING TO PROVED RESERVES (UNAUDITED)

Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying year-end prices relating to the Company's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation

F-42

of existing economic conditions. There are no future income tax expenses because the Company is a nontaxable entity.

		Year Ended December 31, 2002			Period January 1, 2003 through October 31, 2003
		(in thousands)
Future estimated revenues		$	240,380		$	212,969
Future estimated production costs			(38,362	)		(36,354	)
Future estimated development costs			(18,613	)		(18,361	)

	Future net cash flows		183,405			158,254
10% annual discount for estimated timing of cash flows			(123,478	)		(106,174	)

	Standardized measure of discounted future estimated net cash flows	$	59,927		$	52,080

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows (in thousands):

	Year Ended December 31, 2002			Period January 1, 2003 through October 31, 2003
Sales of natural gas and oil production, net of production costs	$	(1,352	)	$	(2,500	)
Changes in estimated future development costs		996			(252	)
Net changes in prices and production costs		90,417			(24,073	)
Development costs incurred during the period		1,347			1,618
Revisions of previous quantity estimates		7,535			56
Less change in discount		(63,298	)		17,304

	$	35,645		$	(7,847	)

It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many subjective determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand, and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

NOTE 12. SALE OF NATURAL GAS AND OIL PROPERTIES

On October 31, 2003, the Company sold substantially all of its natural gas and oil properties to Linn Energy, L.L.C. (Linn) for approximately $31 million. In October 2003, the Company received two payments from Linn totaling approximately $12.3 million. The payments were a deposit for the final purchase price and were recorded as a liability as of October 31, 2003.

F-43

INDEPENDENT AUDITORS' REPORT

To the Members
Linn Energy, LLC

We have audited the accompanying statements of revenues and direct operating expenses of the natural gas and oil property acquired from Emax Oil Company for the period January 1, 2003 through May 31, 2003 and the year ended December 31, 2002. These financial statements are the responsibility of Linn Energy, LLC's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements of revenue and direct operating expenses are free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits of the statements of revenues and direct operating expenses provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the natural gas and oil property and are not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the natural gas and oil property acquired from Emax Oil Company as described in Note 1 for the period January 1, 2003 through May 31, 2003 and the year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

/s/ Toothman Rice, PLLC

Fairmont, West Virginia
August 1, 2005

F-44

LINN ENERGY, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM EMAX OIL COMPANY

FOR THE PERIOD JANUARY 1, 2003 THROUGH MAY 31, 2003
AND
FOR THE YEAR ENDED DECEMBER 31, 2002

	2003		2002
Revenues — natural gas and oil sales	$	387,001	$	552,859
Direct operating expenses		16,552		155,194

Excess of revenues over direct operating expenses	$	370,449	$	397,665

See accompanying notes to statements of revenues and direct operating expenses.

F-45

LINN ENERGY, LLC

(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM EMAX OIL COMPANY)

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD JANUARY 1, 2003 THROUGH MAY 31, 2003
AND FOR THE YEAR ENDED DECEMBER 31, 2002

NOTE 1. BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct operating expenses of the natural gas and oil property (the Property) acquired from Emax Oil Company (Emax) for the period January 1, 2003 through May 31, 2003 and the year ended December 31, 2002. The property was purchased by Linn Energy, LLC (the Company) on May 30, 2003, for approximately $3.1 million. The Property consists of royalty and working interests.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by Emax are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. Any direct operating expenses would be recognized on the accrual basis and would consist of monthly operator overhead costs and other direct costs of operating the Property. Direct operating expenses would include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the natural gas and oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statements of revenues and direct operating expenses of Emax's interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

F-46

NOTE 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

The following reserve estimates present the Company's estimate of the proven natural gas and oil reserves and net cash flow of the Property which is a United States property. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing natural gas and oil properties. Accordingly, the estimates are expected to change as future information becomes available.

(a): Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves of the Property.

			Natural Gas (Mcfe)
Proved developed and undeveloped reserves:
	January 1, 2002		5,439,569
		Production	(199,055	)

	December 31, 2002		5,240,514
		Production	(64,486	)

	May 31, 2003		5,176,028

Proved developed reserves:
	May 31, 2003		3,039,079

(b): Standardized Measure of Discounted Future Net Cash Flows Relating to Natural Gas and Oil Reserves

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standards No. 69.

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the natural gas and oil reserves of the Property. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

F-47

reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

	2003			2002
Future cash inflows	$	16,004		$	15,145
Future production costs		(2,503	)		(2,272	)
Future development and abandonment cost		(42	)		(42	)

Future net cash flows		13,459			12,831
10% annual discount for estimated timing of cash flows		(8,034	)		(7,291	)

Standardized measure of discounted future net cash flows	$	5,425		$	5,540

Changes in the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

	2003			2002
Beginning of period	$	5,540		$	3,194
Sales of natural gas and oil produced, net of production expenses		(370	)		(398	)
Changes in prices and production costs		998			5,832
Accretion of discount		(743	)		(3,088	)

End of period	$	5,425		$	5,540

Estimates of economically recoverable natural gas and oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of natural gas and oil may differ materially from the amounts estimated.

F-48

INDEPENDENT AUDITORS' REPORT

To the Members
Linn Energy, LLC

We have audited the accompanying statement of revenues and direct operating expenses of the natural gas and oil property acquired from Lenape Resources, Inc. for the period April 1, 2003 through July 31, 2003. This financial statement is the responsibility of Lenape Resources, Inc.'s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of revenues and direct operating expenses is free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit of the statement of revenues and direct operating expenses provides a reasonable basis for our opinion.

The accompanying statement of revenues and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. It excludes material expenses, described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the natural gas and oil property and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statement of revenues and direct operating expenses referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the natural gas and oil property acquired from Lenape Resources, Inc. as described in Note 1 for the period April 1, 2003 through July 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

/s/ Toothman Rice, PLLC
Fairmont, West Virginia
April 27, 2005

F-49

LINN ENERGY, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM LENAPE RESOURCES, INC.

FOR THE PERIOD APRIL 1, 2003 THROUGH JULY 31, 2003

Revenues-natural gas and oil sales	$	148,944
Direct operating expenses		95,352

Excess of revenues over direct operating expenses	$	53,592

See accompanying notes to statement of revenues and direct operating expenses.

F-50

LINN ENERGY, LLC
(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM LENAPE RESOURCES, INC.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE PERIOD APRIL 1, 2003 THROUGH JULY 31, 2003

(1) Basis of Presentation

The accompanying financial statement presents the revenues and direct operating expenses of the natural gas and oil property (the Property) acquired from Lenape Resources, Inc. (Lenape) for the period April 1, 2003 through July 31, 2003. The Property was purchased by Linn Energy, LLC (the Company) on August 1, 2003, for approximately $2.0 million. The Property consists of royalty and working interests.

The accompanying statement of revenues and direct operating expenses of the Property does not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by Lenape are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statement of revenues and direct operating expenses are recognized on the entitlement method. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the natural gas and oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploitation expenditures related to the Property were insignificant in the relevant period. Accordingly, the historical statement of revenues and direct operating expenses of Lenape's interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of a financial statement in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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(2) Supplemental Financial Information for Natural Gas and Oil Producing Activities (Unaudited)

(a): Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves of the Property. Barrels (bbls) of oil have been converted to natural gas quantities (mcfe) using a conversion factor of 6.

			Natural gas (Mcfe)
Proved developed and undeveloped reserves:
	March 31, 2003		2,265,212
		Production	(48,242	)

	July 31, 2003		2,216,970

Proved developed reserves:
	July 31, 2003		2,156,355

(b): Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is a disclosure requirement under Statement of Financial Accounting Standards No. 69.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for natural gas and oil, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

F-52

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

Future cash inflows	$	10,035
Future production costs		(1,505	)
Future development and abandonment cost		(76	)

Future net cash flows		8,454
10% annual discount for estimated timing of cash flows		(4,804	)

Standardized measure of discounted future net cash flows	$	3,650

Changes in the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

Beginning of period	$	4,006
Sales of natural gas and oil produced, net of production expenses		(54	)
Changes in prices and production costs		(658	)
Accretion of discount		356

End of period	$	3,650

F-53

INDEPENDENT AUDITORS' REPORT

To the Members
Linn Energy, LLC

We have audited the accompanying statements of revenues and direct operating expenses of the natural gas and oil property acquired from Cabot Oil & Gas Corporation for the period January 1, 2003 through September 30, 2003 and year ended December 31, 2002. These financial statements are the responsibility of Cabot Oil & Gas Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the natural gas and oil properties and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the natural gas and oil property acquired from Cabot Oil & Gas Corporation as described in Note 1 for the periods January 1, 2003 through September 30, 2003 and year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

/s/ Toothman Rice, PLLC
Fairmont, West Virginia
August 1, 2005

F-54

LINN ENERGY, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM CABOT OIL & GAS CORPORATION

FOR THE PERIOD JANUARY 1, 2003 THROUGH SEPTEMBER 30, 2003
AND
FOR THE YEAR ENDED DECEMBER 31, 2002

	2003		2002
Revenues — natural gas and oil sales	$	3,229,723	$	3,065,287
Direct operating expenses		570,528		609,368

Excess of revenues over direct operating expenses	$	2,659,195	$	2,455,919

See accompanying notes to statements of revenues and direct operating expenses.

F-55

LINN ENERGY, LLC

(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM
CABOT OIL & GAS CORPORATION)

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIOD JANUARY 1, 2003 THROUGH SEPTEMBER 30, 2003
AND FOR THE YEAR ENDED DECEMBER 31, 2002

NOTE 1. BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct operating expenses of the natural gas and oil property (the Property) acquired from Cabot Oil & Gas Corporation (Cabot) for the period January 1, 2003 through September 30, 2003 and year ended December 31, 2002. The property was purchased by Linn Energy, LLC (the Company) on September 30, 2003, for approximately $15.5 million. The Property consists of royalty and working interests.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by Cabot are not necessarily indicative of the costs to be incurred by the Company.

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the natural gas and oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a much larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statements of revenues and direct operating expenses of Cabot's interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

F-56

NOTE 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

(a): Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves of the Property.

			Natural Gas (Mcfe)
Proved developed and undeveloped reserves:
	January 1, 2002		15,346,157
		Production	(901,582	)

	December 31, 2002		14,444,575
		Production	(578,072	)

	September 30, 2003		13,866,503

Proved developed reserves:
	September 30, 2003		13,866,503

(b): Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves (Standardized Measure) is a disclosure require-ment under Statement of Financial Accounting Standards No. 69.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for natural gas and oil, estimated future production of proved

F-57

reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands) for the twelve month period beginning October 1, 2003 through September 30, 2004:

	2003			2002
Future cash inflows	$	70,858		$	70,490
Future production costs		(10,629	)		(10,573	)
Future development and abandonment cost		(67	)		(67	)

Future net cash flows		60,162			59,850
10% annual discount for estimated timing of cash flows		(34,186	)		(34,008	)

Standardized measure of discounted future net cash flows	$	25,976		$	25,842

Changes in the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

Beginning of period	$	25,842		$	14,896
Sales of natural gas and oil produced, net of production expenses		(2,659	)		(2,456	)
Changes in prices and production costs		2,971			27,806
Accretion of discount		(178	)		(14,404	)

End of period	$	25,976		$	25,842

F-58

INDEPENDENT AUDITORS' REPORT

To the Members
Linn Energy, LLC

We have audited the accompanying statements of revenues and direct operating expenses of the natural gas and oil property acquired from Mountain V Oil & Gas for the periods January 1, 2004 through May 7, 2004 and April 1, 2003 through December 31, 2003. These financial statements are the responsibility of Mountain V's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the statements of revenues and direct operating expenses are free of material misstatement. An audit of a statement of revenues and direct operating expenses includes examining, on a test basis, evidence supporting the amounts and disclosures in that financial statement. An audit of a statement of revenues and direct operating expenses also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits of the statements of revenues and direct operating expenses provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and excludes material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the natural gas and oil property and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the natural gas and oil property acquired from Mountain V Oil & Gas as described in Note 1 for the periods January 1, 2004 through May 7, 2004 and April 1, 2003 through December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

/s/ Toothman Rice, PLLC
Fairmont, West Virginia
August 1, 2005

F-59

LINN ENERGY, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM
MOUNTAIN V OIL & GAS
FOR THE PERIODS JANUARY 1, 2004 THROUGH MAY 7, 2004
AND
APRIL 1, 2003 THROUGH DECEMBER 31, 2003

	2004		2003
Revenues — natural gas and oil sales	$	712,151	$	2,067,735
Direct operating expenses		185,474		581,411

Excess of revenues over direct operating expenses	$	526,677	$	1,486,324

See accompanying notes to statements of revenues and direct operating expenses.

F-60

LINN ENERGY, LLC

(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM
MOUNTAIN V OIL & GAS)

NOTES TO FINANCIAL STATEMENTS

FOR THE PERIODS JANUARY 1, 2004 THROUGH MAY 7, 2004 AND
APRIL 1, 2003 THROUGH DECEMBER 31, 2003

NOTE 1. BASIS OF PRESENTATION

The accompanying financial statements present the revenues and direct operating expenses of the natural gas and oil property (the Property) acquired from Mt. V. Oil & Gas (Mt. V.) for the periods January 1, 2004 through May 7, 2004 and April 1, 2003 through December 31, 2003. The Property was purchased by Linn Energy, LLC (the Company) on May 7, 2004, for approximately $12.4 million. The Property consists of royalty and working interests.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by Mt. V. are not necessarily indicative of the costs to be incurred by the Company.

Historical financial information reflecting financial position, results of operations, and cash flows of the Property is not presented because the purchase price was assigned to the natural gas and oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Property was a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Property acquired, nor would such allocated historical costs be relevant to future operations of the Property. Development and exploration expenditures related to the Property were insignificant in the relevant periods. Accordingly, the historical statements of revenues and direct operating expenses of Mt. V.'s interest in the Property are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

F-61

NOTE 2. SUPPLEMENTAL FINANCIAL INFORMATION FOR NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

(a): Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves of the Property.

			Natural Gas (Mcfe)
Proved developed and undeveloped reserves:
	March 31, 2003		17,654,322
		Production	(431,242	)

	December 31, 2003		17,223,080
		Production	(121,491	)

	May 7, 2004		17,101,589

Proved developed reserves:
	May 7, 2004		10,136,594

(b): Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves

F-62

costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

	2003			2004
Future cash inflows	$	55,549		$	52,111
Future production costs		(8,332	)		(7,817	)
Future development and abandonment cost		(308	)		(308	)

Future net cash flows		46,909			43,986
10% annual discount for estimated timing of cash flows		(26,656	)		(24,994	)

Standardized measure of discounted future net cash flows	$	20,253		$	18,992

Changes in the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

Beginning of period	$	18,992		$	21,326
Sales of natural gas and oil produced, net of production expenses		(527	)		(1,486	)
Changes in prices and production costs		3,049			(3,182	)
Accretion of discount		(1,261	)		2,334

End of period	$	20,253		$	18,992

F-63

INDEPENDENT AUDITORS' REPORT

The Board of Directors
Linn Energy, LLC

We have audited the accompanying statements of revenues and direct operating expenses of the natural gas and oil properties acquired from Westar Energy, Inc., Pentex Energy, Inc., and Seahorse Exploration, Inc. for the nine month periods from April 1, 2003 through December 31, 2003 and January 1, 2004 through September 30, 2004. These financial statements are the responsibility of Westar Energy, Inc.'s, Pentex Energy, Inc.'s and Seahorse Exploration, Inc.'s management. Our responsibility is to express an opinion on these statements based on our audit.

We conducted our audit in accordance with standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of revenues and direct operating expenses are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and excludes material expenses, described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of the natural gas and oil properties, and is not intended to be a complete presentation of revenue and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the natural gas and oil properties acquired by Westar Energy, Inc., Pentex Energy, Inc., and Seahorse Exploration, Inc.'s as described in Note 1 for the nine month periods from April 1, 2003 through December 31, 2003 and January 1, 2004 through September 30, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Elms, Faris & Co., LLP
April 30, 2005
Midland, Texas

F-64

LINN ENERGY, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTIES ACQUIRED FROM WESTAR ENERGY, INC., PENTEX ENERGY, INC.,
AND SEAHORSE EXPLORATION, INC.

NINE MONTH PERIODS ENDED DECEMBER 31, 2003
AND SEPTEMBER 30, 2004

	Nine Month Period Ended December 31, 2003		Nine Month Period Ended September 30, 2004
Revenues — natural gas and oil sales	$	2,340,534	$	2,210,531
Direct operating expenses		493,144		493,652

Revenues in excess of direct operating expenses	$	1,847,390	$	1,716,879

See accompanying notes to the statements of revenues and direct operating expenses.

F-65

LINN ENERGY, LLC
(NATURAL GAS AND OIL PROPERTIES ACQUIRED FROM WESTAR ENERGY, INC., PENTEX ENERGY, INC., AND SEAHORSE EXPLORATION, INC.)

NOTES TO FINANCIAL STATEMENTS

APRIL 1, 2003 THROUGH SEPTEMBER 30, 2004

(1) Significant Accounting Policies

(a): Financial Statement Presentation

On September 30, 2004, Linn Energy, LLC (the "Company") acquired from Westar Energy, Inc., Pentex Energy, Inc., and Seahorse Exploration, Inc. certain interests in natural gas and oil properties (the "Properties") for approximately $14.2 million. The accompanying statements of revenues and direct operating expenses presents the revenues and direct operating expenses for the eighteen months ended September 30, 2004.

The accompanying statements of revenues and direct operating expenses does not include general and administrative expenses, interest income or expense, depreciation, depletion and amortization, or any provision for income taxes since historical expense of this nature incurred by Westar Energy, Inc., Pentex Energy, Inc., and Seahorse Exploration, Inc., are not necessarily indicative of the costs to be incurred by the Company.

Historical financial information reflecting financial position, results of operations, shareholders' equity and cash flows of the Properties is not presented because the purchase price was assigned to the natural gas and oil property interests and related equipment acquired. Other assets acquired and liabilities assumed were not material. In addition, the Properties were a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Properties acquired, nor would such allocated historical costs be relevant to future operations of the Properties. Development and exploitation expenditures related to the Properties were insignificant in the relevant period. Accordingly, the historical statements of revenues and direct operating expenses of Westar Energy, Inc., Pentex Energy, Inc., and Seahorse Exploration, Inc.'s Interest in the Properties are presented in lieu of the financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

(b): Revenues

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the properties which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include all costs associated with the production, marketing and distribution, including all selling and direct overhead other than costs of general corporate activities.

F-66

(c): Accounting Estimates

The preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

(2) Supplementary Financial Information for Natural Gas and Oil Producing Activities (Unaudited)

Reserve information presented below is based on Company prepared reserve estimates, using prices and costs in effect at December 31, 2004. Changes in reserve estimates were derived by adjusting the period-end quantities and values for actual production using historical prices and costs.

Proved reserves are estimated quantities of natural gas and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Natural gas and oil reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing natural gas and oil properties. Accordingly, these reserve estimates are expected to change as additional information becomes available in the future.

F-67

(a): Reserve Quantity Information (as restated)

Below are the net estimated quantities of proved developed and undeveloped reserves and proved developed reserves of the Properties.

			Oil (MBbls)	Gas (MMcf)
Proved developed and undeveloped reserves:
	April 1, 2003		1	21,805
		Production	—	(449	)

	December 31, 2003		1	21,356

	January 1, 2004		1	21,356
		Production	—	(358	)

	September 30, 2004		1	20,998

Proved developed reserves:
	April 1, 2003		1	11,810
		Production	—	(449	)

	December 31, 2003		1	11,361

	January 1, 2004		1	11,361
		Production	—	(358	)

	September 30, 2004		1	11,003

(b): Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the natural gas and oil reserves of the Properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs are based on period-end sales prices for natural gas and oil. Estimated future production of proved reserves and development costs of proved reserves are based on current costs and

F-68

economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

	2003			2004
Future cash inflows	$	36,040		$	164,315
Future production costs		(5,973	)		(32,008	)
Future development costs		(8,840	)		(8,840	)

Future net cash flows		21,227			123,467
10% annual discount for estimated timing of cash flows		(10,990	)		(81,976	)

Standardized measure of discounted future net cash flows	$	10,237		$	41,491

Changes in the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

	2003			2004
Beginning of period	$	11,504		$	10,237
Sales of natural gas and oil produced, net of production expenses		(1,847	)		(1,717	)
Changes in prices and production costs		3,652			33,472
Changes due to revision in quantity estimates		—			3,262

Accretion of discount		(3,072	)		(3,763	)

End of period	$	10,237		$	41,491

Estimates of economically recoverable natural gas and oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of natural gas and oil may differ materially from the amounts estimated.

F-69

REPORT OF INDEPENDENT AUDITORS

To the Members
Linn Energy, LLC

We have audited the accompanying statements of revenues and direct operating expenses of certain natural gas and oil property acquired from EXPLORATION PARTNERS LLC for the years ended December 31, 2004 and 2003. These financial statement are the responsibility of EXPLORATION PARTNERS, LLC management. Our responsibility is to express an opinion on these financial statements based on our audits.

The accompanying statements of revenues and direct operating expenses were prepared for the purpose of submitting the Form S-1 to the Securities and Exchange Commission and exclude material expenses, as described in Note 1 to the financial statements, that would not be comparable to those resulting from the proposed future operations of these natural gas and oil properties and is not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the certain natural gas and oil property to be acquired from EXPLORATION PARTNERS, LLC as described in Note 1 for the years ended December 31, 2004 and 2003, in conformity with accounting principles generally accepted in the United States of America.

/s/ Hantzmon Wiebel LLP
Charlottesville, Virginia
October 27, 2005

F-70

LINN ENERGY, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES—
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM
EXPLORATION PARTNERS, LLC

FOR THE YEARS ENDED DECEMBER 31, 2004 AND 2003
AND NINE MONTH PERIODS ENDED
SEPTEMBER 30, 2005 AND 2004 (UNAUDITED)

		2004		2003		Nine Months Ended September 30, 2005		Nine Months Ended September 30, 2004
						(Unaudited)		(Unaudited)
Revenues — natural gas and oil sales		$	12,703,000	$	11,696,000	$	11,773,000	$	9,326,000
Direct operating expenses			2,769,000	$	2,382,000	$	2,391,000	$	1,957,000

	Excess of revenues over direct operating expenses	$	9,934,000	$	9,314,000	$	9,382,000	$	7,369,000

See accompanying notes to financial statements.

F-71

LINN ENERGY, LLC
(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM EXPLORATION PARTNERS, LLC)

NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2004 AND 2003
AND NINE MONTH PERIODS ENDED SEPTEMBER 30, 2005 AND 2004

(UNAUDITED)

(1) Basis of Presentation

The accompanying financial statements present the revenues and direct operating expenses of certain natural gas and oil properties (the Property) acquired from Exploration Partners, LLC (EPLLC) and affiliated working interest owners by Linn Energy, LLC on October 27, 2005, for approximately $115.0 million. The Property consists of working interests relating to 550 natural gas and oil wells.

The accompanying statements of revenues and direct operating expenses of the Property do not include general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes since historical expenses of this nature incurred by EPLLC are not necessarily indicative of the costs to be incurred in the future.

Revenues in the accompanying statements of revenues and direct operating expenses are recognized on the entitlement method. Revenue is net of royalties, gathering and transportation fees, and compression charges, except those not allowed under the terms of the leases. Internal compression charges netted out of revenue were approximately $300,000 and $200,000 for 2004 and 2003, respectively. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the Property which were charged to the joint account of working interest owners by the operator of the wells. Direct operating expenses include fixed well tending charges, severance and advalorum taxes, and direct lease operating expenses. The internally charged fixed well tending charges amounted to approximately $863,000 and $771,000 in 2004 and 2003, respectively. Internally charged fixed general and administrative expenses not included in the expenses amounted to $479,000 and $428,000 for 2004 and 2003, respectively.

Historical financial information reflecting financial position, results of operations, and cash flows for the Property are not presented because the purchase price is to be assigned to the natural gas and oil property interests and related equipment acquired. Other assets to be acquired and liabilities assumed have not been included in these statements.

F-72

(2) Supplemental Financial Information for Natural Gas and Oil Producing Activities (Unaudited)

(a): Reserve Quantity Information

Below are the net quantities of net proved developed and undeveloped reserves and proved developed reserves of the Property (in thousands).

		Year Ended December 31,
		2004		2003
		(Mcfe)
Proved developed and undeveloped reserves:
	Beginning of period	54,947		54,667
	Revisions of previous estimates	—		—
	Extensions and discoveries	1,131		2,410
	Production	(2,209	)	(2,130	)

	End of period	53,869		54,947

Proved developed reserves:
	Beginning of period	30,859		30,259
	End of period	32,824		30,859

(b): Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil & Gas Reserves

F-73

reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

		2004			2003
Future estimated revenues		$	377,342			382,898
Future estimated production costs			(68,823	)		(68,401	)
Future estimated development cost			(39,403	)		(44,555	)

	Future net cash flows		269,116			269,942
10% annual discount for estimated timing of cash flows			(187,500	)		(191,281	)

	Standardized measure of discounted future net cash flows	$	81,616		$	78,661

Changes in the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows (in thousands):

		Year Ended December 31,
		2004			2003
Beginning of year		$	78,661		$	57,367
Sales of natural gas and oil produced, net of production expenses			(9,934	)		(9,314	)
Changes in future development costs			5,152			(486	)
Changes in prices and production costs			8,658			75,714
Extensions, discoveries and improved recovery less costs			1,058			1,836
Development costs incurred during the period			(5,760	)		(3,420	)
Revisions of previous estimates			—			—
Accretion of discount			3,781			(43,036	)

	End of year	$	81,616		$	78,661

Estimates of economically recoverable gas and oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of gas and oil may differ materially from the amounts estimated.

F-74

LINN ENERGY, LLC

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

The following unaudited pro forma combined balance sheet as of September 30, 2005 and statements of operations for the year ended December 31, 2004 and for the nine months ended September 30, 2005 are derived from our historical consolidated financial statements as set forth elsewhere in this prospectus and from the historical statement of revenues and direct operating expenses of certain natural gas and oil properties acquired from Mountain V Oil & Gas, Inc. (Mountain V), Pentex Energy, Inc. (Pentex) and Exploration Partners, LLC (Exploration Partners) included elsewhere in this prospectus with pro forma adjustments based on assumptions we have deemed appropriate. The unaudited pro forma combined statement of operations gives effect to the acquisition of the Mountain V, Pentex and Exploration Partners properties as if the transactions had occurred on January 1, 2004. The acquisitions from Mountain V, Pentex and Exploration Partners were completed as of May 7, 2004, September 30, 2004 and October 27, 2005, respectively, and accordingly the operating results related to the acquired properties are included in our historical results from those dates. The pro forma combined balance sheet gives effect to the public offering of units (11,750,000 units at an assumed offering price of $20.00 per unit) and the Exploration Partners acquisition as if the offering and acquisition occurred as of September 30, 2005. The transactions and the related adjustments are described in the accompanying notes. In the opinion of management, all adjustments have been made that are necessary to present fairly in accordance with Regulation S-X the pro forma condensed consolidated financial statements.

The following unaudited pro forma combined balance sheet and statements of operations are presented for illustrative purposes only, and do not purport to be indicative of the financial position or results of operations that would actually have occurred if the transactions described had occurred as presented in such statement or that may be obtained the future. In addition, future results may vary significantly from the results reflected in such statements due to factors described in "Risk Factors" included elsewhere in this prospectus. The following unaudited pro forma combined balance sheet and statements of operations should be read in conjunction with our historical consolidated financial statements and the notes thereto and the combined statement of revenues and direct operating expenses of certain natural gas and oil properties acquired from Mountain V, Pentex and Exploration Partners and the notes thereto included elsewhere in this prospectus.

F-75

Unaudited Pro Forma Combined Balance Sheet
September 30, 2005

				Linn Energy			Pro Forma Adjustments		Pro Forma
Assets
Current assets:
	Cash and cash equivalents			$	2,977,390		723,355	(a)	$	3,700,745
	Receivables				8,207,847		—			8,207,847
	Prepaid expenses and other current assets				3,042,070		(2,032,700	)(a)		1,009,370

			Total current assets		14,227,307		(1,309,345	)		12,917,962

Oil and gas properties (successful efforts accounting method)
	Oil and gas properties and related equipment				129,254,857		116,339,853	(b)		245,594,710
		Less accumulated depreciation, depletion, and amortization			8,077,152		—			8,077,152

					121,177,705		116,339,853			237,517,558

Property, plant, and equipment:
	Land				47,500		—			47,500
	Buildings and leasehold improvements				539,729		—			539,729
	Vehicles				935,590		324,025	(b)		1,259,615
	Furniture and equipment				810,734		340,000	(b)		1,150,734

					2,333,553		664,025			2,997,578
	Less accumulated depreciation				367,433		—			367,433

					1,966,120		664,025			2,630,145
Other assets:					6,215,600		—			6,215,600

			Total assets	$	143,586,732		115,694,533			259,281,265

Liabilities and Members' Capital
Current liabilities:
	Current portion of long-term notes payable			$	104,930		—			104,930
	Accounts payable and accrued expenses				6,949,857		(1,309,345	)(a)		5,640,512
	Current portion of natural gas derivatives				22,288,417		—			22,288,417

			Total current liabilities		29,343,204		(1,309,345	)		28,033,859

Long-term liabilities:
	Long-term portion of notes payable				697,191		—			697,191
	Credit facility				138,278,187		115,300,000	(b)		131,578,187
							(122,000,000	)(c)
	Long-term portion of interest rate swaps				855,225		—			855,225
	Asset retirement obligation				4,418,209		1,703,878	(b)		6,122,087
	Long-term portion of natural gas derivatives				21,937,866		—			21,937,866
	Other long term liabilities				201,592		—			201,592

			Total long-term liabilities		166,388,270		(4,996,122	)		161,392,148

			Total liabilities		195,731,474		(6,305,467	)		189,426,007

Members' capital:
	Units				16,023,743		218,550,000 (86,930,000 (3,000,000 (4,870,000	(d) )(e) )(f) )(g)		139,773,743
	Accumulated loss				(68,168,485	)	(1,750,000	)(h)		(69,918,485	)

					(52,144,742	)	122,000,000			69,855,258

			Total liabilities and members' capital	$	143,586,732		115,694,533		$	259,281,265

F-76

Unaudited Pro Forma Combined Statement of Operations
Year Ended December 31, 2004

		Linn Energy, LLC Historical			Mountain V January 1, 2004 through May 7, 2004		Pentex January 1, 2004 through September 30, 2004		Exploration Partners Year Ended December 31, 2004		Pro Forma Adjustments			Pro Forma
Revenues:
	Natural gas and oil revenue	$	21,231,640		$	712,151	$	2,210,531	$	12,703,000	$	—		$	36,857,322
	Realized (loss) on natural gas derivatives		(2,239,506	)		—		—		—		—			(2,239,506	)
	Unrealized (loss) on natural gas derivatives		(8,764,855	)		—		—		—		—			(8,764,855	)
	Natural gas marketing income		520,340			—		—		—		—			520,340
	Other income		160,131			—		—		—		—			160,131

			10,907,750			712,151		2,210,531		12,703,000		—			26,533,432

Expenses:
	Operating expenses		5,459,503			185,474		493,652		2,769,000		—			8,907,629
	Natural gas and marketing expense		481,993			—		—		—		—			481,993
	General and administrative expense		1,583,054			—		—		—		110,968	(i)		1,694,022
	Depreciation, depletion, and amortization		3,749,318			—		—		—		6,655,607	(j)		10,404,925

			11,273,868			185,474		493,652		2,769,000		6,766,575			21,488,569

			(366,118	)		526,677		1,716,879		9,934,000		(6,766,575	)		5,044,863

Other income and (expense)
	Interest income		7,379			—		—		—		—			7,379
	Interest and financing expense		(3,530,360	)		—		—		—		(5,335,313	)(k)		(8,865,673	)
	(Loss) from equity investment		(56,126	)		—		—		—		—			(56,126	)
	(Loss) on sale of assets		(32,563	)		—		—		—		—			(32,563	)

			(3,611,670	)		—		—		—		(5,335,313	)		(8,946,983	)

	Net income (loss)	$	(3,977,788	)	$	526,677	$	1,716,879		9,934,000	$	(12,101,887	)	$	(3,902,120	)

F-77

Unaudited Pro Forma Combined Statements of Operations
Nine Months Ended September 30, 2005

		Linn Energy, LLC Historical			Exploration Partners January 1, 2005 through September 30, 2005		Pro Forma Adjustments			Pro Forma
Revenues:
	Natural gas and oil revenue	$	24,408,270		$	11,773,000	$	—		$	36,181,270
	Realized (loss) on natural gas derivatives		(45,821,646	)		—		—			(45,821,646	)
	Unrealized (loss) on natural gas derivatives		(26,788,755	)		—		—			(26,788,755	)
	Natural gas marketing income		3,087,106			—		—			3,087,106
	Other income		158,418			—		—			158,418

			(44,956,607	)		11,773,000		—			(33,183,607	)

Expenses:
	Operating expenses		4,617,088			2,391,000		—			7,008,088
	Natural gas and marketing expense		3,161,930			—		—			3,161,930
	General and administrative expense		2,309,315			—		54,542	(l)		2,363,857
	Depreciation, depletion, and amortization		3,736,002			—		4,460,112	(m)		8,196,114

			13,824,335			2,391,000		4,514,654			20,729,989

			(58,780,942	)		9,382,000		(4,514,654	)		(53,913,596	)

Other income and (expense)
	Interest income		15,985			—		—			15,985
	Interest and financing expense		(3,282,352	)		—		(3,545,475	)(n)		(6,827,827	)
	(Loss) from equity investment		(16,714	)		—		—			(16,714	)
	Write-off of deferred financing fees		(364,166	)		—		—			(364,166	)
	(Loss) on sale of assets		(43,016	)		—		—			(43,016	)

			(3,690,263	)		—		(3,545,475	)		(7,235,738	)

	Income (loss) before income taxes		(62,471,205	)		9,382,000		(8,060,129	)		(61,149,334	)

	Income tax provision		384,792			—		—			384,792
	Net income (loss)	$	(62,855,997	)	$	9,382,000	$	(8,060,129	)	$	(61,534,126	)

F-78

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

1. Pro Forma Adjustments

The unaudited pro forma combined financial statements have been adjusted to:

a. record funding of payments made for offering costs paid prior to completion of the offering;

b. record purchase price allocation of the Exploration Partners acquisition. The purchase price paid to Exploration Partners was $115.3 million, plus the assumption of $1.7 million for future plugging costs. The purchase price was allocated as follows:

•: $116.3 million to natural gas and oil properties
•: $0.3 million to vehicles
•: $0.3 million to equipment;

c. record $122 million of repayment on indebtness under the credit facility from proceeds of the offering;

d. record proceeds from the offering of 11,750,000 units at $20.00 per unit, net of underwriters' fees of 7%;

e. record the redemption of membership interests of Quantum Energy Partners and non-affiliated investors;

f. record the redemption of membership interests of Michael C. Linn;

g. record the payment of expenses associated with the offering;

h. record the payment of the one-time bonuses to Michael C. Linn and Kolja Rockov for successful completion of the offering. Bonuses will be paid from proceeds of the offering;

i. record accretion expense related to asset retirement obligation on properties acquired from Mountain V, Pentex and Exploration Partners;

j. record incremental depreciation, depletion, and amortization expense, using the units-of-production method, resulting from the acquisition of the Mountain V, Pentex and Exploration Partners properties;

k. record interest expense associated with debt of approximately $141.9 million incurred to fund the purchase prices. The applicable interest rate for the acquisitions was 4.1%;

l. record accretion expense related to asset retirement obligation on properties acquired from Exploration Partners;

m. record incremental depreciation, depletion and amortization expense, using the units-of-production method, resulting from the acquisition of the Exploration Partners properties; and

n. record interest expense associated with debt of $115.3 million incurred to fund the Exploration Partners purchase price. The applicable interest rate for the acquisition was 4.1%.

We did not incur any incremental increase in general and administrative expense as a result of these acquisitions.

F-79

2. Natural Gas and Oil Revenue Disclosures

The following table sets forth certain unaudited pro forma information concerning our proved natural gas and oil reserves for the year ended December 31, 2004, giving effect to the Mountain V, Pentex and Exploration Partners transactions as if they had occurred on January 1, 2004. The natural gas and oil reserves for Mountain V and Pentex are already included in our reserve information as of December 31, 2004. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact:

Net Proved Natural Gas Reserves

		MMcfe
		Linn Energy		Mountain V		Pentex		Exploration Partners		Pro Forma
Proved developed and undeveloped reserves:
	Beginning of year	69,805		17,223		21,356		54,947		163,331
	Revisions of previous estimates	755		—		—		—		755
	Extension and discoveries	16,485		—		—		1,131		17,616
	Acquisition	36,100		(17,101	)	(20,998	)	—		(1,999	)
	Production	(3,385	)	(122	)	(358	)	(2,209	)	(6,074	)

	End of year	119,760		—		—		53,869		173,629

Proved developed reserves:
	Beginning of year	41,760		10,254		11,361		30,859		94,234

	End of year	74,366		—		—		32,824		107,190

Summarized in the following tables is information for our standardized measure of discounted cash flows relating to proved reserves as of December 31, 2003 and 2004, giving effect to the Mountain V, Pentex and Exploration Partners transactions. Future cash flows are computed by applying year-end pricing relating to our proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. The discounted future net cash flows from proved natural gas and oil reserves of Mountain V and Pentex are already included in our information as of December 31, 2004. The information should be viewed only as a form of standardized disclosure concerning possible future cash flows that would result under the assumptions used, but should not be viewed as indicative of fair market value. Reference is made to our financial statements for the fiscal year ended December 31, 2004, and the Statements of Revenues and Direct Operating Expenses of certain natural gas and oil

F-80

properties acquired from Mountain V, Pentex and Exploration Partners included herein, for a discussion of the assumptions used in preparing the information presented.

		December 31, 2003
		Linn Energy			Mountain V			Pentex			Exploration Partners			Pro Forma
Future estimated revenues		$	462,420		$	55,549		$	36,040		$	382,898		$	936,907
Future estimated production costs			(79,798	)		(8,332	)		(5,973	)		(68,401	)		(162,504	)
Future estimated development costs			(24,076	)		(308	)		(8,840	)		(44,555	)		(77,779	)

	Future net cash flows		358,546			46,909			21,227			269,942			696,624
10% annual discount for estimated timing of cash flows			(232,205	)		(26,656	)		(10,990	)		(191,281	)		(461,132	)

	Standardized measure of discounted future estimated net cash flows	$	126,341		$	20,253		$	10,237		$	78,661		$	235,492

		December 31, 2004
		Linn Energy			Exploration Partners			Pro Forma
Future estimated revenues		$	840,126		$	377,342		$	1,217,468
Future estimated production costs			(146,672	)		(68,823	)		(215,495	)
Future estimated development costs			(41,417	)		(39,403	)		(80,820	)

	Future net cash flows		652,037			269,116			921,153
10% annual discount for estimated timing of cash flows			(437,004	)		(187,500	)		(624,504	)

	Standardized measure of discounted future estimated net cash flows	$	215,033		$	81,616		$	296,649

The following table sets forth unaudited pro forma information for the principal sources of changes in discounted future net cash flows from our proved natural gas and oil for the year ended December 31, 2004, and giving effect to the acquisition of the Mountain V, Pentex and Exploration Partners properties.

F-81

The following table sets forth the principal sources of change in discounted future net cash flows (dollars in thousands):

	Linn Energy			Mountain V			Pentex			Exploration Partners		Pro Forma
Standardized measure at beginning of year	$	126,341		$	20,253		$	10,237		78,661		$	235,492
Sales and transfers of natural gas and oil produced, net of production costs		(16,608	)		(1,486	)		(1,717	)	(9,934	)		(29,745	)
Change in estimated future development costs		17,341			—			—		5,152			22,493
Extensions and discussions, net of future production and development costs		80,376			—			—		1,058			81,434
Net changes in prices and production costs		15,008			(2,109	)		33,472		8,658			55,029
Development cost incurred during the period		16,733			—			—		(5,760	)		10,973
Revisions of quantities		3,671			—			3,262		—			6,933
Change in discount		(204,799	)		2,334			(3,763	)	3,781			(202,447	)
Acquisition		176,970			(18,992	)		(41,491	)	—			116,487

Net increase (decrease) in standardized measure		88,692			(20,253	)		(10,237	)	2,955			61,157

Standardized measure at end of year	$	215,033		$	—		$	—		81,616		$	296,649

F-82

APPENDIX A

FORM OF
SECOND AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT
OF
LINN ENERGY, LLC

TABLE OF CONTENTS

ARTICLE I DEFINITIONS
	Section 1.1	Definitions
	Section 1.2	Construction
ARTICLE II ORGANIZATION
	Section 2.1	Formation
	Section 2.2	Name
	Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices
	Section 2.4	Purposes and Business
	Section 2.5	Powers
	Section 2.6	Power of Attorney
	Section 2.7	Term
	Section 2.8	Title to Company Assets
ARTICLE III RIGHTS OF MEMBERS
	Section 3.1	Members
	Section 3.2	Management of Business
	Section 3.3	Outside Activities of the Members
	Section 3.4	Rights of Members
ARTICLE IV CERTIFICATES; RECORD HOLDERS; TRANSFER OF INTERESTS; REDEMPTION OF INTERESTS
	Section 4.1	Certificates
	Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates
	Section 4.3	Record Holders
	Section 4.4	Transfer Generally
	Section 4.5	Registration and Transfer of Member Interests
	Section 4.6	Restrictions on Transfers
	Section 4.7	Citizenship Certificates; Non-citizen Assignees
	Section 4.8	Redemption of Interests of Non-citizen Assignees
ARTICLE V CAPITAL CONTRIBUTIONS AND ISSUANCE OF INTERESTS
	Section 5.1	Redemption or Exchange of the Pre-Initial Offering Interests.
	Section 5.2	Contributions by Initial Members
	Section 5.3	Interest and Withdrawal
	Section 5.4	Capital Accounts
	Section 5.5	Issuances of Additional Company Securities
	Section 5.6	Limitations on Issuance of Additional Company Securities
	Section 5.7	No Preemptive Rights
	Section 5.8	Splits and Combinations
	Section 5.9	Fully Paid and Non-Assessable Nature of Interests
ARTICLE VI ALLOCATIONS AND DISTRIBUTIONS
	Section 6.1	Allocations for Capital Account Purposes
	Section 6.2	Allocations for Tax Purposes
	Section 6.3	Requirement of Distributions; Distributions to Record Holders
	Section 6.4	Distributions of Available Cash.

ARTICLE VII MANAGEMENT AND OPERATION OF BUSINESS
	Section 7.1	Board of Directors
	Section 7.2	Certificate of Formation
	Section 7.3	Restrictions on the Board of Directors' Authority
	Section 7.4	Officers.
	Section 7.5	Outside Activities
	Section 7.6	Loans or Contributions from the Company or Group Members
	Section 7.7	Indemnification
	Section 7.8	Exculpation of Liability of Indemnitees
	Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties
	Section 7.10	Duties of Officers and Directors
	Section 7.11	Purchase or Sale of Company Securities
	Section 7.12	Reliance by Third Parties
ARTICLE VIII BOOKS, RECORDS, ACCOUNTING AND REPORTS
	Section 8.1	Records and Accounting
	Section 8.2	Fiscal Year
	Section 8.3	Reports
ARTICLE IX TAX MATTERS
	Section 9.1	Tax Returns and Information
	Section 9.2	Tax Elections
	Section 9.3	Tax Controversies
	Section 9.4	Withholding
ARTICLE X DISSOLUTION AND LIQUIDATION
	Section 10.1	Dissolution
	Section 10.2	Liquidator
	Section 10.3	Liquidation
	Section 10.4	Cancellation of Certificate of Formation
	Section 10.5	Return of Contributions
	Section 10.6	Waiver of Partition
	Section 10.7	Capital Account Restoration
ARTICLE XI AMENDMENT OF AGREEMENT; MEETINGS OF MEMBERS; RECORD DATE
	Section 11.1	Amendment of Limited Liability Company Agreement
	Section 11.2	Amendment Requirements
	Section 11.3	Unitholder Meetings
	Section 11.4	Notice of Meetings of Members
	Section 11.5	Record Date
	Section 11.6	Adjournment
	Section 11.7	Waiver of Notice; Approval of Meeting
	Section 11.8	Quorum; Required Vote for Member Action; Voting for Directors
	Section 11.9	Conduct of a Meeting; Member Lists
	Section 11.10	Action Without a Meeting
	Section 11.11	Voting and Other Rights
	Section 11.12	Proxies and Voting
	Section 11.13	Notice of Member Business and Nominations

ARTICLE XII MERGER
	Section 12.1	Authority
	Section 12.2	Procedure for Merger or Consolidation
	Section 12.3	Approval by Members of Merger or Consolidation
	Section 12.4	Certificate of Merger
	Section 12.5	Effect of Merger
	Section 12.6	Business Combination Limitations
ARTICLE XIII RIGHT TO ACQUIRE MEMBER INTERESTS
	Section 13.1	Right to Acquire Member Interests
ARTICLE XIV GENERAL PROVISIONS
	Section 14.1	Addresses and Notices
	Section 14.2	Further Action
	Section 14.3	Binding Effect
	Section 14.4	Integration
	Section 14.5	Creditors
	Section 14.6	Waiver
	Section 14.7	Counterparts
	Section 14.8	Applicable Law
	Section 14.9	Invalidity of Provisions
	Section 14.10	Consent of Members

iii

SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY
AGREEMENT OF LINN ENERGY, LLC

This SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF LINN ENERGY, LLC, dated as of , 2006 is entered into by Quantum, Clark Partners, Kings Highway Investment, Wauwinet Energy Partners, Michael C. Linn, Gerald W. Merriam and Roland P. Keddie, together with any other Persons who hereafter become Members in Linn Energy, LLC or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I
DEFINITIONS

Section 1.1 Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

"Acquisition" means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the operating capacity or revenue of the Company Group from the operating capacity or revenue of the Company Group existing immediately prior to such transaction.

"Additional Book Basis" means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided that the amount treated as Additional Book Basis as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceed the remaining Additional Book Basis attributable to all of the Company's Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (ii) to such Book-Down Event).

"Additional Book Basis Derivative Items" means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Company's Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the "Excess Additional Book Basis"), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis

A-1

Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

"Additional Member" means a Member admitted as a Member of the Company pursuant to Section 4.5 and who is shown as such on the books and records of the Company.

"Adjusted Capital Account" means the Capital Account maintained for each Member as of the end of each fiscal year of the Company, (a) increased by any amounts that such Member is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such fiscal year are expected to be made to such Member's Capital Account in respect of the oil and gas properties of the Company, (ii) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Member in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Member in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Member's Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The "Adjusted Capital Account" of a Member in respect of a Common Unit or any other Interest shall be the amount that such Adjusted Capital Account would be if such Common Unit or other Interest were the only interest in the Company held by such Member from and after the date on which such Common Unit or other Interest was first issued.

"Adjusted Property" means any property the Carrying Value of which has been adjusted pursuant to Section 5.4(d)(i) or Section 5.4(d)(ii).

"Affiliate" means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with the Person in question. As used herein, the term "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

"Aggregate Remaining Net Positive Adjustments" means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all Members.

"Agreed Allocation" means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including, without limitation, a Curative Allocation (if appropriate to the context in which the term "Agreed Allocation" is used).

"Agreed Value" of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the Board of Directors. The Board of Directors shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Company in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

A-2

"Agreement" means this Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC, as it may be amended, supplemented or restated from time to time.

"Amended and Restated Limited Liability Company Agreement" means the Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC, dated as of April 6, 2005, as amended through the date of this Agreement.

"Anniversary" has the meaning assigned to such term in Section 11.13(b).

"Applicable Quarter" means a Quarter other than the first Quarter following the Closing Date.

"Associate" means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

"Available Cash" means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of:

(i) all cash and cash equivalents of the Company Group on hand at the end of such Quarter; and

(ii) all additional cash and cash equivalents of the Company Group on hand on the date of determination of Available Cash for such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter,

(b) less the amount of any cash reserves established by the Board of Directors to:

(i) provide for the proper conduct of the business of the Company Group (including reserves for future capital expenditures including drilling and acquisitions and for anticipated future credit needs of the Company Group),

(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or

(iii) provide funds for distributions under Section 6.4 with respect to any one or more of the next four Quarters;

provided that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the Board of Directors so determines.

Notwithstanding the foregoing, "Available Cash" with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

"Board of Directors" has the meaning assigned to such term in Section 7.1(a).

A-3

"Book Basis Derivative Items" means any item of income, deduction, gain, loss, Simulated Depletion, Simulated Gain or Simulated Loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, Simulated Depletion, or gain, loss, Simulated Gain or Simulated Loss with respect to an Adjusted Property).

"Book-Down Event" means an event that triggers a negative adjustment to the Capital Accounts of the Members pursuant to Section 5.4(d).

"Book-Tax Disparity" means, with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Member's share of the Company's Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Member's Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Member's Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

"Book-Up Event" means an event that triggers a positive adjustment to the Capital Accounts of the Members pursuant to Section 5.4(d).

"Business Day" means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

"Capital Account" means the capital account maintained for a Member pursuant to Section 5.4. The "Capital Account" of a Member in respect of a Common Unit or any other Interest shall be the amount that such Capital Account would be if such Common Unit or other Interest were the only interest in the Company held by such Member from and after the date on which such Common Unit or other Interest was first issued.

"Capital Contribution" means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Member contributes to the Company pursuant to this Agreement.

"Carrying Value" means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, depletion (including Simulated Depletion), amortization and cost recovery deductions charged to the Members' Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Company property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(d)(i) and Section 5.4(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Company properties, as deemed appropriate by the Board of Directors.

"Certificate" means a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the Board of Directors, issued by the Company evidencing ownership of one or more Common Units or a certificate, in such form as may be adopted by the Board of Directors, issued by the Company evidencing ownership of one or more other Company Securities.

A-4

"Certificate of Formation" means the Certificate of Formation of the Company filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Formation may be amended, supplemented or restated from time to time.

"Chairman of the Board" has the meaning assigned to such term in Section 7.1.

"Citizenship Certification" means a properly completed certificate in such form as may be specified by the Board of Directors by which a Member certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

"Clark Partners" means Clark Partners I, L.P., a New York limited partnership.

"Closing Date" means the first date on which Common Units are sold by the Company to the Underwriters pursuant to the provisions of the Underwriting Agreement.

"Closing Price" has the meaning assigned to such term in Section 13.1(a).

"Code" means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

"Commission" means the United States Securities and Exchange Commission.

"Common Unit" means a Company Security representing a fractional part of the Interests of all Members, and having the rights and obligations specified with respect to Common Units in this Agreement.

"Company" means Linn Energy, LLC, a Delaware limited liability company, and any successors thereto.

"Company Group" means the Company and any Subsidiary of the Company, treated as a single consolidated entity.

"Company Minimum Gain" means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

"Company Security" means any class or series of equity interest in the Company (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Company), including without limitation, Common Units.

"Conflicts Committee" means a committee of the Board of Directors composed entirely of two or more Independent Directors who are not (a) Officers or employees of the Company or any Subsidiary of the Company or (b) holders of any ownership interest in the Company Group other than Common Units.

"Contributed Property" means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Company. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

"Curative Allocation" means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(x).

"Current Market Price" has the meaning assigned to such term in Section 13.1(a).

A-5

"Delaware Act" means the Delaware Limited Liability Company Act, 6 Del. C. Section 18-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

"Depositary" means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

"DGCL" means the General Corporation Law of the State of Delaware, 8 Del. C. Section 101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

"Director" means a member of the Board of Directors of the Company.

"Economic Risk of Loss" has the meaning set forth in Treasury Regulation Section 1.752-2(a).

"Eligible Citizen" means a Person qualified to own interests in real property in jurisdictions in which any Group Member does business or proposes to do business from time to time, and whose status as a Member does not or would not subject such Group Member to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.

"Exchange Act" means the Securities Exchange Act of 1934, as amended.

"Existing Investors" means (i) Quantum, (ii) Clark Partners, (iii) Kings Highway Investment, (iv) Wauwinet Energy Partners, (v) Michael C. Linn, an individual residing in Pittsburgh, Pennsylvania, (vi) Gerald W. Merriam, an individual residing in Cranberry Township, Pennsylvania, and (vii) Roland P. Keddie, an individual residing in Eight Four, Pennsylvania.

"Final Adjudication" has the meaning assigned to such term in Section 7.7(e).

"Fully Diluted Basis" means, when calculating the number of Outstanding Units for any period, a basis that includes, in addition to the Outstanding Units, all Company Securities and options, rights, warrants and appreciation rights relating to an equity interest in the Company (a) that are convertible into or exercisable or exchangeable for Units that are senior to or pari passu with the Common Units, (b) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (c) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (d) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (i) the number of Units issuable upon such conversion, exercise or exchange and (ii) the number of Units that such consideration would purchase at the Current Market Price.

"Group" means a Person that with or through any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons) or disposing of any Company Securities with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Company Securities.

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"Group Member" means a member of the Company Group.

"Group Member Agreement" means the partnership agreement of any Group Member that is a limited or general partnership, the limited liability company agreement of any Group Member, other than the Company, that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

"Indemnitee" has the meaning assigned to such term in Section 7.7(a).

"Independent Standards" with respect to a Director means a Director who meets the then current independence standards required of directors and established by the Commission and the National Securities Exchange on which the Common Units are listed for trading.

"Initial Common Units" means the Common Units sold in the Initial Offering.

"Initial Members" means the holders of the Pre-Initial Offering Interests (with respect to the Common Units received by them pursuant to Section 5.1) and the Underwriters upon the issuance by the Company of Common Units to the Underwriters as described in Section 5.2 in connection with the Initial Offering.

"Initial Offering" means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

"Initial Unit Price" means (a) with respect to the Common Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Company, as determined by the Board of Directors, in each case adjusted as the Board of Directors determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

"Interest" means the ownership interest of a Member in the Company, which may be evidenced by Common Units or other Company Securities or a combination thereof or interest therein, and includes any and all benefits to which such Member is entitled as provided in this Agreement, together with all obligations of such Member to comply with the terms and provisions of this Agreement.

"Interim Capital Transactions" means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters pursuant to the exercise of the Over-Allotment Option); and (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and (ii) sales or other dispositions of assets as part of normal retirements or replacements.

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"Issue Price" means the price at which a Unit is purchased from the Company, after taking into account any sales commission or underwriting discount charged to the Company.

"Kings Highway Investment" means Kings Highway Investment, LLC, a Connecticut limited liability company.

"Liquidation Date" means the date on which an event giving rise to the dissolution of the Company occurs.

"Liquidator" means one or more Persons selected by the Board of Directors to perform the functions described in Section 10.2 as liquidating trustee of the Company within the meaning of the Delaware Act.

"Member" means, unless the context otherwise requires, each Initial Member, each Substituted Member, and each Additional Member.

"Member Nonrecourse Debt" has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

"Member Nonrecourse Debt Minimum Gain" has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

"Member Nonrecourse Deductions" means any and all items of loss, deduction, expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Member Nonrecourse Debt.

"Merger Agreement" has the meaning assigned to such term in Section 12.1.

"National Securities Exchange" means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute, or the Nasdaq National Market or any successor thereto.

"Net Agreed Value" means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Company upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Member by the Company, the Company's Carrying Value of such property (as adjusted pursuant to Section 5.4(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Member upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

"Net Income" means, for any taxable year, the excess, if any, of the Company's items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Company's items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xi) were not in this Agreement.

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"Net Loss" means, for any taxable year, the excess, if any, of the Company's items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Company's items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xi) were not in this Agreement.

"Net Positive Adjustments" means, with respect to any Member, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Member pursuant to Book-Up Events and Book-Down Events.

"Net Termination Gain" means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

"Net Termination Loss" means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

"Non-citizen Assignee" means a Person whom the Board of Directors has determined does not constitute an Eligible Citizen and as to whose Interest the Board of Directors has become the Substituted Member, pursuant to Section 4.7.

"Nonrecourse Built-in Gain" means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Members pursuant to Section 6.2(d)(i)(A), Section 6.2(d)(ii)(A) and Section 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

"Nonrecourse Deductions" means any and all items of loss, deduction, expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

"Nonrecourse Liability" has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

"Notice of Election to Purchase" has the meaning assigned to such term in Section 13.1(b).

"Officer" has the meaning assigned to such term in Section 7.4(a).

"Operating Companies" means (i) Linn Operating, Inc., a Delaware corporation, (ii) Linn Energy Holdings, LLC, a Delaware limited liability company, (iii) Chipperco, LLC, a Delaware limited liability company, (iv) Mid-Atlantic Well Services, Inc., a Delaware corporation, and (v) any other operating Subsidiaries of the Company and any successors thereto.

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"Opinion of Counsel" means a written opinion of counsel (who may be regular counsel to the Company or any of its Affiliates) acceptable to the Board of Directors.

"Option Closing Date" means the date or dates on which any Common Units are sold by the Company to the Underwriters upon exercise of the Over-Allotment Option.

"Outstanding" means, with respect to Company Securities, all Company Securities that are issued by the Company and reflected as outstanding on the Company's books and records as of the date of determination; provided, however, that no Company Securities held by the Company (other than Company Securities representing Interests held by the Company on behalf of Non-Citizen Assignees) or any other Group Member shall be considered Outstanding.

"Over-Allotment Option" means the over-allotment option granted to the Underwriters by the Company pursuant to the Underwriting Agreement.

"Parity Units" means Common Units and all other Units of any other class or series that have the right (i) to receive distributions of Available Cash pursuant to Section 6.4 in the same order of priority with respect to the participation of Common Units in such distributions or (ii) to participate in allocations of Net Termination Gain pursuant to Section 6.1(c)(i)(B) in the same order of priority with the Common Units, in each case regardless of whether the amounts or value so distributed or allocated on each Parity Unit equals the amount or value so distributed or allocated on each Common Unit. Units whose participation in such (i) distributions of Available Cash and (ii) allocations of Net Termination Gain are subordinate in order of priority to such distributions and allocations on Common Units shall not constitute Parity Units even if such Units are convertible under certain circumstances into Common Units or Parity Units.

"Per Unit Capital Amount" means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person.

"Percentage Interest" means, as of any date of determination (a) as to any Unitholder holding Units, the product obtained by multiplying (i) 100% less the percentage applicable to paragraph (b) by (ii) the quotient obtained by dividing (A) the number of Units held by such Unitholder by (B) the total number of all Outstanding Units, and (b) as to the holders of other Company Securities issued by the Company in accordance with Section 5.5, the percentage established as a part of such issuance.

"Person" means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization or other enterprise (including an employee benefit plan), association, government agency or political subdivision thereof or other entity.

"Pre-Initial Offering Interests" means the membership interests in the Company outstanding prior to the Initial Offering.

"Prime Rate" means the prime rate of interest as quoted from time to time by the Wall Street Journal or another source reasonably selected by the Company.

"Pro Rata" means (a) when modifying Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, and (b) when modifying Members, apportioned among all designated Members in accordance with their relative Percentage Interest.

"Purchase Date" means the date determined by the Board of Directors as the date for purchase of all Outstanding Units of a certain class pursuant to Article XIII.

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"Quantum" means Quantum Energy Partners II, LP, a Delaware limited partnership.

"Quarter" means, unless the context requires otherwise, a fiscal quarter, or, with respect to the first fiscal quarter after the Closing Date, the portion of such fiscal quarter after the Closing Date, of the Company.

"Recapture Income" means any gain recognized by the Company (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Company, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

"Record Date" means the date established by the Company for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Members or entitled to exercise rights in respect of any lawful action of Members or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

"Record Holder" means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Company Securities, the Person in whose name any such other Company Security is registered on the books that the Company has caused to be kept as of the opening of business on such Business Day.

"Redeemable Interests" means any Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.8.

"Registration Statement" means the Registration Statement on Form S-1 (Registration No. 333-125501) as it has been or as it may be amended or supplemented from time to time, filed by the Company with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

"Remaining Net Positive Adjustments" means as of the end of any taxable period, with respect to the Unitholders holding Common Units, the excess of (i) the Net Positive Adjustments of the Unitholders holding Common Units as of the end of such period over (ii) the sum of those Members' Share of Additional Book Basis Derivative Items for each prior taxable period.

"Required Allocations" means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), 6.1(d)(ii), 6.1(d)(iv), 6.1(d)(vii) or 6.1(d)(ix).

"Residual Gain" or "Residual Loss" means any item of gain or loss or Simulated Gain or Simulated Loss, as the case may be, of the Company recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Gain or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or 6.2(d)(ii)(A), respectively, to eliminate Book-Tax Disparities.

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"Securities Act" means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

"Share of Additional Book Basis Derivative Items" means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, with respect to the Unitholders holding Common Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders' Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

"Simulated Basis" means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

"Simulated Depletion" means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property were its adjusted tax basis) and in the manner specified in Treasury Regulation §1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

"Simulated Gain" means the excess of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

"Simulated Loss" means the excess of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

"Solicitation Notice" has the meaning assigned to such term in Section 11.13(c).

"Special Approval" means approval by a majority of the members of the Conflicts Committee.

"Stakeholders' Agreement" means the Stakeholders' Agreement dated as of June 2, 2005, by and among the Company and the Existing Investors.

"Subsidiary" means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

"Substituted Member" means a Person who is admitted as a Member of the Company pursuant to Sections 4.5 or 4.7 in place of and with all rights of a Member and who is shown as a Member on the books and records of the Company.

"Surviving Business Entity" has the meaning assigned to such term in Section 12.2(b).

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"Tax Matters Partner" means the Tax Matters Partner as defined in the Code.

"Trading Day" has the meaning assigned to such term in Section 13.1(a).

"Transfer" has the meaning assigned to such term in Section 4.4.

"Transfer Agent" means such bank, trust company or other Person (including the Company or one of its Affiliates) as shall be appointed from time to time by the Company to act as registrar and transfer agent for the Common Units; provided that if no Transfer Agent is specifically designated for any other Company Securities, the Company shall act in such capacity.

"Underwriter" means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

"Underwriting Agreement" means that certain Underwriting Agreement, dated , 2005, among the Underwriters, the Company and certain other parties, providing for the purchase of Common Units by the Underwriters.

"Unit" means a Company Security that is designated as a "Unit" and shall include Common Units.

"Unit Majority" means at least a majority of the Outstanding Common Units.

"Unitholders" means the holders of Units.

"Unrealized Gain" attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date).

"Unrealized Loss" attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(d)).

"U.S. GAAP" means United States generally accepted accounting principles consistently applied.

"Wauwinet Energy Partners" means Wauwinet Energy Partners, LLC, a Delaware limited liability company.

"Working Capital Borrowings" means borrowings used solely for working capital purposes or to pay distributions to Members made pursuant to a credit facility or other arrangement to the extent such borrowings are required to be reduced to a relatively small amount each year (or for the year in which the Initial Offering is consummated, the 12-month period beginning on the Closing Date) for an economically meaningful period of time.

Section 1.2 Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term "include" or "includes" means includes, without limitation, and "including" means including, without limitation.

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ARTICLE II
ORGANIZATION

Section 2.1 Formation. The Members have previously formed the Company as a limited liability company pursuant to the provisions of the Delaware Act and hereby amend and restate the Amended and Restated Limited Liability Company Agreement in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Members and the administration, dissolution and termination of the Company shall be governed by the Delaware Act. All Interests shall constitute personal property of the owner thereof for all purposes and a Member has no interest in specific Company property.

Section 2.2 Name. The name of the Company shall be Linn Energy, LLC. The Company's business may be conducted under any other name or names, as determined by the Board of Directors. The words "Limited Liability Company," "LLC," or similar words or letters shall be included in the Company's name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The Board of Directors may change the name of the Company at any time and from time to time and shall notify the Members of such change in the next regular communication to the Members.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the Board of Directors, the registered office of the Company in the State of Delaware shall be located at [1209 Orange Street, Wilmington, Delaware 19801,] and the registered agent for service of process on the Company in the State of Delaware at such registered office shall be [The Corporation Trust Company]. The principal office of the Company shall be located at 1700 North Highland Road, Suite 100, Pittsburgh, Pennsylvania 15241 or such other place as the Board of Directors may from time to time designate by notice to the Members. The Company may maintain offices at such other place or places within or outside the State of Delaware as the Board of Directors determines to be necessary or appropriate.

Section 2.4 Purposes and Business. The purpose and nature of the business to be conducted by the Company shall be to (a) serve as a member or stockholder, as the case may be, of the Operating Companies and, in connection therewith, to exercise all the rights and powers conferred upon the Company as a member or stockholder, as the case may be, of such entities, (b) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that the Operating Companies are permitted to engage in or that their subsidiaries are permitted to engage in by their organizational documents or agreements and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements relating to such business activity, (c) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the Board of Directors and that lawfully may be conducted by a limited liability company organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements relating to such business activity; and (d) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the Company shall not engage, directly or indirectly, in any business activity that the Board of Directors determines would cause the Company to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. The Board of

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Directors has no obligation or duty to the Company or the Members to propose or approve, and may decline to propose or approve, the conduct by the Company of any business.

Section 2.5 Powers. The Company shall be empowered to do any and all acts and things necessary and appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Company.

Section 2.6 Power of Attorney. Each Member hereby constitutes and appoints each of the Chief Executive Officer, the President and the Secretary and, if a Liquidator shall have been selected pursuant to Section 10.2, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(a) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices:

(i) all certificates, documents and other instruments (including this Agreement and the Certificate of Formation and all amendments or restatements hereof or thereof) that the Chief Executive Officer, President or Secretary, or the Liquidator, determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Company as a limited liability company in the State of Delaware and in all other jurisdictions in which the Company may conduct business or own property;

(ii) all certificates, documents and other instruments that the Chief Executive Officer, President or Secretary, or the Liquidator, determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement;

(iii) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the Board of Directors or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Company pursuant to the terms of this Agreement;

(iv) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Member pursuant to, or other events described in, Articles IV or X;

(v) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Company Securities issued pursuant to Section 5.5; and

(vi) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Company pursuant to Article XII.

(b) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the Board of Directors or the Liquidator determines to be necessary or appropriate to (i) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Members hereunder or is consistent with the terms of this Agreement or (ii) effectuate the terms or intent of this Agreement; provided, that when required by Section 11.2 or any other provision of this Agreement that establishes a percentage of the Members or of the Members of any class or series

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required to take any action, the Chief Executive Officer, President or Secretary, or the Liquidator, may exercise the power of attorney made in this Section 2.6(b) only after the necessary vote, consent or approval of the Members or of the Members of such class or series, as applicable.

Nothing contained in this Section 2.6 shall be construed as authorizing the Chief Executive Officer, President or Secretary, or the Liquidator, to amend this Agreement except in accordance with Article XI or as may be otherwise expressly provided for in this Agreement.

(c) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Member and the transfer of all or any portion of such Member's Interest and shall extend to such Member's heirs, successors, assigns and personal representatives. Each such Member hereby agrees to be bound by any representation made by the Chief Executive Officer, President or Secretary, or the Liquidator, acting in good faith pursuant to such power of attorney; and each such Member, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the Chief Executive Officer, President or Secretary, or the Liquidator, taken in good faith under such power of attorney. Each Member shall execute and deliver to the Chief Executive Officer, President or Secretary, or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as any of such Officers or the Liquidator, determines to be necessary or appropriate to effectuate this Agreement and the purposes of the Company.

Section 2.7 Term. The Company's existence shall be perpetual, unless and until it is dissolved in accordance with the provisions of Article X. The existence of the Company as a separate legal entity shall continue until the cancellation of the Certificate of Formation as provided in the Delaware Act.

Section 2.8 Title to Company Assets. Title to Company assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Company as an entity, and no Member, Director or Officer, individually or collectively, shall have any ownership interest in such Company assets or any portion thereof. Title to any or all of the Company assets may be held in the name of the Company or one or more nominees, as the Board of Directors may determine. The Company hereby declares and warrants that any Company assets for which record title is held in the name of one or more of its Affiliates or one or more nominees shall be held by such Affiliates or nominees for the use and benefit of the Company in accordance with the provisions of this Agreement; provided, however, that the Board of Directors shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the Board of Directors determines that the expense and difficulty of conveyancing makes transfer of record title to the Company impracticable) to be vested in the Company as soon as reasonably practicable. All Company assets shall be recorded as the property of the Company in its books and records, irrespective of the name in which record title to such Company assets is held.

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ARTICLE III
RIGHTS OF MEMBERS

Section 3.1 Members.

(a) A Person shall be admitted as a Member and shall become bound by the terms of this Agreement if such Person purchases or otherwise lawfully acquires any Interest and becomes the Record Holder of such Interests in accordance with the provisions of Article IV hereof. A Person may become a Record Holder without the consent or approval of any of the Members. A Person may not become a Member without acquiring an Interest. The rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.7 hereof.

(b) The name and mailing address of each Member shall be listed on the books and records of the Company maintained for such purpose by the Company or the Transfer Agent. The Secretary of the Company shall update the books and records of the Company from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Member's Interest shall be represented by a Certificate, as provided in Section 4.1 hereof.

(c) As provided in Section 18-303 of the Delaware Act, the debts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise, shall be solely the debts, obligations and liabilities of the Company. The Members shall have no liability under this Agreement, or for any such debt, obligation or liability of the Company, in their capacity as a Member, except as expressly provided in this Agreement or the Delaware Act.

(d) Members may not be expelled from or removed as Members of the Company. Members shall not have any right to withdraw from the Company; provided, that when a transferee of a Member's Interest becomes a Record Holder of such Interest, such transferring Member shall cease to be a Member with respect to the Interest so transferred.

Section 3.2 Management of Business. No Member, in its capacity as such, shall participate in the operation or management of the Company's business, transact any business in the Company's name or have the power to sign documents for or otherwise bind the Company by reason of being a Member.

Section 3.3 Outside Activities of the Members. Any Member shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Company, including business interests and activities in direct competition with the Company Group. Neither the Company nor any of the other Members shall have any rights by virtue of this Agreement in any business ventures of any Member.

Section 3.4 Rights of Members.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Member shall have the right, for a lawful purpose reasonably related to such Member's Interest as a Member in the Company, upon reasonable written demand containing a concise statement of such purposes and at such Member's own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Company;

(ii) promptly after becoming available, to obtain a copy of the Company's federal, state and local income tax returns for each year;

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(iii) to have furnished to him a current list of the name and last known business, residence or mailing address of each Member;

(iv) to have furnished to him a copy of this Agreement and the Certificate of Formation and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Formation and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Member and that each Member has agreed to contribute in the future, and the date on which each became a Member; and

(vi) to obtain such other information regarding the affairs of the Company as is just and reasonable and consistent with the stated purposes of the written demand.

(b) The Board of Directors may keep confidential from the Members, for such period of time as the Board of Directors determines, (i) any information that the Board of Directors determines to be in the nature of trade secrets or (ii) other information the disclosure of which the Board of Directors determines (A) is not in the best interests of the Company Group, (B) could damage the Company Group or (C) that any Group Member is required by law, by the rules of any National Securities Exchange on which any Company Security is listed for trading, or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Company the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV
CERTIFICATES; RECORD HOLDERS;
TRANSFER OF INTERESTS; REDEMPTION OF INTERESTS

Section 4.1 Certificates. Upon the Company's issuance of Common Units to any Person, the Company shall issue one or more Certificates in the name of such Person evidencing the number of such Units being so issued. In addition, upon the request of any Person owning any other Company Securities other than Common Units, the Company shall issue to such Person one or more Certificates evidencing such other Company Securities. Certificates shall be executed on behalf of the Company by the Chairman of the Board, President or any Vice President and the Secretary or any Assistant Secretary. No Common Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the Board of Directors elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Company. Any or all of the signatures required on the Certificate may be by facsimile. If any Officer or Transfer Agent who shall have signed or whose facsimile signature shall have been placed upon any such Certificate shall have ceased to be such Officer or Transfer Agent before such Certificate is issued by the Company, such Certificate may nevertheless be issued by the Company with the same effect as if such Person were such Officer or Transfer Agent at the date of issue. Certificates shall be consecutively numbered and shall be entered on the books and records of the Transfer Agent as they are issued and shall exhibit the holder's name and number of Units.

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Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates. If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate Officers on behalf of the Company shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Company Securities as the Certificate so surrendered.

(a) The appropriate Officers on behalf of the Company shall execute and deliver, and the Transfer Agent shall countersign a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i): makes proof by affidavit, in form and substance satisfactory to the Company, that a previously issued Certificate has been lost, destroyed or stolen;
(ii): requests the issuance of a new Certificate before the Company has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;
(iii): if requested by the Company, delivers to the Company a bond, in form and substance satisfactory to the Company, with surety or sureties and with fixed or open penalty as the Company may direct to indemnify the Company and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and
(iv): satisfies any other reasonable requirements imposed by the Company.

If a Member fails to notify the Company within a reasonable time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Interests represented by the Certificate is registered before the Company or the Transfer Agent receives such notification, the Member shall be precluded from making any claim against the Company or the Transfer Agent for such transfer or for a new Certificate.

(b) As a condition to the issuance of any new Certificate under this Section 4.2, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Company shall be entitled to recognize the Record Holder as the owner of an Interest and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such Interest on the part of any other Person, regardless of whether the Company shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Interests are listed for trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Interests, as between the Company on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Interest.

Section 4.4 Transfer Generally. The term "transfer," when used in this Agreement with respect to an Interest, shall be deemed to refer to a transaction by which the holder of an Interest assigns such Interest to another Person who is or becomes a Member, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage. No Interest shall be

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transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of an Interest not made in accordance with this Article IV shall be null and void.

Section 4.5 Registration and Transfer of Member Interests.

(a) The Company shall keep or cause to be kept on behalf of the Company a register that, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), will provide for the registration and transfer of Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Company shall not recognize transfers of Certificates evidencing Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate Officers of the Company shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the Record Holder's instructions, one or more new Certificates evidencing the same aggregate number and type of Interests as were evidenced by the Certificate so surrendered.

(b) Except as provided in Section 4.7, the Company shall not recognize any transfer of Interests until the Certificates evidencing such Interests are surrendered for registration of transfer. No charge shall be imposed by the Company for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5(b), the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

(c) By acceptance of the transfer of any Interest in accordance with this Section 4.5 and except as provided in Section 4.7, each transferee of an Interest (including any nominee holder or an agent or representative acquiring such Interests for the account of another Person) (i) shall be admitted to the Company as a Member with respect to the Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Company, with or without execution of this Agreement, (ii) shall be deemed to agree to be bound by the terms of, and shall be deemed to have executed, this Agreement, (iii) shall become the Record Holder of the Interests so transferred, (iv) represents that the transferee has the capacity, power and authority to enter into this Agreement, (v) grants powers of attorney to the Officers of the Company and any Liquidator of the Company and (vi) makes the consents and waivers contained in this Agreement. The transfer of any Interests and the admission of any new Member shall not constitute an amendment to this Agreement.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.6, (iv) with respect to any series of Interests, the provisions of any statement of designations establishing such series, (v) any contractual provision binding on any Member and (vi) provisions of applicable law including the Securities Act, Interests shall be freely transferable to any Person.

Section 4.6 Restrictions on Transfers.

(a) The Company may impose restrictions on the transfer of Interests if it receives an Opinion of Counsel providing that such restrictions are necessary to avoid a significant risk of any Group Member becoming taxable as a corporation or otherwise becoming taxable as an entity for

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federal income tax purposes. The Board of Directors may impose such restrictions by amending this Agreement in accordance with Article XI; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Interests on the principal National Securities Exchange on which such class of Interests is then traded must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Interests of such class. Notwithstanding Section 11.10, such approval may be obtained through a written consent of such holders.

(b) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Interests entered into through the facilities of any National Securities Exchange on which such Interests are listed for trading.

Section 4.7 Citizenship Certificates; Non-citizen Assignees.

(a) If any Group Member is or becomes subject to any federal, state or local law or regulation that the Board of Directors determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Member, the Board of Directors may request any Member to furnish to the Company, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Member is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the Company may request. If a Member fails to furnish to the Company, within the aforementioned 30-day period, such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the Board of Directors determines that a Member is not an Eligible Citizen, the Interests owned by such Member shall be subject to redemption in accordance with the provisions of Section 4.8. In addition, the Board of Directors may require that the status of any such Member be changed to that of a Non-citizen Assignee and, thereupon, the Company shall be substituted for such Non-citizen Assignee as the Member in respect of the Non-citizen Assignee's Interests.

(b) The Company shall, in exercising voting rights in respect of Interests held by the Company on behalf of Non-citizen Assignees, distribute the votes in the same ratios or for the same candidates for election as Directors as the votes of Members in respect of Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter or election.

(c) Upon dissolution of the Company, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 10.3, but shall be entitled to the cash equivalent thereof, and the Company shall provide cash in exchange for an assignment of the Non-citizen Assignee's share of any distribution in kind. Such payment and assignment shall be treated for Company purposes as a purchase by the Company from the Non-citizen Assignee of his Member Interest (representing his right to receive his share of such distribution in kind).

(d) At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the Board of Directors, request that, with respect to any Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.8, such Non-citizen Assignee be admitted as a Member, and upon approval of the Board of Directors, such Non-citizen Assignee shall be admitted as a Member and shall no longer constitute a

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Non-citizen Assignee and the Company shall cease to be deemed to be the Member in respect of such Interests.

Section 4.8 Redemption of Interests of Non-citizen Assignees.

(a) If at any time a Member fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.7(a), or, if upon receipt of such Citizenship Certification or other information the Board of Directors determines, with the advice of counsel, that a Member is not an Eligible Citizen, the Company may, unless the Member establishes to the satisfaction of the Board of Directors that such Member is an Eligible Citizen or has transferred his Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the Board of Directors prior to the date fixed for redemption as provided below, redeem the Interest of such Member as follows:

(i) The Board of Directors shall, not later than the 30^th day before the date fixed for redemption, give notice of redemption to the Member, at his last address designated on the records of the Company or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Member would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Interests of the class to be so redeemed multiplied by the number of Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the Board of Directors, in cash or by delivery of a promissory note of the Company in the principal amount of the redemption price, bearing interest at the Prime Rate annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) Upon surrender by or on behalf of the Member, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Member or his duly authorized representative shall be entitled to receive the payment therefor.

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Member Interests.

(b) The provisions of this Section 4.8 shall also be applicable to Interests held by a Member as nominee of a Person determined to be other than an Eligible Citizen.

(c) Nothing in this Section 4.8 shall prevent the recipient of a notice of redemption from transferring his Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the Board of Directors shall withdraw the notice of redemption, provided the transferee of such Interest certifies to the satisfaction of the Board of Directors in a Citizenship Certification that he is an Eligible Citizen. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

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ARTICLE V
CAPITAL CONTRIBUTIONS AND ISSUANCE OF INTERESTS

Section 5.1 Redemption or Exchange of the Pre-Initial Offering Interests. On the Closing Date all Pre-Initial Offering Interests in the Company shall be exchanged for Common Units as set forth on Exhibit B hereto.

Section 5.2 Contributions by Initial Members.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Company cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In exchange for such Capital Contributions by the Underwriters, the Company shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Company by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(b) Upon the exercise of the Over-Allotment Option and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Company cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Company shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contributions to the Company by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit. Upon receipt by the Company of the Capital Contributions from the Underwriters as provided in this Section 5.2(b), the Company shall use such cash to redeem from Quantum, Clark Partners, Kings Highway Investment and Wauwinet Energy Partners, on a pro rata basis, that number of Common Units held by them equal to the number of Common Units issued to the Underwriters as provided in this Section 5.2(b).

(c) No Member Interests will be issued or issuable as of or at the Closing Date other than (i) the [ ] Common Units issuable pursuant to Section 5.2(a) to the Underwriters, (ii) the "Option Units," as such term is used in the Underwriting Agreement, in an aggregate number up to [ ] Common Units issuable upon exercise of the Over-Allotment Option pursuant to Section 5.2(b), and (iii) the [ ] Common Units issuable to the holders of Pre-Initial Offering Interests pursuant to Section 5.1.

Section 5.3 Interest and Withdrawal. No interest shall be paid by the Company on Capital Contributions. No Member shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Company may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Member shall have priority over any other Member either as to the return of Capital Contributions or as to profits, losses or distributions.

Section 5.4 Capital Accounts.

(a) The Company shall maintain for each Member (or a beneficial owner of Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the

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Company in accordance with Section 6031(c) of the Code or any other method acceptable to the Company) owning an Interest a separate Capital Account with respect to such Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Company with respect to such Interest pursuant to this Agreement and (ii) all items of Company income and gain (including, without limitation, Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.4(b) and allocated with respect to such Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Interest pursuant to this Agreement and (y) all items of Company deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.4(b) and allocated with respect to such Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction, Simulated Depletion, Simulated Gain or Simulated Loss which is to be allocated pursuant to Article VI and is to be reflected in the Members' Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including, without limitation, any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.4, the Company shall be treated as owning directly its proportionate share (as determined by the Board of Directors based upon the provisions of the applicable Group Member Agreement) of all property owned by any other Group Member that is classified as a partnership for federal income tax purposes.

(ii) All fees and other expenses incurred by the Company to promote the sale of (or to sell) an Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Members pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under Section 754 of the Code which may be made by the Company and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Company property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Company's Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery amortization or Simulated Depletion attributable to any

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Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Company were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.4(d) to the Carrying Value of any Company property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery, amortization or Simulated Depletion derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery, amortization or Simulated Depletion deductions shall be determined using any method that the Board of Directors may adopt.

(vi) If the Company's adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Members pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Members to whom such deemed deduction was allocated.

(c) A transferee of an Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Interest so transferred.

(d)

(i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Interests for cash or Contributed Property and the issuance of Interests as consideration for the provision of services, the Capital Account of all Members and the Carrying Value of each Company property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Members at such time pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Company assets (including, without limitation, cash or cash equivalents) immediately prior to the issuance of additional Interests shall be determined by the Board of Directors using such method of valuation as it may adopt; provided, however, that the Board of Directors, in arriving at such valuation, must take fully into account the fair market value of the Interests of all Members at such time. The Board of Directors shall allocate such aggregate value among the assets of the Company (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Member of any Company property (other than a distribution of cash that is not in redemption or retirement of an Interest), the Capital Accounts of all Members and the Carrying Value of all Company property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized in a

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sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Members, at such time, pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Company assets (including, without limitation, cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 10.3 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.4(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 10.3, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.5 Issuances of Additional Company Securities.

(a) Subject to Section 5.6, the Company may issue additional Company Securities, and options, rights, warrants and appreciation rights relating to the Company Securities for any Company purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the Board of Directors shall determine, all without the approval of any Members.

(b) Each additional Company Security authorized to be issued by the Company pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Company Securities), as shall be fixed by the Board of Directors, including (i) the right to share Company profits and losses or items thereof; (ii) the right to share in Company distributions; (iii) the rights upon dissolution and liquidation of the Company; (iv) whether, and the terms and conditions upon which, the Company may redeem the Company Security; (v) whether such Company Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Company Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Company Security; and (viii) the right, if any, of each such Company Security to vote on Company matters, including matters relating to the relative rights, preferences and privileges of such Company Security.

(c) The Board of Directors shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Company Securities and options, rights, warrants and appreciation rights relating to Company Securities pursuant to this Section 5.5, (ii) the admission of Additional Members and (iii) all additional issuances of Company Securities. The Board of Directors shall determine the relative designations, preferences, rights, powers and duties of the holders of the Units or other Company Securities being so issued. The Board of Directors shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Company Securities pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Company Securities are listed for trading.

Section 5.6 Limitations on Issuance of Additional Company Securities. The issuance of Company Securities pursuant to Section 5.5 shall be subject to the following restrictions and limitations: No fractional Units shall be issued by the Company.

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Section 5.7 No Preemptive Rights. No Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Company Security, whether unissued, held in the treasury or hereafter created.

Section 5.8 Splits and Combinations.

(a) Subject to Section 5.8(d), the Company may make a Pro Rata distribution of Company Securities to all Record Holders or may effect a subdivision or combination of Company Securities so long as, after any such event, each Member shall have the same Percentage Interest in the Company as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted retroactive to the date of formation of the Company.

(b) Whenever such a distribution, subdivision or combination of Company Securities is declared, the Board of Directors shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The Board of Directors also may cause a firm of independent public accountants selected by it to calculate the number of Company Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The Board of Directors shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Company may issue Certificates to the Record Holders of Company Securities as of the applicable Record Date representing the new number of Company Securities held by such Record Holders, or the Board of Directors may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Company Securities Outstanding, the Company shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Company shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.6(a) and this Section 5.8(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.9 Fully Paid and Non-Assessable Nature of Interests. All Member Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be validly issued, fully paid and non-assessable Interests in the Company, except as such non-assessability may be affected by Sections 18-607 or 18-804 of the Delaware Act and except to the extent otherwise provided in this Agreement.

ARTICLE VI
ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Members among themselves, the Company's items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss

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(computed in accordance with Section 5.4(b)) shall be allocated among the Members in each taxable year (or portion thereof) as provided herein below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Income for such taxable year shall be allocated to the Unitholders in accordance with their respective Percentage Interests.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Losses for such taxable period shall be allocated to the Unitholders in accordance with their respective Percentage Interests; provided that Net Losses shall not be allocated pursuant to this Section 6.1(b) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account).

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 10.3.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.4(d)), such Net Termination Gain shall be allocated among the Members in the following manner (and the Capital Accounts of the Members shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A) First, to each Member having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Members, until each such Member has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account; and

(B) Second, 100% to all Unitholders in accordance with their respective Percentage Interests.

(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.4(d)), such Net Termination Loss shall be allocated among the Members in the following manner:

(A) First, to the Unitholders holding Common Units, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero; and

(B) Second, the balance, if any, 100% to all Unitholders in accordance with their respective percentage Interests.

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(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Company Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Company Minimum Gain during any Company taxable period, each Member shall be allocated items of Company income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Member's Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Company Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Member Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Member Nonrecourse Debt Minimum Gain during any Company taxable period, any Member with a share of Member Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Company income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Member's Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Intentionally left blank.

(iv) Qualified Income Offset. In the event any Member unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Company income, gain and Simulated Gain shall be specially allocated to such Member in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or (ii).

(v) Gross Income Allocations. In the event any Member has a deficit balance in its Capital Account at the end of any Company taxable period in excess of the sum of (A) the amount such Member is required to restore pursuant to the provisions of this Agreement and (B) the amount such Member is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Member shall be specially allocated items of

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Company gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Member would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Members in accordance with their respective Percentage Interests. If the Board of Directors determines that the Company's Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the Board of Directors is authorized, upon notice to the other Members, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Member Nonrecourse Deductions. Member Nonrecourse Deductions for any taxable period shall be allocated 100% to the Member that bears the Economic Risk of Loss with respect to the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Member bears the Economic Risk of Loss with respect to a Member Nonrecourse Debt, such Member Nonrecourse Deductions attributable thereto shall be allocated between or among such Members in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Members agree that Nonrecourse Liabilities of the Company in excess of the sum of (A) the amount of Company Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Members in accordance with their respective Percentage Interests.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Members in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss allocated to each Member pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Member under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that

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there has been a decrease in Company Minimum Gain and (2) Member Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Member Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(x)(A) shall only be made with respect to Required Allocations to the extent the Board of Directors reasonably determines that such allocations will otherwise be inconsistent with the economic agreement among the Members. Further, allocations pursuant to this Section 6.1(d)(x)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the Board of Directors determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The Board of Directors shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(x)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(x)(A) among the Members in a manner that is likely to minimize such economic distortions.

(xi) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.4(d) hereof) to only certain Members (the "Allocated Members"), the Board of Directors shall allocate additional items of gross income, gain and Simulated Gain away from the Allocated Members to the extent that the Additional Book Basis Derivative Items allocated to the Allocated Members exceed their Share of Additional Book Basis Derivative Items and to the remaining Members (or shall allocate additional items of deduction, loss, Simulated Depletion and Simulated Loss away from the other Members and to the Allocated Members). For this purpose, a Member shall be treated as having been allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that otherwise have been allocated to the Member under this Amended and Restated Limited Liability Company Agreement. Any allocation made pursuant to this Section 6.1(d)(xi)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xi) were not in this Amended and Restated Limited Liability Company Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(B) In the case of any negative adjustments to the Capital Accounts of the Members resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the Board of Directors, that to the extent possible the aggregate Capital Accounts of the Members will equal the amount that would have been the Capital Account balance of the Members if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

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(C) In making the allocations required under this Section 6.1(d)(xi), the Board of Directors may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xi).

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Members in the same manner as its correlative item of "book" income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Members rather than by the Company in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Company under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Members in accordance with their respective Percentage Interests.

Each Member shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Company.

(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Member on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Company's allocable share of the "amount realized" (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Members as follows:

(i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Members in the same proportion as the depletable basis of such property was allocated to the Members pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii));

(ii) second, the remainder of such amount realized, if any, to the Members so that, to the maximum extent possible, the amount realized allocated to each Member under this Section 6.2(c)(ii) will equal such Member's share of the Simulated Gain recognized by the Company from such sale or disposition.

(iii) The Members recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Members to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).

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(iv) Any elections or other decisions relating to such allocations shall be made by the Board of Directors in any manner that reasonably reflects the purpose and intention of the Agreement.

(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than an oil and gas property pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Members as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Members in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Members in the same manner as its correlative item of "book" gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Members in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.4(d)(i) or 5.4(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Members in a manner consistent with Section 6.2(b)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Members in the same manner as its correlative item of "book" gain or loss is allocated pursuant to Section 6.1.

(iii) The Board of Directors shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

(e) For the proper administration of the Company and for the preservation of uniformity of the Units (or any class or classes thereof), the Board of Directors shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including, without limitation, gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Units (or any class or classes thereof). The Board of Directors may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(c) only if such conventions, allocations or amendments would not have a material adverse effect on the Members, the holders of any class or classes of Units issued and Outstanding or the Company, and if such allocations are consistent with the principles of Section 704 of the Code.

(f) The Board of Directors may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Company's common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the Board of Directors determines that such reporting position cannot be taken, the Board of Directors may

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adopt depreciation and amortization conventions under which all purchasers acquiring Units in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Company's property. If the Board of Directors chooses not to utilize such aggregate method, the Board of Directors may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Member Interests, so long as such conventions would not have a material adverse effect on the Members or the Record Holders of any class or classes of Units.

(g) Any gain allocated to the Members upon the sale or other taxable disposition of any Company asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Members (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(h) All items of income, gain, loss, deduction and credit recognized by the Company for federal income tax purposes and allocated to the Members in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Company; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the Board of Directors) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(i) Each item of Company income, gain, loss and deduction shall, for federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Members as of the opening of the New York Stock Exchange on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Members as of the opening of the New York Stock Exchange on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Company or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the Board of Directors, shall be allocated to the Members as of the opening of the New York Stock Exchange on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The Board of Directors may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(j) Allocations that would otherwise be made to a Member under the provisions of this Article VI shall instead be made to the beneficial owner of Units held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company in accordance with Section 6031(c) of the Code or any other method determined by the Board of Directors.

Section 6.3 Requirement of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the Quarter ending on [ , 2005], an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 18-607 of the Delaware Act, be distributed in accordance with this Article VI by the Company to the Members as of the Record Date selected by the Board of Directors. All distributions required to be made under this Agreement shall be made subject to Sections 18-607 and 18-804 of the Delaware Act.

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(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Company, all receipts received during or after the Quarter in which the Liquidation Date occurs, other than from borrowings described in (a)(ii) of the definition of Available Cash, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 10.3(a).

(c) The Board of Directors may treat taxes paid by the Company on behalf of, or amounts withheld with respect to, all or less than all of the Members, as a distribution of Available Cash to such Members.

(d) Each distribution in respect of an Interest shall be paid by the Company, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Company's liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Distributions of Available Cash. Available Cash with respect to any Quarter, subject to Section 18-607 of the Delaware Act and except as otherwise required by Section 5.6(b) in respect of other Company Securities issued pursuant thereto, shall be distributed 100% to all Unitholders in accordance with their respective Percentage Interests.

ARTICLE VII
MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Board of Directors.

(a) Except as otherwise expressly provided in this Agreement, the business and affairs of the Company shall be managed by or under the direction of a Board of Directors (the "Board of Directors"). As provided in Section 7.4, the Board of Directors shall have the power and authority to appoint Officers of the Company. The Directors and Officers shall constitute "managers" within the meaning of the Delaware Act. No Member, by virtue of its status as such, shall have any management power over the business and affairs of the Company or actual or apparent authority to enter into, execute or deliver contracts on behalf of, or to otherwise bind, the Company. Except as otherwise specifically provided in this Agreement, the authority and functions of the Board of Directors, on the one hand, and of the Officers, on the other, shall be identical to the authority and functions of the board of directors and officers, respectively, of a corporation organized under the DGCL. In addition to the powers that now or hereafter can be granted to managers under the Delaware Act and to all other powers granted under any other provision of this Agreement subject to Section 7.3, the Board of Directors shall have full power and authority to do, and to direct the Officers to do, all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Company, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Company Securities, and the incurring of any other obligations;

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(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Company;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Company or the merger or other combination of the Company with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3);

(iv) the use of the assets of the Company (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Company Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment of obligations of the Company Group and the making of capital contributions to any member of the Company Group;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Company under contractual arrangements to all or particular assets of the Company);

(vi) the distribution of Company cash;

(vii) the selection and dismissal of officers, employees, agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring, the creation and operation of employee benefit plans, employee programs and employee practices;

(viii) the maintenance of insurance for the benefit of the Company Group and the Members;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Company, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or remediation, and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.6);

(xiii) unless restricted or prohibited by Section 5.7, the purchase, sale or other acquisition or disposition of Company Securities, or the issuance of additional options, rights, warrants and appreciation rights relating to Company Securities;

(xiv) the undertaking of any action in connection with the Company's participation in any Group Member; and

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(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member.

(b) The Board of Directors shall consist of not fewer than three nor more than 11 natural Persons. Each Director shall be elected as provided in Section 7.1(c) and shall serve in such capacity until his successor has been duly elected and qualified or until such Director dies, resigns or is removed. A Director may resign at any time upon written notice to the Company. The Board of Directors may from time to time determine the number of Directors then constituting the whole Board of Directors, but the Board of Directors shall not decrease the number of Persons that constitute the whole Board of Directors if such decrease would shorten the term of any Director.

(c) Directors shall be elected at each annual meeting of Members to serve for a term expiring at the next annual meeting of Members. The nomination of Persons to serve as Directors and the election of the Board of Directors shall be in accordance with Article XI hereof.

(d) Subject to applicable law and the rights of the holders of any series of Interests, vacancies existing on the Board of Directors (including a vacancy created by virtue of an increase in the size of the Board of Directors) may be filled only by the affirmative vote of a majority of the Directors then serving, even if less than a quorum. Any Director chosen to fill a vacancy shall hold office until the next annual meeting of Members and until his successor has been duly elected and qualified or until such Director's earlier resignation or removal. Subject to the rights of the holders of any series of Interests, any Director, and the entire Board of Directors, may be removed from office at any time by the affirmative vote of Members holding a majority of the Percentage Interest of all Members entitled to vote; provided, however, that no Director may be removed (whether voting on the removal of an individual Director or the removal of the entire Board of Directors) without cause if the votes cast against such Director's removal would be sufficient to elect such Director if then cumulatively voted at an election of the entire Board of Directors.

(e) Directors need not be Members. The Board of Directors may, from time to time and by the adoption of resolutions, establish qualifications for Directors.

(f) Unless otherwise required by the Delaware Act, other law or the provisions hereof,

(i) each member of the Board of Directors shall have one vote;

(ii) the presence at a meeting of the Board of Directors of a majority of the members of the Board of Directors shall constitute a quorum at any such meeting for the transaction of business; and

(iii) the act of a majority of the members of the Board of Directors present at a meeting of the Board of Directors at which a quorum is present shall be deemed to constitute the act of the Board of Directors.

(g) Regular meetings of the Board of Directors and any committee thereof shall be held at such times and places as shall be designated from time to time by resolution of the Board of Directors or such committee. Notice of such regular meetings shall not be required. Special meetings of the Board of Directors or meetings of any committee thereof may be called by the Chairman of the Board or on the written request of any three Directors or committee members, as applicable, to the Secretary, in each case on at least twenty-four hours personal, written, facsimile, electronic, telegraphic, cable or wireless notice to each Director or committee member,

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which notice may be waived by any Director. Any such notice, or waiver thereof, need not state the purpose of such meeting except as may otherwise be required by law. Attendance of a Director at a meeting (including pursuant to the last sentence of this Section 7.1(g)) shall constitute a waiver of notice of such meeting, except where such Director attends the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened. Any action required or permitted to be taken at a meeting of the Board of Directors, or any committee thereof, may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, are signed by all members of the Board of Directors or committee. Members of the Board of Directors or any committee thereof may participate in and hold a meeting by means of conference telephone, video conference or similar communications equipment by means of which all Persons participating in the meeting can hear each other, and participation in such meetings shall constitute presence in Person at the meeting.

(h) The Board of Directors may, by resolution of a majority of the full Board of Directors, designate one or more committees, each committee to consist of one or more of the Directors. The Board of Directors may designate one or more Directors as alternate members of any committee, who may replace any absent or disqualified Director at any meeting of such committee. Any such committee, to the extent provided in the resolution of the Board of Directors or in this Agreement, shall have and may exercise all powers and authority of the Board of Directors in the management of the business and affairs of the Company; but no such committee shall have the power or authority in reference to the following matters: approving or adopting, or recommending to the Members, any action or matter expressly required by this Agreement or the Delaware Act to be submitted to the Members for approval or adopting, amending or repealing any provision of this Agreement. Unless specified by resolution of the Board of Directors, any committee designated pursuant to this Section 7.1(h) shall choose its own chairman, shall keep regular minutes of its proceedings and report the same to the Board of Directors when requested, and, subject to Section 7.1(g), shall fix its own rules or procedures and shall meet at such times and at such place or places as may be provided by such rules. At every meeting of any such committee, the presence of a majority of all the members thereof shall constitute a quorum and the affirmative vote of a majority of the members present at a meeting of which a quorum is present shall be necessary for the adoption by the committee of any resolution.

(i) The Board of Directors may elect one of its members as Chairman of the Board (the "Chairman of the Board"). The Chairman of the Board, if any, and if present and acting, shall preside at all meetings of the Board of Directors and of Members, unless otherwise directed by the Board of Directors. If the Board of Directors does not elect a Chairman or if the Chairman is absent from the meeting, the Chief Executive Offer, if present and a Director, or any other Director chosen by the Board of Directors, shall preside. In the absence of a Secretary, the chairman of the meeting may appoint any Person to serve as Secretary of the meeting.

(j) Unless otherwise restricted by law, the Board of Directors shall have the authority to fix the compensation of the Directors. The Directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors or paid a stated salary or paid other compensation as Director. No such payment shall preclude any Director from serving the Company in any other capacity and receiving compensation therefor. Members of special or standing committees may also be paid their expenses, if any, of and allowed compensation for attending committee meetings.

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(k) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Members and each other Person who may acquire an interest in Company Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Underwriting Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the Board of Directors (on its own or through any Officer of the Company) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Company without any further act, approval or vote of the Members or the other Persons who may acquire an interest in Company Securities; and (iii) agrees that the execution, delivery or performance by the Company, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement shall not constitute a breach by the Board of Directors or any Officer of any duty that the Board of Directors or any Officer may owe the Company or the Members or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

Section 7.2 Certificate of Formation. The Certificate of Formation has been filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The Board of Directors shall use all reasonable efforts to cause to be filed such other certificates or documents that it determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited liability company in the State of Delaware or any other state in which the Company may elect to do business or own property. To the extent that the Board of Directors determines such action to be necessary or appropriate, the Board of Directors shall direct the appropriate Officers of the Company to file amendments to and restatements of the Certificate of Formation and do all things to maintain the Company as a limited liability company under the laws of the State of Delaware or of any other state in which the Company may elect to do business or own property. Subject to the terms of Section 3.4(a), the Company shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Formation, any qualification document or any amendment thereto to any Member.

Section 7.3 Restrictions on the Board of Directors' Authority.

(a) Except as otherwise provided in this Agreement, the Board of Directors may not, without written approval of the specific act by holders of all of the Outstanding Member Interests or by other written instrument executed and delivered by holders of all of the Outstanding Member Interests subsequent to the date of this Agreement, take any action in contravention of this Agreement, including (i) committing any act that would make it impossible to carry on the ordinary business of the Company; (ii) possessing Company property, or assigning any rights in specific Company property, for other than a Company purpose; (iii) admitting a Person as a Member; or (iv) amending this Agreement in any manner.

(b) Except as provided in Articles X and XII, the Board of Directors may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Company Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the Board of Directors' ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the

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Company Group and shall not apply to any forced sale of any or all of the assets of the Company Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.4 Officers.

(a) The Board of Directors shall have the power and authority to appoint such officers with such titles, authority and duties as determined by the Board of Directors. Such Persons so designated by the Board of Directors shall be referred to as "Officers." Unless provided otherwise by resolution of the Board of Directors, the Officers shall have the titles, power, authority and duties described below in this Section 7.4.

(b) The Officers of the Company shall include a Chairman of the Board, a Chief Executive Officer, a President, and a Secretary, and may also include a Vice Chairman, Chief Operating Officer, Treasurer, one or more Vice Presidents (who may be further classified by such descriptions as "executive," "senior," "assistant" or otherwise, as the Board of Directors shall determine), one or more Assistant Secretaries and one or more Assistant Treasurers. Officers shall be elected by the Board of Directors, which shall consider that subject at its first meeting after every annual meeting of Members and as necessary to fill vacancies. Each Officer shall hold office until his or her successor is elected and qualified or until his or her earlier death, resignation or removal. Any number of offices may be held by the same Person. The compensation of Officers elected by the Board of Directors shall be fixed from time to time by the Board of Directors or by such Officers as may be designated by resolution of the Board of Directors.

(c) Any Officer may resign at any time upon written notice to the Company. Any Officer, agent or employee of the Company may be removed by the Board of Directors with or without cause at any time. The Board of Directors may delegate the power of removal as to Officers, agents and employees who have not been appointed by the Board of Directors. Such removal shall be without prejudice to a Person's contract rights, if any, but the appointment of any Person as an Officer, agent or employee of the Company shall not of itself create contract rights.

(d) The President shall be the Chief Executive Officer of the Company unless the Board of Directors designates the Chairman of the Board as Chief Executive Officer. Subject to the control of the Board of Directors and the executive committee (if any), the Chief Executive Officer shall have general executive charge, management and control of the properties, business and operations of the Company with all such powers as may be reasonably incident to such responsibilities; he may employ and discharge employees and agents of the Company except such as shall be appointed by the Board of Directors, and he may delegate these powers; he may agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Company, and shall have such other powers and duties as designated in accordance with this Agreement and as from time to time may be assigned to him by the Board of Directors.

(e) If elected, the Chairman of the Board shall preside at all meetings of the Members and of the Board of Directors; and shall have such other powers and duties as designated in this Agreement and as from time to time may be assigned to him by the Board of Directors.

(f) Unless the Board of Directors otherwise determines, the President shall have the authority to agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Company; and, unless the Board of Directors otherwise determines, shall, in the absence of the Chairman of the Board or if there be no Chairman of the Board, preside at all meetings of the Members and (should he be a Director) of the Board of Directors;

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and he shall have such other powers and duties as designated in accordance with this Agreement and as from time to time may be assigned to him by the Board of Directors.

(g) In the absence of the President, or in the event of his inability or refusal to act, a Vice President designated by the Board of Directors shall perform the duties of the President, and when so acting shall have all the powers of and be subject to all the restrictions upon the President. In the absence of a designation by the Board of Directors of a Vice President to perform the duties of the President, or in the event of his absence or inability or refusal to act, the Vice President who is present and who is senior in terms of uninterrupted time as a Vice President of the Company shall so act. The Vice President shall perform such other duties and have such other powers as the Board of Directors may from time to time prescribe. Unless otherwise provided by the Board of Directors, each Vice President will have authority to act within his or her respective areas and to sign contracts relating thereto.

(h) The Treasurer shall have responsibility for the custody and control of all the funds and securities of the Company and shall have such other powers and duties as designated in this Agreement and as from time to time may be assigned to the Treasurer by the Board of Directors. The Treasurer shall perform all acts incident to the position of Treasurer, subject to the control of the Chief Executive Officer and the Board of Directors. Each Assistant Treasurer shall have the usual powers and duties pertaining to his office, together with such other powers and duties as designated in this Agreement and as from time to time may be assigned to him by the Chief Executive Officer or the Board of Directors. The Assistant Treasurers shall exercise the powers of the Treasurer during that Officer's absence or inability or refusal to act. An Assistant Treasurer shall also perform such other duties as the Treasurer or the Board of Directors may assign to him.

(i) The Secretary shall issue all authorized notices for, and shall keep minutes of, all meetings of the Members and the Board of Directors. The Secretary shall have charge of the corporate books and shall perform such other duties as the Board of Directors may from time to time prescribe. In the absence or inability to act of the Secretary, any Assistant Secretary may perform all the duties and exercise all the powers of the Secretary. The performance of any such duty shall, in respect of any other Person dealing with the Company, be conclusive evidence of his power to act. An Assistant Secretary shall also perform such other duties as the Secretary or the Board of Directors may assign to him.

(j) The Board of Directors may from time to time delegate the powers or duties of any Officer to any other Officers or agents, notwithstanding any provision hereof.

(k) Unless otherwise directed by the Board of Directors, the Chief Executive Officer, the President or any Officer of the Company authorized by the Chief Executive Officer shall have power to vote and otherwise act on behalf of the Company, in person or by proxy, at any meeting of Members of or with respect to any action of equity holders of any other entity in which the Company may hold securities and otherwise to exercise any and all rights and powers which the Company may possess by reason of its ownership of securities in such other entities.

Section 7.5 Outside Activities. (a) It shall be deemed not to be a breach of any duty (including any fiduciary duty) or any other obligation of any type whatsoever of any Director for Affiliates of such Director to engage in outside business interests and activities in preference to or to the exclusion of the Company or in direct competition with the Company; provided such Affiliate does not engage in such business or activity as a result of or using confidential information provided by or on behalf of the Company to such Director and (b) Directors shall

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have no obligation hereunder or as a result of any duty expressed or implied by law to present business opportunities to the Company that may become available to Affiliates of such Director. None of any Group Member, any Member or any other Person shall have any rights by virtue of a Director's duties as a Director, this Agreement or any Group Member Agreement in any business ventures of any Director.

Section 7.6 Loans or Contributions from the Company or Group Members.

(a) The Company may lend or contribute to any Group Member, and any Group Member may borrow from the Company, funds on terms and conditions determined by the Board of Directors.

(b) No borrowing by any Group Member or the approval thereof by the Board of Directors shall be deemed to constitute a breach of any duty (including any fiduciary duty), expressed or implied, of the Board of Directors to the Company or the Members by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to enable distributions to the Members.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law as it currently exists and to such greater extent as applicable law hereafter may permit, but subject to the limitations expressly provided in this Agreement, the Company shall indemnify any Person who was or is a party or is threatened to be made a party to, or otherwise requires representation of counsel in connection with, any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the Company) by reason of the fact that such Person is or was a Director or Officer of the Company, or, while serving as a Director or Officer of the Company, is or was serving as a Tax Matters Partner or, at the request of the Company, as a director, officer, tax matters partner, employee, partner, manager, fiduciary or trustee of any Group Member or any other Person (each an "Indemnitee") or by reason of any action alleged to have been taken or omitted in such capacity, against losses, expenses (including attorneys' fees), judgments, fines, damages, penalties, interest, liabilities and amounts paid in settlement actually and reasonably incurred by the Person in connection with such action, suit or proceeding if the Person acted in good faith and in a manner the Person reasonably believed to be in or not opposed to the best interests of the Company, and, with respect to any criminal action or proceeding, had no reasonable cause to believe that such Person's conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the Person did not act in good faith and in a manner which the Person reasonably believed to be in or not opposed to the best interests of the Company, and, with respect to any criminal action or proceeding, had reasonable cause to believe that the Person's conduct was unlawful.

(b) To the fullest extent permitted by law, but subject to the limitations expressly provided in this Agreement, the Company shall indemnify any Person who was or is a party or is threatened to be made a party to, or otherwise requires representation of counsel in connection with, any threatened, pending or completed action, suit or proceeding, by or in the right of the Company to procure a judgment in its favor by reason of the fact that such Person was serving as an Indemnitee, or by reason of any action alleged to have been taken or omitted in such capacity, against losses, expenses (including attorneys' fees), judgments, fines, damages, penalties, interest, liabilities and amounts paid in settlement actually and reasonably incurred by the Person in

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connection with such action, suit or proceeding if the Person acted in good faith and in a manner the Person reasonably believed to be in or not opposed to the best interests of the Company and except that no indemnification shall be made in respect of any claim, issue or matter as to which such Person shall have been adjudged to be liable to the Company unless and only to the extent that the Delaware Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such Person is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper.

(c) To the extent an Indemnitee has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in Section 7.7(a) or Section 7.7(b), or in the defense of any claim, issue or matter therein, such Person shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred by such Person in connection therewith.

(d) Any indemnification under Section 7.7(a) or Section 7.7(b) (unless ordered by a court) shall be made by the Company only as authorized in the specific case upon a determination that indemnification of the Indemnitee is proper in the circumstances because the Person has met the applicable standard of conduct set forth in such section. Such determination shall be made, with respect to a Person who is a Director or Officer at the time of such determination, (i) by a majority vote of the Directors who are not parties to such action, suit or proceeding, even though less than a quorum, (ii) by a committee of such Directors designated by majority vote of such Directors, even though less than a quorum, (iii) if there are no such Directors, or if such Directors so direct, by independent legal counsel in an Opinion of Counsel, or (iv) by the Members.

(e) Expenses (including attorneys' fees) incurred by an Indemnitee in defending any action, suit or proceeding referred to in Section 7.7(a) or Section 7.7(b) shall be paid by the Company in advance of the final disposition of such action, suit or proceeding and in advance of any determination that such Indemnitee is not entitled to be indemnified, upon receipt of an undertaking by or on behalf of such Indemnitee to repay such amount if it shall ultimately be determined by final judicial decision from which there is no further right to appeal (a "Final Adjudication") that such Person is not entitled to be indemnified by the Company as authorized in this Section 7.7.

(f) The indemnification, advancement of expenses and other provisions of this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Interests, as a matter of law or otherwise, both as to actions in the Indemnitee's capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(g) The Company may purchase and maintain insurance, on behalf of its Directors and Officers, and such other Persons as the Board of Directors shall determine, against any liability that may be asserted against or expense that may be incurred by such Person in connection with the Company's activities or such Person's activities on behalf of the Company, regardless of whether the Company would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(h) For purposes of the definition of Indemnitee in Section 7.7(a), the Company shall be deemed to have requested a Person to serve as fiduciary of an employee benefit plan whenever

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the performance by such Person of his duties to the Company also imposes duties on, or otherwise involves services by, such Person to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute "fines" within the meaning of Section 7.7(a); and action taken or omitted by such Person with respect to any employee benefit plan in the performance of such Person's duties for a purpose reasonably believed by him to be in the interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in, or not opposed to, the best interests of the Company.

(i) Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Company, it being agreed that the Members shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Company to enable it to effectuate such indemnification.

(j) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(k) If a claim under Section 7.7 of this Agreement is not paid in full by the Company within 60 days after a written claim has been received by the Company, except in the case of a claim for an advancement of expenses, in which case the applicable period shall be 20 days, the Indemnitee may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim. If successful in whole or in part in any such suit, or in a suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the Indemnitee shall be entitled to be paid also the reasonable expenses of prosecuting or defending such suit. In (i) any suit brought by the Indemnitee to enforce a right to indemnification hereunder (but not in a suit brought by the Indemnitee to enforce a right to an advancement of expenses) it shall be a defense that, and (ii) in any suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the Company shall be entitled to recover such expenses upon a Final Adjudication that, the Indemnitee has not met any applicable standard for indemnification set forth in this Agreement. Neither the failure of the Company (including its Directors who are not parties to such action, a committee of such Directors, independent legal counsel, or its Members) to have made a determination prior to the commencement of such suit that indemnification of the Indemnitee is proper in the circumstances because the Indemnitee has met the applicable standard of conduct set forth in this Agreement, nor an actual determination by the Company (including its Directors who are not parties to such action, a committee of such Directors, independent legal counsel, or its Members) that the Indemnitee has not met the applicable standard of conduct shall create a presumption that the Indemnitee has not met the applicable standard of conduct, or, in the case of such a suit brought by the Indemnitee, be a defense to such suit. In any suit brought by the Indemnitee to enforce a right to indemnification or to an advancement of expenses hereunder, or brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the burden of proving that the Indemnitee is not entitled to be indemnified or to such advancement of expenses, under this Section 7.7 or otherwise shall be on the Company.

(l) The Company may indemnify any Person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (whether or not an action by or in the right of the Company) by reason of the fact that the Person is or was an employee (other than an Officer) or

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agent of the Company, or, while serving as an employee (other than an Officer) or agent of the Company is or was serving at the request of the Company as a director, officer, employee, partner, fiduciary, trustee or agent of another Group Member or another Person to the extent (i) permitted by the laws of the State of Delaware as from time to time in effect, and (ii) authorized by the Board of Directors. The Company may, to the extent permitted by Delaware law and authorized by the Board of Directors, pay expenses (including attorneys' fees) reasonably incurred by any such employee or agent in defending any civil, criminal, administrative or investigative action, suit or proceeding in advance of the final disposition of such action, suit or proceeding, upon such terms and conditions as the Board of Directors determine. The provisions of this Section 7.7(l) shall not constitute a contract right for any such employee or agent.

(m) The indemnification, advancement of expenses and other provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(n) Except to the extent otherwise provided in Section 7.7(l), the right to be indemnified and to receive advancement of expenses in this Section 7.7 shall be a contract right. No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Company, nor the obligations of the Company to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

(o) The Board of Directors, acting alone and without the approval of any Member, in the event of any amendment to Section 145 of the DGCL or the amendment or addition of any other provision of the DGCL relating to indemnification by Delaware corporations of Persons of the type referenced in this Section 7.7, may amend this Agreement to, entirely or in part, reflect such amendment or addition in the indemnification provisions of this Agreement.

Section 7.8 Exculpation of Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Director shall be liable to the Company or the Members for monetary damages for breach of fiduciary duty as a Director, except

(i) for a breach of the Director's duty of loyalty to the Company or the Members;

(ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law; or

(iii) for any transaction from which the Director derived an improper personal benefit.

If the DGCL is amended after the date of this Agreement to authorize Delaware corporations to further eliminate or limit the personal liability of directors of Delaware corporations beyond that permitted under Section 102(b)(7) of the DGCL, then the liability of a Director to the Company or the Members, in addition to the personal liability limitation provided herein, shall be further limited to the fullest extent permitted under the DGCL as so amended.

(b) Subject to its obligations and duties as Board of Directors set forth in this Article VII, the Board of Directors may exercise any of the powers granted to it by this Agreement and

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perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the Board of Directors shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the Board of Directors in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Company or to the Members, the Directors and any other Indemnitee acting in connection with the Company's business or affairs shall not be liable to the Company or to any Member for its good faith reliance on the provisions of this Agreement. The provisions of this Agreement, to the extent that they restrict or eliminate or otherwise modify the duties (including fiduciary duties) and liabilities of an Indemnitee otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of such Indemnitee.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of any Indemnitee under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between one or more Directors or their respective Affiliates, on the one hand, and the Company or any Group Member, on the other, any resolution or course of action by the Board of Directors or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Members, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, including any fiduciary duty, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Outstanding Units held by disinterested parties, (iii) on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Company, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Company). The Board of Directors shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the Board of Directors may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is not sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest is on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or that the resolution or course of action taken with respect to a conflict of interest is fair and reasonable to the Company, then such resolution or course of action shall be permitted and deemed approved by all the Members, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, including any fiduciary duty. In connection with any such approval by the Board of Directors, it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Member or by or on behalf of

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such Member or any other Member or the Company challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Members.

(b) The Members hereby authorize the Board of Directors, on behalf of the Company as a partner or member of a Group Member, to approve of actions by the Board of Directors or managing member of such Group Member similar to those actions permitted to be taken by the Board of Directors pursuant to this Section 7.9.

Section 7.10 Duties of Officers and Directors.

(a) Except as otherwise expressly provided in Section 7.5, 7.6, 7.7, 7.8 and 7.9 or elsewhere in this Agreement, the duties and obligations owed to the Company and to the Members by the Officers and Directors, shall be the same as the respective duties and obligations owed to a corporation organized under DGCL by its officers and directors, respectively.

(b) A Director shall, in the performance of his duties, be fully protected in relying in good faith upon the records of the Company and on such information, opinions, reports or statements presented to the Company by any of the Company's Officers or employees, or committees of the Board of Directors, or by any other Person as to matters the Director reasonably believes are within such other Person's professional or expert competence and who has been selected with reasonable care by or on behalf of the Company.

(c) The Board of Directors shall have the right, in respect of any of its powers or obligations hereunder, to act through a duly appointed attorney or attorneys-in-fact or the duly authorized Officers of the Company.

Section 7.11 Purchase or Sale of Company Securities. The Board of Directors may cause the Company to purchase or otherwise acquire Company Securities.

Section 7.12 Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Company shall be entitled to assume that the Board of Directors and any Officer authorized by the Board of Directors to act on behalf of and in the name of the Company has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Company and to enter into any authorized contracts on behalf of the Company, and such Person shall be entitled to deal with the Board of Directors or any Officer as if it were the Company's sole party in interest, both legally and beneficially. Each Member hereby waives any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the Board of Directors or any Officer in connection with any such dealing. In no event shall any Person dealing with the Board of Directors or any Officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the Board of Directors or any Officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Company by the Board of Directors or any Officer or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Company and

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(c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Company.

ARTICLE VIII
BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting. The Board of Directors shall keep or cause to be kept at the principal office of the Company appropriate books and records with respect to the Company's business, including all books and records necessary to provide to the Members any information required to be provided pursuant to this Agreement. Any books and records maintained by or on behalf of the Company in the regular course of its business, including the record of the Record Holders of Units or other Company Securities, books of account and records of Company proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Company shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year. The fiscal year of the Company shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Company, the Board of Directors shall cause to be mailed or made available to each Record Holder of a Unit as of a date selected by the Board of Directors, an annual report containing financial statements of the Company for such fiscal year of the Company, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, equity and cash flows, such statements to be audited by a registered public accounting firm selected by the Board of Directors.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the Board of Directors shall cause to be mailed or made available to each Record Holder of a Unit, as of a date selected by the Board of Directors, a report containing unaudited financial statements of the Company and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed for trading, or as the Board of Directors determines to be necessary or appropriate.

ARTICLE IX
TAX MATTERS

Section 9.1 Tax Returns and Information. The Company shall timely file all returns of the Company that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Company's taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

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Section 9.2 Tax Elections.

(a) The Company shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the Board of Directors' determination that such revocation is in the best interests of the Members. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the Board of Directors shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Member Interest will be deemed to be the lowest quoted closing price of the Member Interests on any National Securities Exchange on which such Member Interests are traded during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(i) without regard to the actual price paid by such transferee.

(b) The Company shall elect to deduct expenses incurred in organizing the Company ratably over a sixty-month period as provided in Section 709 of the Code.

(c) Except as otherwise provided herein, the Board of Directors shall determine whether the Company should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the Board of Directors shall designate one Officer who is a Member as the Tax Matters Partner (as defined in the Code). The Tax Matters Partner is authorized and required to represent the Company (at the Company's expense) in connection with all examinations of the Company's affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Company funds for professional services and costs associated therewith. Each Member agrees to cooperate with the Tax Matters Partner and to do or refrain from doing any or all things reasonably required by the Tax Matters Partner to conduct such proceedings.

Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the Board of Directors is authorized to take any action that may be required to cause the Company and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including, without limitation, pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Company is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Member (including, without limitation, by reason of Section 1446 of the Code), the Board of Directors may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Member.

ARTICLE X
DISSOLUTION AND LIQUIDATION

Section 10.1 Dissolution. The Company shall not be dissolved by the admission of Substituted Members or Additional Members. The Company shall dissolve, and its affairs shall be wound up, upon:

(a) an election to dissolve the Company by the Board of Directors that is approved by the holders of a Unit Majority;

(b) the sale, exchange or other disposition of all or substantially all of the assets and properties of the Company and the Company's Subsidiaries; or

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Section 10.2 Liquidator. Upon dissolution of the Company, the Board of Directors shall select one or more Persons to act as Liquidator. The Liquidator (if other than the Board of Directors) shall be entitled to receive such compensation for its services as may be approved by holders of a Unit Majority. The Liquidator (if other than the Board of Directors) shall agree not to resign at any time without 15 days' prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of a Unit Majority. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a Unit Majority. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article X, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the Board of Directors under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3(b)) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Company as provided for herein.

Section 10.3 Liquidation. The Liquidator shall proceed to dispose of the assets of the Company, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 18-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Members on such terms as the Liquidator and such Member or Members may agree. If any property is distributed in kind, the Member receiving the property shall be deemed for purposes of Section 10.3(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Members. The Liquidator may defer liquidation or distribution of the Company's assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Company's assets would be impractical or would cause undue loss to the Members. The Liquidator may distribute the Company's assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Members.

(b) Liabilities of the Company include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 10.2) and amounts to Members otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 10.3(b) shall be distributed to the Members in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of

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distributions pursuant to this Section 10.3(c)) for the taxable year of the Company during which the liquidation of the Company occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 10.4 Cancellation of Certificate of Formation. Upon the completion of the distribution of Company cash and property as provided in Section 10.3 in connection with the liquidation of the Company, the Company shall be terminated and the Certificate of Formation and all qualifications of the Company as a foreign limited liability company in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Company shall be taken.

Section 10.5 Return of Contributions. None of any member of the Board of Directors or any Officer of the Company will be personally liable for, or have any obligation to contribute or loan any monies or property to the Company to enable it to effectuate, the return of the Capital Contributions of the Members or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Company assets.

Section 10.6 Waiver of Partition. To the maximum extent permitted by law, each Member hereby waives any right to partition of the Company property.

Section 10.7 Capital Account Restoration. No Member shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Company.

ARTICLE XI
AMENDMENT OF AGREEMENT; MEETINGS OF MEMBERS; RECORD DATE

Section 11.1 Amendment of Limited Liability Company Agreement.

(a) General Amendments. Except as provided in Section 11.1(b) and Section 11.1(c), the Board of Directors may amend any of the terms of this Agreement but only in compliance with the terms, conditions and procedures set forth in this Section 11.1(a). If the Board of Directors desires to amend any provision of this Agreement other than pursuant to Section 11.1(c), then it shall first adopt a resolution setting forth the amendment proposed, declaring its advisability, and either calling a special meeting of the Members entitled to vote in respect thereof for the consideration of such amendment or directing that the amendment proposed be considered at the next annual meeting of the Members. Amendments to this Agreement may be proposed only by or with the consent of the Board of Directors. Such special or annual meeting shall be called and held upon notice in accordance with Section 11.2 and Section 11.3 of this Agreement. The notice shall set forth such amendment in full or a brief summary of the changes to be effected thereby, as the Board of Directors shall deem advisable. At the meeting, a vote of Members entitled to vote thereon shall be taken for and against the proposed amendment. A proposed amendment shall be effective upon its approval by a Unit Majority, unless a greater percentage is required under this Agreement or by Delaware law.

(b) Super-Majority Amendments. Notwithstanding Section 11.1(a) but subject to Section 11.1(c), the affirmative vote of the holders of at least 75% of all Outstanding Units, voting together as a single class, shall be required to alter, amend, adopt any provision inconsistent with or repeal subsection (d) of Section 7.1, this subsection (b) of Section 11.1, Section 11.2, subsection (d) of Section 11.3, subsections (b) or (c) of Section 11.8, Section 11.10 or Section 11.13.

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(c) Amendments to be Adopted Solely by the Board of Directors. Notwithstanding Section 11.1(a) and Section 11.1(b), the Board of Directors, without the approval of any Member, may amend any provision of this Agreement, and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(i) a change in the name of the Company, the location of the principal place of business of the Company, the registered agent of the Company or the registered office of the Company;

(ii) admission, substitution, withdrawal or removal of Members in accordance with this Agreement;

(iii) a change that the Board of Directors determines to be necessary or appropriate to qualify or continue the qualification of the Company as a limited liability company under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(iv) a change that the Board of Directors determines (A) does not adversely affect the Members (including any particular class of Interests as compared to other classes of Interests) in any material respect, (B) to be necessary or appropriate to (1) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (2) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed for trading, compliance with any of which the Board of Directors deems to be in the best interests of the Company and the Members, (C) to be necessary or appropriate in connection with action taken by the Board of Directors pursuant to Section 5.8 or (D) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(v) a change in the fiscal year or taxable year of the Company and any other changes that the Board of Directors determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Company including, if the Board of Directors shall so determine, a change in the definition of "Quarter" and the dates on which distributions are to be made by the Company;

(vi) an amendment that is necessary, in the Opinion of Counsel, to prevent the Company or its Directors, Officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(vii) subject to the terms of Section 5.6, an amendment that the Board of Directors determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Company Securities pursuant to Section 5.5;

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(viii) any amendment expressly permitted in this Agreement to be made by the Board of Directors acting alone;

(ix) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 12.3;

(x) an amendment that the Board of Directors determines to be necessary or appropriate to reflect and account for the formation by the Company of, or investment by the Company in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Company of activities permitted by the terms of Section 2.4;

(xi) a merger or conveyance pursuant to Section 12.3(d); or

(xii) any other amendments substantially similar to the foregoing.

Section 11.2 Amendment Requirements.

(a) Notwithstanding the provisions of Section 11.1, no provision of this Agreement that establishes a percentage of Outstanding Units required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Section 11.1, no amendment to this Agreement may (i) enlarge the obligations of any Member without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 11.2(c), (ii) change Section 10.1(a), or (iii) change the term of the Company or, except as set forth in Section 10.1(a), give any Person the right to dissolve the Company.

(c) Except as provided in Section 12.3, and without limitation of the Board of Directors' authority to adopt amendments to this Agreement without the approval of any Members as contemplated in Section 11.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Interests in relation to other classes of Interests must be approved by the holders of not less than a majority of the Outstanding Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 11.1 and except as otherwise provided by Section 12.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Company obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Member under applicable law.

Section 11.3 Unitholder Meetings.

(a) All acts of Members to be taken hereunder shall be taken in the manner provided in this Article XI. An annual meeting of the Members for the election of Directors and for the transaction of such other business as may properly come before the meeting shall be held at such time and place as the Board of Directors shall specify, which date shall be within 13 months of the last annual meeting of Members. If authorized by the Board of Directors, and subject to such guidelines and procedures as the Board of Directors may adopt, Members and proxyholders not physically present at a meeting of Members, may by means of remote communication participate

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in such meeting, and be deemed present in person and vote at such meeting provided that the Company shall implement reasonable measures to verify that each Person deemed present and permitted to vote at the meeting by means of remote communication is a Member or proxyholder, to provide such Members or proxyholders a reasonable opportunity to participate in the meeting and to record the votes or other action made by such Members or proxyholders.

(b) A failure to hold the annual meeting of the Members at the designated time or to elect a sufficient number of Directors to conduct the business of the Company shall not affect otherwise valid acts of the Company or work a forfeiture or dissolution of the Company. If the annual meeting for election of Directors is not held on the date designated therefor, the Directors shall cause the meeting to be held as soon as is convenient. If there is a failure to hold the annual meeting for a period of 30 days after the date designated for the annual meeting, or if no date has been designated, for a period of 13 months after the latest to occur of the date of this Agreement or its last annual meeting, the Delaware Court of Chancery may summarily order a meeting to be held upon the application of any Member or Director. The Outstanding Units present at such meeting, either in person or by proxy, and entitled to vote thereat, shall constitute a quorum for the purpose of such meeting, notwithstanding any provision of this Agreement to the contrary. The Delaware Court of Chancery may issue such orders as may be appropriate, including orders designating the time and place of such meeting, the record date for determination of Unitholders entitled to vote, and the form of notice of such meeting.

(c) All elections of Directors will be by written ballots; if authorized by the Board of Directors, such requirement of a written ballot shall be satisfied by a ballot submitted by electronic transmission, provided that any such electronic transmission must either set forth or be submitted with information from which it can be reasonably determined that the electronic transmission was authorized by the Member or proxyholder.

(d) Special meetings of the Members may be called only by a majority of the Board of Directors. No Members or group of Members, acting in its or their capacity as Members, shall have the right to call a special meeting of the Members.

Section 11.4 Notice of Meetings of Members.

(a) Notice, stating the place, day and hour of any annual or special meeting of the Members, as determined by the Board of Directors, and (i) in the case of a special meeting of the Members, the purpose or purposes for which the meeting is called, as determined by the Board of Directors or (ii) in the case of an annual meeting, those matters that the Board of Directors, at the time of giving the notice, intends to present for action by the Members, shall be delivered by the Company not less than 10 calendar days nor more than 60 calendar days before the date of the meeting, in a manner and otherwise in accordance with Section 14.1 to each Record Holder who is entitled to vote at such meeting. Such further notice shall be given as may be required by Delaware law. The notice of any meeting of the Members at which directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the Board of Directors intends to present for election. Only such business shall be conducted at a special meeting of Members as shall have been brought before the meeting pursuant to the Company's notice of meeting. Any previously scheduled meeting of the Members may be postponed, and any special meeting of the Members may be canceled, by resolution of the Board of Directors upon public notice given prior to the date previously scheduled for such meeting of the Members.

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(b) The Board of Directors shall designate the place of meeting for any annual meeting or for any special meeting of the Members. If no designation is made, the place of meeting shall be the principal office of the Company.

Section 11.5 Record Date. For purposes of determining the Members entitled to notice of or to vote at a meeting of the Members, the Board of Directors may set a Record Date, which shall not be less than 10 nor more than 60 days before the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed for trading, in which case the rule, regulation, guideline or requirement of such exchange shall govern). If no Record Date is fixed by the Board of Directors, the Record Date for determining Members entitled to notice of or to vote at a meeting of Members shall be at the close of business on the day next preceding the day on which notice is given. A determination of Members of record entitled to notice of or to vote at a meeting of Members shall apply to any adjournment or postponement of the meeting; provided, however, that the Board of Directors may fix a new Record Date for the adjourned or postponed meeting.

Section 11.6 Adjournment. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 30 days. At the adjourned meeting, the Company may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 30 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XI.

Section 11.7 Waiver of Notice; Approval of Meeting. Whenever notice to the Members is required to be given under this Agreement, a written waiver, signed by the Person entitled to notice, whether before or after the time stated therein, shall be deemed equivalent to notice. Attendance of a Person at any such meeting of the Members shall constitute a waiver of notice of such meeting, except when the Person attends a meeting for the express purpose of objecting at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Members need be specified in any written waiver of notice unless so required by resolution of the Board of Directors. All waivers and approvals shall be filed with the Company records or made part of the minutes of the meeting.

Section 11.8 Quorum; Required Vote for Member Action; Voting for Directors.

(a) At any meeting of the Members, the holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum of such class or classes unless any such action by the Members requires approval by holders of a greater percentage of Outstanding Units, in which case the quorum shall be such greater percentage. The submission of matters to Members for approval and the election of Directors shall occur only at a meeting of the Members duly called and held in accordance with this Agreement at which a quorum is present; provided, however, that the Members present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Members to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Interests specified in this Agreement. In the absence of a quorum any meeting of Members may be adjourned from time to time by the chairman of the meeting to another place or time.

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(b) Each Outstanding Common Unit shall be entitled to one vote per Unit on all matters submitted to Members for approval and in the election of Directors.

(c) All matters (other than the election of Directors) submitted to Members for approval shall be determined by a majority of the votes cast affirmatively or negatively by Members holding Outstanding Units unless a greater percentage is required with respect to such matter under the Delaware Act, under the rules of any National Securities Exchange on which the Units are listed for trading, or under the provisions of this Agreement, in which case the approval of Members holding Outstanding Units that in the aggregate represent at least such greater percentage shall be required.

(d) Directors will be elected by a plurality of the votes cast for a particular position.

Section 11.9 Conduct of a Meeting; Member Lists.

(a) The Board of Directors shall have full power and authority concerning the manner of conducting any meeting of the Members, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of this Article XI, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The Board of Directors shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Company maintained by the Board of Directors. The Board of Directors may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Members, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes, the submission and examination of proxies and other evidence of the right to vote.

(b) A complete list of Members entitled to vote at any meeting of Members, arranged in alphabetical order for each class of Interests and showing the address of each such Member and the number of Outstanding Units registered in the name of such Member, shall be open to the examination of any Member, for any purpose germane to the meeting, during ordinary business hours, for a period of at least 10 days before the meeting, at the principal place of business of the Company. The Member list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any Member who is present.

Section 11.10 Action Without a Meeting. No action permitted or required to be taken at a meeting of Members may be taken by written consent or by any other means or manner than a meeting of Members called and conducted in accordance with this Agreement.

Section 11.11 Voting and Other Rights.

(a) Only those Record Holders of Outstanding Units on the Record Date set pursuant to Section 11.5 shall be entitled to notice of, and to vote at, a meeting of Members or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Outstanding Units that are held for a Person's account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Outstanding Units are registered, such other Person shall, in

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exercising the voting rights in respect of such Outstanding Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Outstanding Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Company shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 11.11(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

Section 11.12 Proxies and Voting.

(a) At any meeting of the Members, every holder of an Outstanding Unit entitled to vote may vote in person or by proxy authorized by an instrument in writing or by a transmission permitted by law filed in accordance with the procedure established for the meeting. Any copy, facsimile telecommunication or other reliable reproduction of the writing or transmission created pursuant to this paragraph may be substituted or used in lieu of the original writing or transmission for any and all purposes for which the original writing or transmission could be used, provided that such copy, facsimile telecommunication or other reproduction shall be a complete reproduction of the entire original writing or transmission.

(b) The Company may, and to the extent required by law, shall, in advance of any meeting of Members, appoint one or more inspectors to act at the meeting and make a written report thereof. The Company may designate one or more alternate inspectors to replace any inspector who fails to act. If no inspector or alternate is able to act at a meeting of Members, the Person presiding at the meeting may, and to the extent required by law, shall, appoint one or more inspectors to act at the meeting. Each inspector, before entering upon the discharge of his or her duties, shall take and sign an oath faithfully to execute the duties of inspector with strict impartiality and according to the best of his or her ability. Every vote taken by ballots shall be counted by a duly appointed inspector or inspectors.

(c) With respect to the use of proxies at any meeting of Members, the Company shall be governed by paragraphs (b), (c), (d) and (e) of Section 212 of the DGCL and other applicable provisions of the DGCL, as though the Company were a Delaware corporation.

(d) With respect to any contested matter relating to any election, appointment, removal or resignation of any Director, the Company shall be governed by Section 225 of the DGCL and any other applicable provision of the DGCL, as though the Company were a Delaware corporation.

Section 11.13 Notice of Member Business and Nominations.

(a) Subject to Section 7.1(d) of this Agreement, nominations of Persons for election to the Board of Directors of the Company and the proposal of business to be considered by the Members may be made at an annual meeting of Members (i) pursuant to the Company's notice of meeting delivered pursuant to Section 11.4 of this Agreement, (ii) by or at the direction of the Board of Directors, (iii) for nominations to the Board of Directors only, by any holder of Outstanding Units who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraph (b) or (d) of this Section 11.13 [and who was a Record Holder of a sufficient number of Outstanding Units as of the Record Date for such meeting to elect one or more members to the Board of Directors assuming that such holder cast all of the votes it is entitled to cast in such election in favor of a single candidate and such candidate received no other votes from any other holder of Outstanding Units], or (iv) by any holder of Outstanding Units who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraphs (c) or (d) of this Section 11.13 and who is a Record Holder of Outstanding Units at the time such notice is delivered to the Secretary of the Company.

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(b) For nominations to be properly brought before an annual meeting by a Unitholder pursuant to Section 11.13(a)(iii), the Unitholder must have given timely notice thereof in writing to the Secretary of the Company. To be timely, a Unitholder's notice shall be delivered to the Secretary at the principal executive offices of the Company not less than 90 or more than 120 days prior to the first anniversary (the "Anniversary") of the date on which the Company first mailed its proxy materials for the preceding year's annual meeting of Members; provided, however, that if the date of the annual meeting is advanced more than 30 days prior to or delayed by more than thirty (30) days after the anniversary of the preceding year's annual meeting, notice by the Unitholder to be timely must be so delivered not later than the close of business on the later of (x) the ninetieth day prior to such annual meeting or (y) the tenth day following the day on which public announcement of the date of such meeting is first made. Such Unitholder's notice shall set forth: (A) as to each Person whom the Unitholder proposes to nominate for election or reelection as a Director all information relating to such Person that is required to be disclosed in solicitations of proxies for election of Directors, or is otherwise required, in each case pursuant to Regulation 14A under the Exchange Act, including such Person's written consent to being named in the proxy statement as a nominee and to serving as a Director if elected and (B) as to the Unitholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made the name and address of such Unitholder, as they appear on the Company's books, and of such beneficial owner, the class and number of Units of the Company which are owned beneficially and of record by such Unitholder and such beneficial owner. Such holder shall be entitled to nominate as many candidates for election to the Board of Directors as would be elected assuming such holder cast the precise number of votes necessary to elect each candidate and no more votes were cast by such holder or any other holder for such candidates.

(c) For nominations or other business to be properly brought before an annual meeting by a Unitholder pursuant to Section 11.13(a)(iv), (i) the Unitholder must have given timely notice thereof in writing to the Secretary of the Company, (ii) such business must be a proper matter for Member action under this Agreement and the Delaware Act, (iii) if the Unitholder, or the beneficial owner on whose behalf any such proposal or nomination is made, has provided the Company with a Solicitation Notice, such Unitholder or beneficial owner must, in the case of a proposal, have delivered a proxy statement and form of proxy to holders of at least the percentage of the Company's Outstanding Units required under this Agreement or Delaware law to carry any such proposal, or, in the case of a nomination or nominations, have delivered a proxy statement and form of proxy to holders of a percentage of the Company's Outstanding Units reasonably believed by such Unitholder or beneficial holder to be sufficient to elect the nominee or nominees proposed to be nominated by such Unitholder, and must, in either case, have included in such materials the Solicitation Notice and (iv) if no Solicitation Notice relating thereto has been timely provided pursuant to this Section 11.13, the Unitholder or beneficial owner proposing such business or nomination must not have solicited a number of proxies sufficient to have required the delivery of such a Solicitation Notice. To be timely, a Unitholder's notice shall be delivered to the Secretary at the principal executive offices of the Company not less than 90 or more than 120 days prior to the first Anniversary; provided, however, that in the event that the date of the annual meeting is advanced more than thirty (30) days prior to or delayed by more than thirty (30) days after the anniversary of the preceding year's annual meeting, notice by the Unitholder to be timely must be so delivered not later than the close of business on the later of (x) the ninetieth day prior to such annual meeting or (y) the tenth day following the day on which public announcement of the date of such meeting is first made. Such Unitholder's notice shall set forth: (A) as to each

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Person whom the Unitholder proposes to nominate for election or reelection as a Director all information relating to such Person that is required to be disclosed in solicitations of proxies for election of Directors, or is otherwise required, in each case pursuant to Regulation 14A under the Exchange Act, including such Person's written consent to being named in the proxy statement as a nominee and to serving as a Director if elected; (B) as to any other business that the Unitholder proposes to bring before the meeting, a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest in such business of such Unitholder and the beneficial owner, if any, on whose behalf the proposal is made; and (C) as to the Unitholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made the name and address of such Unitholder, as they appear on the Company's books, and of such beneficial owner, the class and number of Units of the Company which are owned beneficially and of record by such Unitholder and such beneficial owner, and whether either such Unitholder or beneficial owner intends to deliver a proxy statement and form of proxy to holders of, in the case of a proposal, at least the percentage of the Company's Outstanding Units required under this Agreement or Delaware law to carry the proposal or, in the case of a nomination or nominations, a sufficient number of holders of the Company's Outstanding Units to elect such nominee or nominees (an affirmative statement of such intent, a "Solicitation Notice").

(d) Notwithstanding anything in the second sentence of Section 11.13(b) or the second sentence of Section 11.13(c) to the contrary, if the number of Directors to be elected to the Board of Directors is increased and there is no public announcement naming all of the nominees for Director or specifying the size of the increased Board of Directors made by the Company at least 90 days prior to the Anniversary, then a Unitholder's notice required by this Section 11.13 shall also be considered timely, but only with respect to nominees for any new positions created by such increase, if it shall be delivered to the Secretary at the principal executive offices of the Company not later than the close of business on the tenth day following the day on which such public announcement is first made by the Company.

(e) Only such business shall be conducted at a special meeting of Members as shall have been brought before the meeting pursuant to the Company's notice of meeting pursuant to Section 11.4 of this Agreement. Subject to Section 7.1(d) of this Agreement, nominations of Persons for election to the Board of Directors may be made at a special meeting of Members at which Directors are to be elected pursuant to the Company's notice of meeting (i) by or at the direction of the Board of Directors, (ii) by any holder of Outstanding Units who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraph (b) or (d) of this Section 11.13 [and who was a Record Holder of a sufficient number of Outstanding Units as of the Record Date for such meeting to elect one or more members to the Board of Directors assuming that such holder cast all of the votes it is entitled to cast in such election in favor of a single candidate and such candidate received no other votes from any other holder of Outstanding Units], or (iii) by any holder of Outstanding Units who is entitled to vote at the meeting, who complies with the notice procedures set forth in this Section 11.13 and who is a Record Holder of Outstanding Units at the time such notice is delivered to the Secretary of the Company. Nominations by Unitholders of Persons for election to the Board of Directors may be made at such a special meeting of Members if the Unitholder's notice as required by Section 11.13(b) or Section 11.13(c) shall be delivered to the Secretary of the Company not earlier than the ninetieth day prior to such special meeting and not later than the close of business on the later of the seventieth day prior to such special meeting or the tenth day following the day on which public

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announcement is first made of the date of the special meeting and of the nominees proposed by the Board of Directors to be elected at such meeting. Holders of Outstanding Units making nominations pursuant to Section 11.13(d)(ii) shall be entitled to nominate the number of candidates for election at such special meeting as provided in Section 11.13(b) for an annual meeting.

(f) Except to the extent otherwise provided in Section 7.1(d) with respect to vacancies, only Persons who are nominated in accordance with the procedures set forth in this Section 11.13 shall be eligible to serve as Directors and only such business shall be conducted at a meeting of Members as shall have been brought before the meeting in accordance with the procedures set forth in this Section 11.13. Except as otherwise provided herein or required by law, the chairman of the meeting shall have the power and duty to determine whether a nomination or any business proposed to be brought before the meeting was made in accordance with the procedures set forth in this Section 11.13 and, if any proposed nomination or business is not in compliance with this Section 11.13, to declare that such defective proposal or nomination shall be disregarded.

(g) Notwithstanding the foregoing provisions of this Section 11.13, a Member shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 11.13. Nothing in this Section 11.13 shall be deemed to affect any rights of Members to request inclusion of proposals in the Company's proxy statement pursuant to Rule 14a-8 under the Exchange Act.

ARTICLE XII
MERGER

Section 12.1 Authority. The Company may merge or consolidate with one or more limited liability companies or "other business entities" as defined in Section 18-209 of the Delaware Act, formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation ("Merger Agreement") in accordance with this Article XII.

Section 12.2 Procedure for Merger or Consolidation. Merger or consolidation of the Company pursuant to this Article XII requires the prior approval of the Board of Directors. If the Board of Directors shall determine to consent to the merger or consolidation, the Board of Directors shall approve the Merger Agreement, which shall set forth:

(a) the names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;

(b) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the "Surviving Business Entity");

(d) the manner and basis of exchanging or converting the rights or securities of, or interests in, each constituent business entity for, or into, cash, property, rights, or securities of or interests in, the Surviving Business Entity; and if any rights or securities of, or interests in, any constituent business entity are not to be exchanged or converted solely for, or into, cash, property, rights, or securities of or interests in, the Surviving Business Entity, the cash, property, rights, or securities of or interests in, any limited liability company or other business entity which the holders of such rights, securities or interests are to receive;

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(e) a statement of any changes in the constituent documents or the adoption of new constituent documents (the certificate of formation or limited liability company agreement, articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(f) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 12.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of the certificate of merger, the effective time shall be fixed no later than the time of the filing of the certificate of merger and stated therein); and

(g) such other provisions with respect to the proposed merger or consolidation that the Board of Directors determines to be necessary or appropriate.

Section 12.3 Approval by Members of Merger or Consolidation.

(a) Except as provided in Section 12.3(d), the Board of Directors, upon its approval of the Merger Agreement, shall direct that the Merger Agreement be submitted to a vote of Members, whether at an annual meeting or a special meeting, in either case in accordance with the requirements of Article XI. A copy or a summary of the Merger Agreement shall be included in or enclosed with the notice of meeting.

(b) Except as provided in Section 12.3(d), the Merger Agreement shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Members, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement.

(c) Except as provided in Section 12.3(d), after such approval by vote or consent of the Members, and at any time prior to the filing of the certificate of merger pursuant to Section 12.4, the merger or consolidation may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement.

(d) Notwithstanding anything else contained in this Article XII or in this Agreement, the Board of Directors is permitted without Member approval, to convert the Company or any Group Member into a new limited liability entity, to merge the Company or any Group Member into, or convey all of the Company's assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Company or other Group Member if (i) the Board of Directors has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Member or any Group Member or cause the Company or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Company into another limited liability entity and (iii) the governing instruments of the new entity provide the Members and the Board of Directors with the same rights and obligations as are herein contained.

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(e) Members are not entitled to dissenters' rights of appraisal in the event of a merger or consolidation pursuant to Section 12.1, a sale of all or substantially all of the assets of the Company or the Company's Subsidiaries, or any other transaction or event.

Section 12.4 Certificate of Merger. Upon the required approval by the Board of Directors and the Unitholders of a Merger Agreement, a certificate of merger shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 12.5 Effect of Merger.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) A merger or consolidation effected pursuant to this Article XII shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

Section 12.6 Business Combination Limitations. Notwithstanding any other provision of this Agreement, with respect to any "Business Combination" (as such term is defined in Section 203 of the DGCL), the provisions of Section 203 of the DGCL shall be applied with respect to the Company as though the Company were a Delaware corporation.

ARTICLE XIII
RIGHT TO ACQUIRE MEMBER INTERESTS

Section 13.1 Right to Acquire Member Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time any Person holds more than 90% of the total Member Interests of any class then Outstanding, such Person shall then have the right, which right it may assign and transfer in whole or in part to the Company or any of its Affiliates, exercisable at its option, to purchase all, but not less than all, of such Member Interests of such class then Outstanding held by other holders, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 13.1(b) is mailed and (y) the highest price paid by such Person or any of its Affiliates for any such Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 13.1(b) is mailed. As used in this Agreement, (i) "Current Market

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Price" as of any date of any class of Interests listed or admitted to trading on any National Securities Exchange means the average of the daily Closing Prices (as hereinafter defined) per Interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) "Closing Price" for any day means the average of the high bid and low asked prices on such day, regular way, or in the case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system for securities listed or admitted for trading on the principal National Securities Exchange on which the units of that class are listed or admitted to trading, or if the units of that class are not listed or admitted for trading on any National Securities Exchange, the last quoted price on that day, or if no quoted price exists, the average of the high bid low asked price on that day in the over-the-counter market, as reported by the Nasdaq National Market or such other system then in use, or, if on any such day such Interests of such class are not quoted by any such organization of that type, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Interests of such class selected by the Board of Directors, or if on any such day no market maker is making a market in such Interests of such class, the fair value of such Interests on such day as determined by the Board of Directors; and (iii) "Trading Day" means a day on which the principal National Securities Exchange on which such Interests of any class are listed or admitted to trading is open for the transaction of business or, if Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

(b) If any Person elects to exercise the right to purchase Interests granted pursuant to Section 13.1(a), the Board of Directors shall deliver to the Transfer Agent notice of such election to purchase (the "Notice of Election to Purchase") and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Interests of such class (as of a Record Date selected by the Board of Directors) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 13.1(a)) at which Interests will be purchased and state that such Person elects to purchase such Interests, upon surrender of Certificates representing such Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the Person exercising the right to purchase hereunder shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Interests to be purchased in accordance with this Section 13.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Interests (including any rights pursuant to Articles IV, V, VI, and X) shall thereupon cease, except the right to receive the purchase price (determined in accordance with

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Section 13.1(a)) for Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Interests, and such Interests shall thereupon be deemed to be transferred to the Person exercising the right to purchase hereunder on the record books of the Transfer Agent and the Company, and such Person shall be deemed to be the owner of all such Interests from and after the Purchase Date and shall have all rights as the owner of such Interests (including all rights as owner of such Interests pursuant to Articles IV, V, VI and X).

(c) At any time from and after the Purchase Date, a holder of an Outstanding Interest subject to purchase as provided in this Section 13.1 may surrender his Certificate evidencing such Interest to the Transfer Agent in exchange for payment of the amount described in Section 13.1(a), therefor, without interest thereon.

(d) Upon the exercise by any Person of the right to purchase Interests granted pursuant to Section 13.1(a), no Member shall be entitled to dissenters' rights of appraisal.

ARTICLE XIV
GENERAL PROVISIONS

Section 14.1 Addresses and Notices. Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Member under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Member at the address described below. Any notice, payment or report to be given or made to a Member hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Company Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Company, regardless of any claim of any Person who may have an interest in such Company Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 14.1 executed by the Company, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Company is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Company of a change in his address) if they are available for the Member at the principal office of the Company for a period of one year from the date of the giving or making of such notice, payment or report to the other Members. Any notice to the Company shall be deemed given if received by the Secretary at the principal office of the Company designated pursuant to Section 2.3. The Board of Directors and the Officers may rely and shall be protected in relying on any notice or other document from a Member or other Person if believed by it to be genuine.

Section 14.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

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Section 14.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 14.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 14.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Company.

Section 14.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 14.7 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Unit, upon accepting the certificate evidencing such Unit.

Section 14.8 Applicable Law. This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware applicable to contracts executed and to be performed solely in such state.

Section 14.9 Invalidity of Provisions. If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 14.10 Consent of Members. Each Member hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Members, such action may be so taken upon the concurrence of less than all of the Members and each Member shall be bound by the results of such action.

Remainder of page intentionally left blank.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

		Michael C. Linn
		Gerald W. Merriam
		Roland P. Keddie
		QUANTUM ENERGY PARTNERS II, LP
		By:		its General Partner
		By:
		Name:
		Title:
		CLARK PARTNERS I, L.P.
		By:		its General Partner
		By:
		Name:
		Title:

Signature Page to Second Amended and Restated
Limited Liability Company Agreement

		KINGS HIGHWAY INVESTMENT, LLC
		By:
		Name:
		Title:
		WAUWINET ENERGY PARTNERS, LLC
		By:
		Name:
		Title:
		MEMBERS:
		All Members now and hereafter admitted as Members of the Company, pursuant to powers of attorney now and hereafter executed in favor of, and granted and delivered to, the Board of Directors.

Signature Page to Second Amended and Restated
Limited Liability Company Agreement

EXHIBIT A
to the Second Amended and
Restated Agreement of Limited Liability Company of
Linn Energy, LLC

Certificate Evidencing Common Units
Representing Member Interests in
Linn Energy, LLC

No. [ ] [ ] Common Units

In accordance with Section 4.1 of the Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC, as amended, supplemented or restated from time to time (the "Company Agreement"), Linn Energy, LLC, a Delaware limited liability company (the "Company"), hereby certifies that [ ] (the "Holder") is the registered owner of Common Units representing Interests in the Company (the "Common Units") transferable on the books of the Company, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Company Agreement. Copies of the Company Agreement are on file at, and will be furnished without charge on delivery of written request to the Company at, the principal office of the Company located at 1700 North Highland Road, Suite 100, Pittsburgh, Pennsylvania 15241 or such other address as may be specified by notice under the Company Agreement. Capitalized terms used herein but not defined shall have the meanings given them in the Company Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Member and to have agreed to comply with and be bound by and to have executed the Company Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Company Agreement, (iii) granted the powers of attorney provided for in the Company Agreement and (iv) made the waivers and given the consents and approvals contained in the Company Agreement.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

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Reverse of Certificate

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

TEN COM—	as tenants in common	UNIF GIFT/TRANSFERS MIN ACT
TEN ENT—	as tenants by the entireties		Custodian

		(Cust)		(Minor)
JT TEN—	as joint tenants with right of survivorship and not as tenants in common	under Uniform Gifts/Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

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ASSIGNMENT OF COMMON UNITS
in
LINN ENERGY, LLC

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto

(Please print or typewrite name
and address of Assignee)

(Please insert Social Security or other
identifying number of Assignee)

Common Units representing Member Interests evidenced by this Certificate, subject to the Company Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of Linn Energy, LLC.

Date:				NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
SIGNATURE(S) MUST BE GUARANTEED BY A MEMBER FIRM OF THE NATIONAL ASSOCIATION OF SECURITIES DEALERS, INC. OR BY A COMMERCIAL BANK OR TRUST COMPANY SIGNATURE(S) GUARANTEED				(Signature)
				(Signature)

No transfer of the Common Units evidenced hereby will be registered on the books of the Company, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration of transfer.

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EXHIBIT B
to the Second Amended and
Restated Agreement of Limited Liability Company of
Linn Energy, LLC

Existing Investor		Common Units Received in Exchange
Quantum Energy Partners II, LP		[ ] Common Units
Clark Partners I, L.P.		[ ] Common Units
Kings Highway Investment, LLC		[ ] Common Units
Wauwinet Energy Partners, LLC		[ ] Common Units
Michael C. Linn		[ ] Common Units
Gerald W. Merriam		[ ] Common Units
Roland P. Keddie		[ ] Common Units

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APPENDIX B

GLOSSARY OF TERMS

The following are abbreviations and definitions of terms commonly used in the natural gas and oil industry that are used in this prospectus.

Acquisitions. Refers to acquisitions, mergers or exercise of preferential rights of purchase.

Available Cash means, for any quarter prior to liquidation:

(a) the sum of:

(i) all cash and cash equivalents of Linn Energy on hand at the end of that quarter; and

(ii) all additional cash and cash equivalents of Linn Energy on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made subsequent to the end of the quarter,

(b) less the amount of any cash reserves established by the board of directors to

(i) provide for the proper conduct of the business of Linn Energy (including reserves for future capital expenditures including drilling and acquisitions and for anticipated future credit needs),

(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which Linn Energy or any of its subsidiaries is a party or by which it is bound or its assets are subject; or

(iii) provide funds for distributions with respect to any one or more of the next four quarters.

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

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

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

dth. Ten therms, one million British thermal units.

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

Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

B-1

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

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

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

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

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfe/d. One MMcfe per day.

MMMBtu. One billion British thermal units.

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

NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proppant. Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional natural gas and oil expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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Proved reserves. Proved natural gas and oil reserves are the estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

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

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Standardized measure. The estimated future cash flows from natural gas and oil properties, taking into account all anticipated future costs of production, development and abandonment, and taking into account expected income tax liabilities, discounted to present value using a 10% discount rate. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Linn Energy Holdings, LLC, which is not subject to income taxes.

Successful well. A well capable of producing natural gas and/or oil in commercial quantities.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

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

Workover. Operations on a producing well to restore or increase production.

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APPENDIX C

RESERVE REPORT

Data & Consulting Services Division of Schlumberger Technology Corporation
1310 Commerce Drive Park Ridge 1 Pittsburgh, PA 15275-1011 Tel: 412-787-5403 Fax: 412-787-2906
07 November, 2005
Linn Energy, LLC 650 Washington Road Pittsburgh, PA 15228

Dear Gentlemen:

At the request of Linn Energy, LLC (Linn Energy), Schlumberger Data & Consulting Services (DCS) has prepared a reserve and economic evaluation of certain proved oil and gas interests as of September 30, 2005. These properties are located in various counties of New York, Pennsylvania, Virginia, and West Virginia. Unescalated September 30, 2005 Spot pricing was used for all properties contained in this evaluation. All properties were evaluated to economic limit or a maximum future well life of 50 years. The economics presented are before federal income taxes (BFIT). The results of the Proved reserve evaluation are summarized in Table 1. Fig. 1 illustrates the distribution by Proved reserve category for the present value at a 10% discount rate (PV10). Attachment 1 contains the summary level cash flows by reserve category and Attachment 2 contains a oneline report with the well results. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report.

TABLE 1

ESTIMATED NET RESERVES & INCOME
CERTAIN PROVED OIL AND GAS INTERESTS
SEC PRICING & ESCALATION
LINN ENERGY, LLC
AS OF SEPTEMBER 30, 2005

		Proved Producing Reserves	Proved Non-producing Reserves	Proved Undeveloped Reserves	Total Proved Reserves
Remaining Net Reserves
Oil — Mbbls		234.728	0.000	0.000	234.728
Gas — MMscf		119,378.516	4,079.525	64,720.543	188,178.609
Income Data (M$)
Future Net Revenue		1,962,686.625	63,906.520	1,071,192.375	3,097,785.500
Deductions
	Operating Expense	199,310.531	2,732.935	44,714.277	246,757.750
	Production Taxes	94,421.496	4,365.427	46,204.917	144,991.848
	Investment	10,238.593	146.370	84,851.781	95,236.750
	Future Net Cash Flow	1,658,715.875	56,661.793	895,421.500	2,610,799.250
Discounted PV @ 10% (M$)		600,443.688	22,385.842	275,859.438	898,689.000

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Fig. 1 — Present value distribution by Proved reserve category — calculated using a
10% discount rate (MM$), SEC unescalated prices and costs.

The values in the tables above may not add up arithmetically or exactly match the attached cash flows due to rounding procedures in the computer software program used to prepare the economic projections.

RESERVES ESTIMATES

Conventional decline curve analysis and production data analysis methods were used to generate the performance forecast of the producing wells included in this report. Decline curves were completed using ARIES™, an industry-accepted reserve evaluation and economic software package. Linn Energy provided all production data in an ARIES™ database or Excel spreadsheet. Offset analog well production was used to forecast the production for all non-producing or undeveloped wells. Linn Energy provided maps with the proposed drilling locations for each undeveloped location. No adjustments were made to gas volumes to account for non-hydrocarbon gases such as nitrogen or CO₂.

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision.

RESERVE CATEGORIES

Reserves were assigned to the proved developed producing (PDP), proved developed non-producing (PDNP), and proved undeveloped (PUD) reserve categories. Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and

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non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The proved reserves evaluated in this report conform to the Securities and Exchange Commission Regulation S-X, Rule 4-10 (a). These reserve definitions are presented in Exhibit 1 of this report.

We included in the proved undeveloped category only reserves assigned to undeveloped locations Linn Energy has plans to drill in the next three years. Linn Energy has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of significant volumes to the proved reserve category.

The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

ECONOMIC TERMS

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and natural gas before any deductions. Future net cashflow is future net revenue less net lease operating, transportation, processing, and marketing expenses, and state severance or production taxes. Field level general and administrative (G&A) expenses are deducted from future net income (cashflow) for all wells. These G&A expenses are charged to each particular well or unit on a monthly basis as part of the fixed operating costs. Future plugging, abandonment, and salvage costs are included in this report. No provisions for State or Federal income taxes are made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

PRICING AND ECONOMIC PARAMETERS

Linn Energy provided all pricing and economic parameters used in this evaluation. Prices and costs were unescalated. All properties were evaluated to economic limit or a maximum future well life of 50 years. The prices used in this report were based on the September 30, 2005 Spot prices adjusted for local differentials, gravity and Btu where applicable. Linn Energy sells gas into the TCO and DTI systems at approximately equal volumes. The TCO spot for the 30th was $15.405/MMBtu and the DTI spot was $15.305/MMBtu. An average gas price $15. 355/MMBtu was used for all gas production exclusive of gas contracts. Existing gas contracts were honored. Adjustments were made for transportation, treating, or gathering costs based on actual data. The September 30, 2005 oil spot price was $66.21/Bbl.

The operating costs were modeled as a fixed per well monthly operating expense, a variable operating cost for gas, and a variable water expense where applicable. The fixed and variable costs were determined from actual averages for the wells. Field level overhead was included in the operating cost for each well. Severance and ad valorem production taxes were included in this evaluation. Capital costs for the undeveloped wells were based on an average of the estimated costs for future wells in each state. A future abandonment cost of $7,000 per well was included in the cash flow projections at the life of the wells.

OWNERSHIP

The leasehold interests were supplied by Linn Energy and were accepted as presented. No attempt was made by the undersigned to verify the title or ownership of the interests evaluated.

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GENERAL

All data used in this study were obtained from Linn Energy, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report.

The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization by Linn Energy.

This report was prepared solely for the use of the party to whom it is addressed and any disclosure made of this report and/or the contents by said party thereof shall be solely the responsibility of said party, and shall in no way constitute any representation of any kind whatsoever of the undersigned with respect to the matters being addressed.

We appreciate the opportunity to perform this evaluation and are available should you need further assistance in this matter.

Sincerely yours,

Joseph H. Frantz, Jr., P.E. Consulting Services Operations Manager U.S. Land East		Denise L. Delozier Senior Engineer

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Linn Energy, LLC

11,750,000 Units

Representing Limited Liability Company Interests

P R O S P E C T U S

RBC CAPITAL MARKETS

LEHMAN BROTHERS

A.G. EDWARDS

UBS INVESTMENT BANK

KEYBANC CAPITAL MARKETS

, 2006

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the Nasdaq National Market listing fee, the amounts set forth below are estimates.

SEC registration fee	$	33,399
NASD filing fee		28,877
Nasdaq National Market listing fee		107,500
Printing and engraving expenses		450,000
Accounting fees and expenses		*
Legal fees and expenses		*
Transfer agent and registrar fees		5,000
Miscellaneous		10,000

Total	$	*

*: To be provided by amendment.

Item 14. Indemnification of Directors and Officers.

The section of the prospectus entitled "The Limited Liability Company Agreement — Indemnification" discloses that we will generally indemnify officers and members of our board of directors to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to Section of the Underwriting Agreement to be filed as an exhibit to this registration statement in which we will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other persons from and against all claims and demands whatsoever.

To the extent that the indemnification provisions of our limited liability company agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities.

In connection with our formation in April 2005, we issued membership interests representing the right to receive an aggregate 100% of our distributions to Quantum Energy Partners II, LP, Clark Partners I, L.P., Kings Highway Investment, LLC, Wauwinet Energy Partners, LLC and Nemacolin Resources, L.L.C. The offering was exempt from registration under Section 4(2) of the

II-1

Securities Act because the transaction did not involve a public offering. The following table summarizes the offering:

Purchaser	Purchase Price		Percentage Sharing Ratio Represented by Membership Interests Purchased
Quantum Energy Partners II, LP	$	15.0 million	91.891	%
Clark Partners I, L.P.	$	356,971	2.187	%
Kings Highway Investment, LLC	$	22,132	0.136	%
Wauwinet Partners, LLC	$	7,139	0.044	%
Nemacolin Resources, L.L.C.(1)	$	937,500	5.743	%

(1): Controlled by Michael C. Linn, Gerald W. Merriam and Roland P. Keddie.

II-2

Item 16. Exhibits and Financial Statement Schedules.

(a): The following documents are filed as exhibits to this registration statement:

Exhibit Number		Description
1.1*	—	Form of Underwriting Agreement
3.1†	—	Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC)
3.2†	—	Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC)
3.3†	—	Form of Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (included as Appendix A to the Prospectus and including specimen unit certificate for the units)
5.1†	—	Opinion of Andrews Kurth LLP as to the legality of the securities being registered
8.1†	—	Opinion of Andrews Kurth LLP relating to tax matters
10.1†	—	Credit Agreement dated as of April 11, 2005, among Linn Energy, LLC (f/k/a Linn Energy Holdings, LLC), the Lenders from time to time party thereto, BNP Paribas, as administrative agent, and Royal Bank of Canada, as syndication agent
10.2†	—	First Amendment and Consent to Credit Agreement dated as of May 3, 2005, among Linn Energy, LLC (f/k/a Linn Energy Holdings, LLC), the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent
10.3†	—	Second Amendment to Credit Agreement dated as of August 12, 2005, among Linn Energy, LLC, the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent
10.4†	—	Letter Agreement dated as of August 24, 2005, among Linn Energy, LLC, the Lenders signatory thereto and BNP Paribas, as administrative agent
10.5†	—	Third Amendment to Credit Agreement dated as of October 27, 2005, among Linn Energy, LLC, the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent
10.6†	—	Second Lien Senior Subordinated Term Loan Agreement dated as of October 27, 2005, among Linn Energy, LLC, Royal Bank of Canada, as administrative agent, Societe Generale, as syndication agent, and the Lenders signatory thereto
10.7†	—	First Amendment to Credit Agreement and Consent dated as of November 22, 2005, among Linn Energy, LLC, Royal Bank of Canada, as administrative agent, and the Lenders signatory thereto
10.8†	—	Intercreditor and Subordination Agreement dated as of October 27, 2005, among Linn Energy, LLC, Royal Bank of Canada, as subordinated administrative agent, and BNP Paribas, as administrative agent for the senior revolving lenders
10.9†	—	Form of Asset Purchase Agreement dated as of October 1, 2005, between Exploration Partners, LLC and others, as Seller, and Linn Energy Holdings, LLC and others, as Purchaser
10.10	—	Form of Linn Energy, LLC Long-Term Incentive Plan
10.11†	—	Stakeholders' Agreement
10.12	—	Amended and Restated Employment Agreement, dated as of December 14, 2005 between Linn Operating, Inc. and Michael C. Linn

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10.13†	—	Second Amended and Restated Employment Agreement, dated as of September 15, 2005 between Linn Operating, Inc. and Kolja Rockov
21.1†	—	List of subsidiaries of Linn Energy, LLC
23.1	—	Consent of KPMG LLP for Linn Energy, LLC
23.2	—	Consent of KPMG LLP for Waco Properties
23.3	—	Consent of Toothman Rice, PLLC
23.4	—	Consent of Elms, Faris & Co., LP
23.5	—	Consent of Hantzmon Wiebel LLP
23.6	—	Consent of Schlumberger Data and Consulting Services
23.7†	—	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
23.8†	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
24.1†	—	Powers of Attorney
99.1†	—	Consent of George A. Alcorn
99.2†	—	Consent of Terrence S. Jacobs
99.3†	—	Consent of Jeffrey C. Swoveland

*: To be filed by amendment.
†: Previously filed.

Item 17. Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction of the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Pittsburgh, State of Pennsylvania, on December 14, 2005.

		LINN ENERGY, LLC
		By:		/s/ MICHAEL C. LINN Michael C. Linn President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.

Name	Title	Date

/s/ MICHAEL C. LINN Michael C. Linn	President and Chief Executive Officer and Director (Principal Executive Officer)	December 14, 2005
/s/ KOLJA ROCKOV Kolja Rockov	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	December 14, 2005
* Donald T. Robinson	Chief Accounting Officer (Principal Accounting Officer)
* Toby R. Neugebauer	Chairman

*By:

/s/ KOLJA ROCKOV

Kolja Rockov
Attorney-in-Fact

December 14, 2005

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EXHIBIT INDEX

Exhibit Number		Description
1.1*	—	Form of Underwriting Agreement
3.1†	—	Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC)
3.2†	—	Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC)
3.3†	—	Form of Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (included as Appendix A to the Prospectus and including specimen unit certificate for the units)
5.1†	—	Opinion of Andrews Kurth LLP as to the legality of the securities being registered
8.1†	—	Opinion of Andrews Kurth LLP relating to tax matters
10.1†	—	Credit Agreement dated as of April 11, 2005, among Linn Energy, LLC (f/k/a Linn Energy Holdings, LLC), the Lenders from time to time party thereto, BNP Paribas, as administrative agent, and Royal Bank of Canada, as syndication agent
10.2†	—	First Amendment and Consent to Credit Agreement dated as of May 3, 2005, among Linn Energy, LLC (f/k/a Linn Energy Holdings, LLC), the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent
10.3†	—	Second Amendment to Credit Agreement dated as of August 12, 2005, among Linn Energy, LLC, the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent
10.4†	—	Letter Agreement dated as of August 24, 2005, among Linn Energy, LLC, the Lenders signatory thereto and BNP Paribas, as administrative agent
10.5†	—	Third Amendment to Credit Agreement dated as of October 27, 2005, among Linn Energy, LLC, the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent
10.6†	—	Second Lien Senior Subordinated Term Loan Agreement dated as of October 27, 2005, among Linn Energy, LLC, Royal Bank of Canada, as administrative agent, Societe Generale, as syndication agent, and the Lenders signatory thereto
10.7†	—	First Amendment to Credit Agreement and Consent dated as of November 22, 2005, among Linn Energy, LLC, Royal Bank of Canada, as administrative agent, and the Lenders signatory thereto
10.8†	—	Intercreditor and Subordination Agreement dated as of October 27, 2005, among Linn Energy, LLC, Royal Bank of Canada, as subordinated administrative agent, and BNP Paribas, as administrative agent for the senior revolving lenders
10.9†	—	Form of Asset Purchase Agreement dated as of October 1, 2005, between Exploration Partners, LLC and others, as Seller, and Linn Energy Holdings, LLC and others, as Purchaser
10.10	—	Form of Linn Energy, LLC Long-Term Incentive Plan
10.11†	—	Stakeholders' Agreement
10.12	—	Amended and Restated Employment Agreement, dated as of December 14, 2005 between Linn Operating, Inc. and Michael C. Linn
10.13†	—	Second Amended and Restated Employment Agreement, dated as of September 15, 2005 between Linn Operating, Inc. and Kolja Rockov

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21.1†	—	List of subsidiaries of Linn Energy, LLC
23.1	—	Consent of KPMG LLP for Linn Energy, LLC
23.2	—	Consent of KPMG LLP for Waco Properties
23.3	—	Consent of Toothman Rice, PLLC
23.4	—	Consent of Elms, Faris & Co., LP
23.5	—	Consent of Hantzmon Wiebel LLP
23.6	—	Consent of Schlumberger Data and Consulting Services
23.7†	—	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
23.8†	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
24.1†	—	Powers of Attorney
99.1†	—	Consent of George A. Alcorn
99.2†	—	Consent of Terrence S. Jacobs
99.3†	—	Consent of Jeffrey C. Swoveland

*: To be filed by amendment.
†: Previously filed.

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We intend to make an initial quarterly distribution of $0.40 per unit to the extent we have sufficient available cash. The amount of available cash, if any, at the end of any quarter may be greater than or less than the aggregate initial quarterly distribution to be distributed on all units.

Based on the assumptions and considerations included in "Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations" of this prospectus, absent expected borrowings of $17.9 million under our credit facility, we would experience a shortfall of that amount in the cash necessary to allow us, together with cash generated from operations, to fund our drilling program and to pay the initial quarterly distribution of $0.40 on all units for each quarter through December 31, 2006. The amount borrowed would constitute approximately 40.2% of the aggregate annual distribution of $44.5 million. The amount of borrowings available is dependent upon the borrowing base, which is in the sole discretion of the lenders. Please read "Risk Factors — Risks Related to Our Business — Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions" on page 26. If we had completed the transactions contemplated in this prospectus on January 1, 2004, pro forma available cash generated during the year ended December 31, 2004 would have been approximately $3.6 million. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 8% of the initial quarterly distributions on our units during this period. If we had completed the transactions contemplated in this prospectus on October 1, 2004, pro forma cash available to pay distributions generated during the twelve-month period ended September 30, 2005 would have been approximately $0.2 million. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 1% of the initial quarterly distributions on our units during this period. For a calculation of our ability to make distributions to you based on our pro forma results for the year ended December 31, 2004, please read "Cash Distribution Policy and Restrictions on Distributions" included elsewhere in this prospectus.