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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on June 3, 2005

Registration No. 333-

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

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)
1700 North Highland Road, Suite 100 Pittsburgh, Pennsylvania 15241 (412) 854-0470 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)
Michael C. Linn Linn Energy, LLC 1700 North Highland Road, Suite 100 Pittsburgh, Pennsylvania 15241 (412) 854-0470 (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

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee


Units representing limited liability company interests	$133,066,500	$15,662

(1): Includes units issuable upon exercise of the underwriters' over-allotment option.
(2): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.

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 June 3, 2005

PROSPECTUS

Linn Energy, LLC
5,510,000 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 make an initial quarterly distribution of available cash of $ per unit, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses. 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 to pay the initial quarterly distribution in each quarter following establishment of cash reserves and payment of fees and expenses.
•: Natural gas prices are volatile and a decline in natural gas prices can significantly affect our financial results and impede our growth.
•: 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.
•: Our management and Quantum Energy Partners will own, in the aggregate, a controlling interest in us, with management and Quantum Energy Partners owning approximately 19.1% and 45.4%, 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 $17.92 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 , 2005. We have granted the underwriters a 30-day option to purchase up to an additional 826,500 units on the same terms and conditions as set forth in this prospectus to cover over-allotments of units, if any.

Joint Book-Running Managers

RBC CAPITAL MARKETS

LEHMAN BROTHERS

A.G. EDWARDS

KEYBANC CAPITAL MARKETS

, 2005

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 Measures
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
	Quarterly Distributions of Available Cash
	Distributions of Cash Upon Liquidation
CASH AVAILABLE FOR DISTRIBUTION
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
	New Accounting Pronouncements
	Quantitative and Qualitative Disclosure About Market Risk
	Commodity Price Risk
	Interest Rate Risks
BUSINESS
	Overview
	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	—	Estimated Available Cash	C-1
APPENDIX D	—	Reserve Report	D-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 , 2005 (25 days after the date of this prospectus), all dealers that buy, sell or trade our units, 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' over-allotment option 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 & Consulting Services, an independent engineering firm, provided the estimates of proved natural gas and oil reserves as of December 31, 2004 included in this prospectus. These estimates are contained in a summary prepared by Schlumberger of its reserve report as of December 31, 2004 for the properties described below. This summary is located at the back of this prospectus as Appendix D 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 that increase distributable cash flow per unit. 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 seven acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate purchase price of $82.5 million, with total proved reserves of 100.9 Bcfe, or an acquisition cost of $0.82 per Mcfe. Our seven acquisitions included 1,234 producing wells and we have subsequently drilled 126 wells with a success rate of 100%. At May 31, 2005, our production was approximately 12.8 MMcfe per day from 1,360 wells.

Our proved reserves at December 31, 2004 were 119.8 Bcfe, of which approximately 98% were natural gas and 62% were classified as proved developed. At May 31, 2005, we operated 1,303, or 96%, of our 1,360 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 30 years based on our 2004 year end reserve report and annualized production for the quarter ended March 31, 2005. As of December 31, 2004, we had identified 235 proved undeveloped drilling locations and 461 additional drilling locations and had a leasehold interest in 104,805 net acres in the Appalachian Basin, 77% of which have additional drilling potential. From inception through December 31, 2004, we added 17.2 Bcfe of proved natural gas and oil reserves through our drilling activities, at a finding and development cost of $0.99 per Mcfe.

Drilling

Most of our wells are relatively shallow, ranging from 2,500 to 5,500 feet, and many are completed to multiple producing zones. Our average well cost for 2005 is expected to be approximately $200,000, 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.

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 December 31, 2004, we spent $17.0 million and drilled 90 wells, all of which produce in commercial quantities, with an average finding and development cost of $0.99 per Mcfe. 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 $20.2 million to drill 106 wells, 100 of which we will operate. As of May 31, 2005, we had drilled 36 out of our planned 106 wells.

Acquisition History

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 seven acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate purchase price of $82.5 million, with total proved reserves of 100.9 Bcfe, or an acquisition cost of $0.82 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

	Total	1,234		$	82.5

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 Mcfe, 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 Mcfe 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 exclusively use fixed price swaps to hedge NYMEX natural gas prices, which do not include the additional net premium we typically realize in the Appalachian Basin. For the twelve month period ending September 30, 2006, we currently have fixed price swaps in place for a total hedged amount of 4,931 MMMBtu, which represents approximately 79% of our total expected production volume of 6,226 MMcfe. The average hedge price is $7.53 per MMBtu. We currently have entered into fixed price swaps for a total hedged amount of 4,952 MMMBtu at an average price of $7.47 per MMBtu for 2006 and 4,528 MMMBtu at an average price of $7.03 per MMBtu for 2007. 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 350 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 46 miles of natural gas gathering systems. We transport our natural gas as well as a limited amount for third parties.

Business Strategy

Our goal is to provide stability and growth in distributions to our unitholders through a combination of continued successful drilling and acquisitions that increase distributable cash per unit. The key elements of our business strategy are:

•: Executing low risk, low cost exploitation drilling;
•: Focusing on acquisitions that increase distributable cash per unit;
•: 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 May 31, 2005, we drilled 126 wells with a success rate of 100%. From inception through December 31, 2004, our average finding and development cost was $0.99 per Mcfe. Our average well takes five days to drill and is expected to have an average cost of $200,000 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 seven acquisitions with an average purchase price of $0.82 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 due to the large number of small owner/operators in the region.
•: Large Undeveloped Land Base — At December 31, 2004, we had leases totaling 104,805 net acres with 235 identified proved undeveloped drilling locations and 461 additional identified drilling locations. We continually seek to acquire new lease positions to increase potential drilling locations.
•: Operating Control — As of May 31, 2005, we operated 1,303, or 96%, of our total 1,360 producing wells and we will operate 100 of the 106 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 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.
•: Long Life Reserves — Our average reserve life is 30 years based on our 2004 year end reserves and annualized production for the quarter ended March 31, 2005.
•: Production Diversification — At May 31, 2005, our production was approximately 12.8 MMcfe per day from 1,360 producing wells from four states in the Appalachian Basin, including 771 wells in Pennsylvania, 517 wells in West Virginia, 61 wells in New York and 11 wells in Virginia. Our largest well accounts for less than 2% 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 operating results and 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 Mcfe 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.

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 to pay the initial quarterly distribution in each quarter following establishment of cash reserves and payment of fees and expenses.
•: If we are unable to achieve the forecast results set forth in "Cash Available for Distribution," 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.
•: Natural gas prices are volatile and a decline in natural gas prices can significantly affect our financial results and impede our growth.
•: 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 in our businesses, 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 19.1% and 45.4%, 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 $17.92 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, regulated investment companies 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) and Chipperco, LLC. We own, directly or indirectly, all of the ownership interests in our operating subsidiaries.

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 $60.0 million of membership interests from Quantum Energy Partners, $1.5 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 3,064,917 units, representing an aggregate 19.1% membership interest in us;
•: Quantum Energy Partners will own 7,296,038 units, representing an aggregate 45.4% membership interest in us; and
•: the public unitholders will own 5,510,000 units, representing an aggregate 34.3% membership interest in us.

We will use any net proceeds from the exercise of the underwriters' over-allotment option 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 over-allotment option. If the over-allotment option is exercised in full, Quantum Energy Partners' ownership of units will be reduced from 7,296,038 units to 6,490,286 units, or 40.4% of all then outstanding units, and the ownership interest of the public unitholders will increase to 6,336,500, or 39.5% 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 manages 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 1700 North Highland Road, Suite 100, Pittsburgh, Pennsylvania 15241, and our telephone number is (412) 854-0470. We also maintain a corporate office at 600 Travis, Suite 6910, Houston, Texas 77002, and our Houston telephone number is (713) 223-0880.

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

(1): Does not include 187,869 units (or 1.2% 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 over-allotment option is exercised in full, Quantum Energy Partners' ownership in us will be reduced to 6,490,286 units, or 40.4% of all outstanding units, and the ownership interest of the public unitholders will increase to 6,336,500 units, or 39.5% of all then outstanding units.

THE OFFERING

Units offered by us	5,510,000 units.
	6,336,500 units if the underwriters exercise their over-allotment option in full.
Units outstanding after this offering	16,058,824 units.
Use of proceeds	We anticipate using the net proceeds of $102.5 million from this offering to:
		•	repay $35.0 million of the indebtedness outstanding under our revolving credit facility;
		•	redeem $60.0 million of membership interests from Quantum Energy Partners;
		•	redeem $1.5 million of membership interests from certain non-affiliated investors;
		•	redeem $3.0 million of membership interests from Michael C. Linn; and
		•	pay $2.9 million of expenses associated with this offering. Please read "Use of Proceeds."
	The $2.9 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' over-allotment option 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 over-allotment option. If the over-allotment option is exercised in full, Quantum Energy Partners' ownership of units will be reduced from 7,296,038 units to 6,490,286 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 management 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.
	We intend to make an initial quarterly distribution of $ 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.
	The amount of estimated available cash generated during 2004 would have been sufficient to allow us to pay approximately % of the initial quarterly distribution on all of the units during this period. Please read "Cash Available for Distribution" and Appendix C to this prospectus for the calculation of our ability to have paid the initial quarterly distribution during this period.
	Based on the forecast included in "Cash Available for Distribution" and the assumptions described therein, we believe that we will have sufficient available cash to enable us to make the initial quarterly distribution of $ per unit on all outstanding units for each quarter through September 30, 2006.
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 % of the cash distributed to you with respect to that period. Please read "Material Tax Consequences — Tax Consequences of Unit Ownership" beginning on page 114 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. 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 quarters ended March 31, 2004 and 2005 and the balance sheet data as of March 31, 2005 are derived from our unaudited financial statements included in this prospectus. The pro forma financial data gives effect to the properties acquired from Mountain V Oil & Gas, Inc. and Pentex Energy, Inc. in 2004 as if they occurred on January 1, 2004. 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, distributable cash flow, 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.

												Quarter Ended March 31,
			Period from March 14, 2003 (inception) through December 31, 2003			Year Ended December 31, 2004						Quarter Ended March 31,
						Historical			Pro Forma			2004			2005
									(unaudited)			(unaudited)
			(in thousands)
Statement of Operations Data:
Revenues:
	Natural gas and oil sales		$	3,323		$	21,232		$	24,154		$	3,955		$	6,146
	Realized gain (loss) on natural gas swaps(1)			163			(2,240	)		(2,240	)		(170	)		(8,575	)
	Unrealized (loss) on natural gas swaps(2)			(1,600	)		(8,765	)		(8,765	)		(2,683	)		(6,580	)
	Natural gas marketing income			—			520			520			—			814
	Other income			4			160			160			20			74

		Total revenue		1,890			10,907			13,829			1,122			(8,121	)

Expenses:
	Operating expenses			917			5,460			6,139			1,145			1,834
	Natural gas marketing expense			—			482			482			—			790
	General and administrative expenses			845			1,583			1,624			220			490
	Depreciation, depletion and amortization			972			3,749			4,478			572			1,046

		Total expenses		2,734			11,274			12,723			1,937			4,160

Other Income and (Expenses):
	Interest income			34			7			7			3			—
	Interest and financing expenses(3)			(517	)		(3,530	)		(4,150	)		(823	)		20
	Investment (loss)			(3	)		(56	)		(56	)		(14	)		(10	)
	(Loss) on sale of assets			(5	)		(32	)		(32	)		—			(22	)

				(491	)		(3,611	)		(4,231	)		(834	)		(12	)

Net (loss)			$	(1,335	)	$	(3,978	)	$	(3,125	)	$	(1,649	)	$	(12,293	)

(1): During the quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the money natural gas swaps for the fourth quarter of 2005, and the years ending December 31, 2006 and 2007, and realized a loss of $8.0 million. We subsequently hedged similar volumes at higher prices.
(2): The natural gas swaps that were established in 2003 and 2004, 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. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. Further, these amounts represent non-cash charges.
(3): 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 in our current earnings. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. Further, these amounts represent non-cash items.

	Period from March 14, 2003 (inception) through December 31, 2003
							Quarter Ended March 31,
				Year Ended December 31, 2004			Quarter Ended March 31,
				Year Ended December 31, 2004			2004			2005
							(unaudited)
	(in thousands)
Cash Flow Data:
Net cash provided (used in) by operating activities	$	929		$	11,381		$	1,595		$	(7,138	)
Net cash used in investing activities		(36,408	)		(62,402	)		(20,612	)		(1,801	)
Net cash provided by financing activities		57,521			31,167			—			7,971
Capital expenditures	$	52,356		$	47,508		$	4,791		$	1,782
Other Financial Information (unaudited):
Distributable cash flow	$	1,469		$	10,080		$	2,122		$	2,457

		As of December 31,				As of March 31,
		2003		2004		2005
						(unaudited)
		(in thousands)
Balance Sheet Data:
Cash and cash equivalents(1)		$	22,043	$	2,188	$	1,220
Other current assets			1,714		5,094		4,558
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization			53,036		97,123		97,886
Property, plant and equipment, net of accumulated depreciation			370		1,387		1,317
Other assets			2,486		542		606

	Total assets	$	79,649	$	106,334	$	105,587

Current liabilities		$	20,319	$	9,968	$	12,659
Long-term debt			41,518		72,750		80,766
Other long-term liabilities			3,123		12,905		13,744
Members' capital			14,689		10,711		(1,582	)

	Total liabilities and members' capital	$	79,649	$	106,334	$	105,587

(1): 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 D) 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,
			2003			2004
Reserve Data:
Estimated net proved reserves(1):
	Natural gas (Bcf)			68.9			118.9
	Oil (MMBbls)			0.2			0.1
		Total (Bcfe)		69.8			119.8
Proved developed (Bcfe)				41.8			74.4
Proved undeveloped (Bcfe)				28.0			45.4
Proved developed reserves as a percentage of total proved reserves				59.9	%		62.1	%
PV-10 (in millions)(2)			$	126.3		$	215.0
Representative Natural Gas and Oil Prices(3):
	Natural gas — NYMEX Henry Hub per MMBtu		$	5.97		$	6.18
	Oil — NYMEX WTI per Bbl			32.76			43.00

		Period from March 14, 2003 (inception) through December 31, 2003(4)
						Quarter Ended March 31,
				Year Ended December 31, 2004		Quarter Ended March 31,
				Year Ended December 31, 2004		2004		2005
Net Production:
	Total production (MMcfe)		802		3,385		639		977
	Average daily production (Mcfe/d)		3,748		9,274		7,100		10,856
Average Sales Prices per Mcfe:
	Average sales prices (including hedges)	$	5.07	$	5.74	$	5.57	$	5.85
	Average sales prices (excluding hedges)		4.87		6.43		5.84		6.53
Average Unit Costs per Mcfe:
	Operating expenses	$	1.14	$	1.61	$	1.79	$	1.88
	General and administrative expenses		1.05		0.47		0.35		0.50
	Depreciation, depletion and amortization		1.21		1.11		0.90		1.07

(1): Excludes estimated proved reserves as of December 31, 2004 of 3.8 Bcfe associated with the Columbia Natural Resources properties we purchased on April 27, 2005.
(2): PV-10 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%. PV-10 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 54.
(3): 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 Mcfe premium to NYMEX natural gas prices.
(4): 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

Distributable Cash Flow

We define distributable cash flow as net income (loss) plus:

•: Depreciation, depletion and amortization;
•: Amortization 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;
•: Unrealized (gain) loss on interest rate swaps; and
•: Realized (gain) loss on cancelled natural gas swaps.

Distributable cash flow 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. Distributable cash flow 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 to distributable cash flow:

	Period from March 14, 2003 (inception) through December 31, 2003
				Year Ended December 31, 2004						Quarter Ended March 31,
				Historical			Pro Forma			2004			2005
							(unaudited)			(unaudited)
	(in thousands)
Net (loss)	$	(1,335	)	$	(3,978	)	$	(3,125	)	$	(1,649	)	$	(12,293	)
Plus: Depreciation, depletion and amortization		972			3,749			4,478			572			1,046
Plus: Amortization of deferred financing fees		20			123			123			25			46
Plus: Loss on sale of assets		5			32			32			—			22
Plus: Loss from equity investment		3			56			56			14			10
Plus: Accretion of asset retirement obligation		15			74			115			16			25
Plus: Unrealized loss on natural gas swaps		1,600			8,765			8,765			2,683			6,580
Plus: Unrealized loss (gain) on interest rate swaps		189			1,259			1,259			461			(956	)
Plus: Realized loss on cancelled natural gas swaps(1)		—			—			—			—			7,977

Distributable Cash Flow	$	1,469		$	10,080		$	11,703		$	2,122		$	2,457

(1): During the quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the-money natural gas swaps for the fourth quarter of 2005, and for the years ending December 31, 2006 and 2007, and realized a loss of $8.0 million. We subsequently hedged similar volumes at higher prices.

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 to pay the initial quarterly distribution in each quarter following establishment of cash reserves and payment of fees and expenses.

We may not have sufficient available cash each quarter to pay the initial quarterly distribution. 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 maintenance and drilling 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 capital expenditures we make;
•: 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;
•: our ability to make working capital borrowings under our credit facility to pay distributions;
•: 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 approximately $ 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 $10.3 million. The amount of pro forma cash available for distribution during 2004 would have been sufficient to allow us to pay approximately % 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 Available for Distribution" and Appendix C 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 to the use of the net proceeds from this offering, our borrowings under the credit facility as of May 31, 2005 would have been approximately $63.5 million, or 58% of our current borrowing base of $109 million.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not directly on profitability.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings. Cash available for distribution is not dependent directly on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

If we are unable to achieve the forecast results set forth in "Cash Available for Distribution," 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 summarized forecast results set forth in "Cash Available for Distribution" are for the 12 months ending September 30, 2006. Our management has prepared the forecast information and we have not received an opinion or report on it from any independent accountants. In addition, "Cash Available for Distribution" includes a calculation of distributable cash flow. The assumptions underlying the forecast 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 forecasted. If we do not achieve the forecasted results, 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.

Natural gas prices are volatile and a decline in natural gas prices can significantly affect our financial results and impede our growth.

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 12 months ended December 31, 2004, the NYMEX natural gas index price ranged from a high of $8.14 per MMBtu to a low of $4.40 per MMBtu.

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 business, financial condition and results of operations.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our December 31, 2004 reserve report, our average decline rate for proved reserves is 7.5% during the first five years, 4.5% in the next five years and less than 4% thereafter. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2004, 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 PV-10 of our proved reserves as of December 31, 2004 would decrease from $215.0 million to $172.9 million. Our PV-10 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 quarter ended March 31, 2005, sales of natural gas to Dominion, Cabot, UGI Energy Services, Equitable and Amerada Hess accounted for approximately 37%, 21%, 13%, 12% and 8%, respectively or an aggregate of approximately 91% of our total volumes. 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 in our businesses, 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.

Our business is difficult to evaluate because we have a limited operating history and a limited history of operating the assets we have acquired.

In considering whether to invest in our units, you should consider that there is only limited historical financial and operating information available on which to base your evaluation of our performance. We commenced operations in March 2003 and, as a result, we have a limited operating history and a limited history of operating the assets we have acquired. 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.

We have incurred losses from operations since our inception and may continue to do so in the future.

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 $1.6 million and $12.3 million in the quarters ended March 31, 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 May 31, 2005, we participated in the drilling of a total of 126 wells resulting in all wells producing 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.

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 December 31, 2004, we had identified 235 proved undeveloped drilling locations and 461 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 & Consulting Services has not assigned any proved reserves to the 461 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 business, financial condition or results of operations.

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.

We will depend on our revolving credit facility for future capital needs. 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.

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. It is also important to note that it is not practical to hedge the cash flows relating to all of our production, and we therefore retain the risk of a price decrease on our unhedged volumes.

We depend on a limited number of key personnel who would be difficult to replace.

We depend on the performance of our executive officers and other key employees, in particular Michael C. Linn, our President and Chief Executive Officer. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy.

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.

Competition in the natural gas and oil industry is intense, which may adversely affect our ability to succeed.

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 19.1% and 45.4%, respectively, of our units.

Upon completion of this offering, our management and Quantum Energy Partners will own or control an aggregate 64.5% of the outstanding units, or 59.5% if the underwriters' over-allotment option 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 $17.92 per unit.

The initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $2.08 per unit. Based on the initial public offering price, you will incur immediate and substantial dilution of $17.92 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 5,510,000 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 7,296,038 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, regulated investment companies 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), regulated investment companies (known as mutual funds) 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. Effective for taxable years of a regulated investment company beginning after October 22, 2004, income derived from the ownership of publicly traded partnerships is income from a permitted source for a regulated investment company. However, for taxable years of a regulated investment company beginning on or before October 22, 2004, very little of our income will be treated as derived from a permitted source. 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 12-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 $102.5 million from the sale of 5,510,000 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' over-allotment option.

We anticipate using the net proceeds of this offering to:

•: repay $35.0 million of the currently outstanding $98.5 million of indebtedness under our revolving credit facility;
•: redeem $60.0 million of membership interests from Quantum Energy Partners;
•: redeem $1.5 million of membership interests from certain non-affiliated investors;
•: redeem $3.0 million of membership interests from Michael C. Linn; and
•: pay $2.9 million of expenses associated with this offering.

The $2.9 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 May 31, 2005, we had $98.5 million outstanding under our credit facility, bearing interest at an interest rate of 5.1%. We used the borrowings under the 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 in April 2005,
•: fund the $4.3 million purchase price of assets from Columbia Natural Resources, LLC; and
•: pay $8.0 million in connection with the cancelled (before their original settlement date) out-of-the money natural gas hedges for the fourth quarter of 2005, and the years ending December 31, 2006 and 2007.

We will use any net proceeds from the exercise of the underwriters' over-allotment option 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 over-allotment option is exercised in full, Quantum Energy Partners' ownership of units will be reduced from 7,296,038 units to 6,490,286 units, reducing Quantum Energy Partners' ownership in us from 45.4% to 40.4%.

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

CAPITALIZATION

The following table shows:

•: our historical capitalization as of March 31, 2005; and
•: our pro forma capitalization as of March 31, 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 March 31, 2005
				Historical			Pro Forma
				(unaudited) (in thousands)
Cash and cash equivalents				$	1,220		$	1,220

Long-term debt and other obligations:
	Credit facility			$	75,241		$	40,241
	Other long-term debt				5,525			5,525

			Total long-term debt and other obligations		80,766			45,766
Members' Capital:
	Unitholders' capital				16,024			—
	Unitholders				—			51,924
	Accumulated deficit				(17,606	)		(18,506	)

		Total members' capital			(1,582	)		33,418

			Total capitalization	$	79,184		$	79,184

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 March 31, 2005, after giving effect to the offering of units and the application of the related net proceeds, our net tangible book value was $33.4 million, or $2.08 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)	$	(0.15	)
	Increase in net tangible book value per unit attributable to purchasers in the offering		2.23

Less: Pro forma net tangible book value per unit after the offering(2)						2.08

Immediate dilution in net tangible book value per unit to new investors					$	17.92

(1): Determined by dividing the total number of units to be issued to our management, Quantum Energy Partners and non-affiliated investors (10,548,824 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 (16,058,824 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)		10,548,824	65.7	%	$	(0.5	)	(0.5	)%
New investors		5,510,000	34.3	%		110.2		100.5	%

	Total	16,058,824	100.0	%	$	109.7		100.0	%

(1): The total consideration is equal to the net tangible book value as of March 31, 2005 contributed by our management, Quantum Energy Partners and non-affiliated investors.

CASH DISTRIBUTION POLICY

Quarterly Distributions of Available Cash

General. Within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2005, we will distribute all of our available cash to unitholders of record on the applicable record date. The first distribution that purchasers of units in this offering will be eligible to receive will be for the period from the closing of this offering through September 30, 2005, which will be adjusted based on the actual length of that period.

Available Cash. 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. 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 (other than any quarter in which our liquidation commences or is continuing). If we are not in compliance with covenants contained in our credit facilities, we will be unable to make distributions of available cash. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities."

The amount of cash that is available for distribution for any quarter prior to the commencement of our liquidation will depend on the level of cash flow from operations we generated in that quarter, as reduced by the level of cash reserves established by our board of directors in its discretion to provide for our future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. In addition, any cash on hand that is attributable to working capital borrowings after the end of the quarter for which a determination of available cash is then being made will also constitute available cash. The cash generated by our operating activities will be dependent in large part upon the quantity of natural gas produced from our net revenue interest in our producing wells and the prevailing realized sales price for that production, reduced by the costs incurred to produce and to market such volume. Our board of directors will establish cash reserves based on its evaluation of our estimated future cash flows, estimated operating and capital expenditures, expected debt service requirements and the level of reserves that is necessary or appropriate under the circumstances to provide for such expected cash uses, for unexpected contingencies and for future cash distributions to our unitholders. Cash reserves so established by our board of directors will reduce the level of available cash on hand to be distributed below that which would exist if the reserve were not established.

Although we intend to conduct our operations in a manner intended to permit generally stable and increasing distributions of available cash over the long-term, the natural gas and oil business in which we operate is subject to numerous operating and competitive risks outside our control. No assurance is given, therefore, that we will be successful in our efforts to pay sustainable or increasing distributions of available cash over the long-term or short-term. Please read "Risk Factors — Risks Related to Our Business — We may not have sufficient cash to pay the initial quarterly distribution in each quarter following establishment of cash reserves and payment of fees and expenses."

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 and any liquidation trustee. We will then distribute any remaining proceeds to the unitholders in accordance with their respective capital account balances, as adjusted to reflect any taxable gain or loss upon the sale or other disposition of our assets in liquidation.

CASH AVAILABLE FOR DISTRIBUTION

We intend to pay, to the extent we have sufficient available cash, an initial quarterly distribution of $ per unit on all the units. Available cash for any quarter will consist generally of all cash on hand at the end of that quarter, plus cash on hand from working capital borrowings after the end of the quarter, as adjusted for reserves. The definition of available cash is in our limited liability company agreement and in the glossary.

The amount of available cash needed to pay the initial quarterly distribution for one quarter and for four quarters on the units to be outstanding immediately after this offering is:

		One Quarter			Four Quarters
		(In thousands)
Units		$			$

If we had completed this offering on January 1, 2004, our pro forma available cash generated during 2004 would have been $11.5 million. The pro forma financial data gives effect to the properties acquired from Mountain V Oil & Gas, Inc. and Pentex Energy, Inc. in 2004 as if they occurred on January 1, 2004 and to the $35 million debt repayment from the proceeds of this offering. This amount would have been sufficient to allow us to pay approximately % of the initial quarterly distribution on the units. Pro forma available cash is derived from our financial statements in the manner described in Appendix C which is adjusted to reflect the incremental general and administrative expenses associated with being a public company.

We expect to incur approximately $1.4 million annually in incremental general and administrative expenses, such as 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.

We derived the amounts of pro forma available cash shown above from our financial statements in the manner described in Appendix C. In addition, available cash as defined in the limited liability company agreement is a cash accounting concept, while our financial statements have been prepared on an accrual basis. As a result, you should only view the amount of estimated available cash as a general indication of the amount of available cash that we might have generated had we been formed in earlier periods.

We believe we will have sufficient cash available for distribution following the completion of this offering to pay the initial quarterly distribution through September 30, 2006. Our belief is based on our forecast information found under the heading "Forecast Information."

You should read the notes and the other information found below under the heading "Forecast Information" carefully for a discussion of the material assumptions underlying the forecast information. The forecast information presents, to the best of our knowledge and belief, the expected results of our operations for the forecast period. While we believe that the assumptions underlying the forecast are reasonable in light of management's current beliefs concerning future events, these assumptions 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 we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than that currently expected and could,

therefore, be insufficient to permit us to make the full, or any, amount of the initial quarterly distribution, in which event the market price of the units may decline materially. Consequently, the statement that we believe that we will have sufficient available cash to pay the full amount of the initial quarterly distributions for each quarter through September 30, 2006 should not be regarded as a representation by us or the underwriters or any other person that we will make such a distribution.

When considering the forecast, you should keep in mind the risk factors and other cautionary statements under the heading "Risk Factors — Risks Related to Our Business" and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in the forecast.

Forecast Information

We believe we will have sufficient cash available for distribution following the completion of this offering to pay the initial quarterly distribution through September 30, 2006.

The following is a summarized financial and operating forecast for Linn Energy, LLC for the 12 months ending September 30, 2006. We do not as a matter of course make public projections of future results and furthermore, do not undertake any obligation to release publicly the results of any future revisions or updates to the forecast information. The forecast information was not prepared in accordance with the guidelines established by the American Institute of Certified Public Accountants and our independent registered public accounting firm has not reviewed or examined the forecast information.

The forecast information is based on certain assumptions and, as of the date hereof, represents our best judgment of future results, commodity prices and course of action. The assumptions disclosed herein are those that we believe are most significant to the forecast. Because events and circumstances frequently do not occur as expected, we can give you no assurance that the forecast results will be achieved. There will likely be differences between the forecast information and the actual results and those differences may be material. Our forecast is a forward-looking statement and should be read together with the consolidated financial statements and the accompanying notes included elsewhere in this prospectus and together with "Management's Discussion and Analysis of Financial Condition and Results of Operations." When considering the forecast information you should keep in mind the risk factors and other cautionary statements under the heading "Risk Factors — Risks Related to Our Business" elsewhere in this prospectus. If the forecast is not achieved, we may not be able to pay the full, or any, amount of the initial quarterly distribution.

Summarized Forecast Information
(in thousands, except per unit data)
(Unaudited)

	Twelve Months Ending September 30, 2006
Net Production:
Total production (MMcfe)		6,226
Average daily production (Mcfe/d)		17,057
Average Natural Gas Sales Prices per Mcf:
Average sales prices (hedged volumes)	$	7.53
Average sales prices (unhedged volumes)	$	6.00
Percentage of total production hedged		79%
Premium to NYMEX	$	0.50
Weighted average net sales prices	$	7.73
Distributable Cash Flow:
Total revenue	$	48,050
Operating expenses		5,763
General and administrative expenses		2,910
Cash interest expense		4,077

Distributable cash flow	$	35,300

Distributable cash flow per unit	$	2.20
Weighted average units outstanding after the offering		16,059

The amount of available cash needed to pay the initial quarterly distribution for four quarters on the units to be outstanding immediately after the offering is:

		Four Quarters Ending September 30, 2006
Initial quarterly distribution		$
Initial quarterly distribution per unit		$

Significant Forecast Assumptions

Capital Expenditures for Drilling. We expect to drill 106 gross, 101 net wells, for each of the years ending December 31, 2005 and 2006 at an average cost of $200,000 with expected reserves of 200 MMcfe per well. Total capital expenditures are expected to be $20.2 million in both 2005 and 2006. Since inception, all of the wells we have drilled have been successful in producing natural gas in commercial quantities and we are forecasting similar results for our 2005 and 2006 drilling program. We also expect that the wells drilled will have similar producing characteristics as wells we have recently drilled in these operating areas. Based on our historical experience, we expect that the new wells will be producing and connected to a pipeline within 60 days after drilling has commenced. Due to these factors, we expect that capital expenditures for drilling at the levels expected in our 2005 and 2006 drilling program will result in increased natural gas production and increased natural gas reserves, which in turn will result in an increase in our borrowing base by at least the amount of the actual capital expenditures for drilling. Therefore, 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 forecast period.

Net Production. Production volumes are based on natural gas and oil production in our reserve report (as of December 31, 2004), expected production from our acquisition of natural gas and oil properties from Columbia Natural Resources, LLC (completed in April 2005) and the additional production volumes expected to be derived from our 2005 and 2006 drilling program.

Average Sales Prices per Mcfe. Weighted average sales prices are calculated by taking into account the volume of natural gas we have hedged for the forecast period (4,931 MMMBtu, or approximately 79% of total forecasted production volume) at a weighted average NYMEX price of $7.53 per MMBtu and unhedged natural gas production volumes at an assumed price of $6.00 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 (as of December 31, 2004 this premium was $0.67 per Mcf).

Revenue. Revenue is calculated by multiplying total 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 $44.00 per Bbl, after a negative basis differential and gathering fees.

Operating Expenses. Operating expenses are based on our historical lease operating expenses per well, including labor supervision, transportation, minor maintenance, severance and ad valorem taxes and other customary charges plus additional costs related to drilling overhead.

General and Administrative Expenses. General and administrative expenses are based on our estimate of the costs of our employees and executive officers, related benefits, office leases, professional fees, and other costs not directly associated with field operations and the additional costs associated with being a public company.

Cash Interest Expense. Cash interest expense is based on our assumed average debt 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 5.5%.

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. 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 quarters ended March 31, 2004 and 2005 and the balance sheet information as of March 31, 2005 were derived from our unaudited financial statements included in this prospectus. The pro forma financial data gives effect to the acquisition of the properties acquired from Mountain V Oil & Gas, Inc. and Pentex Energy, Inc. as if they occurred at January 1, 2004. 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.

The following table presents a non-GAAP financial measure, distributable cash flow, 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 "Prospectus Summary — Non-GAAP Financial Measures" beginning on page 16.

			Period from March 14, 2003 (inception) through December 31, 2003
						Year Ended December 31, 2004						Quarter Ended March 31,
						Historical			Pro Forma			2004			2005
									(unaudited)			(unaudited)
			(in thousands)
Statement of Operations Data:
Revenues:
	Natural gas and oil sales		$	3,323		$	21,232		$	24,154		$	3,955		$	6,146
	Realized gain (loss) on natural gas swaps(1)			163			(2,240	)		(2,240	)		(170	)		(8,575	)
	Unrealized (loss) on natural gas swaps(2)			(1,600	)		(8,765	)		(8,765	)		(2,683	)		(6,580	)
	Natural gas marketing income			—			520			520			—			814
	Other income			4			160			160			20			74

		Total revenues		1,890			10,907			13,829			1,122			(8,121	)

Expenses:
	Operating expenses			917			5,460			6,139			1,145			1,834
	Natural gas marketing expense			—			482			482			—			790
	General and administrative expenses			845			1,583			1,624			220			490
	Depreciation, depletion and amortization			972			3,749			4,478			572			1,046

		Total expenses		2,734			11,274			12,723			1,937			4,160

Other Income and (Expenses):
	Interest income			34			7			7			3			—
	Interest and financing expenses(3)			(517	)		(3,530	)		(4,150	)		(823	)		20
	Investment (loss)			(3	)		(56	)		(56	)		(14	)		(10	)
	(Loss) on sale of assets			(5	)		(32	)		(32	)		—			(22	)

				(491	)		(3,611	)		(4,231	)		(834	)		(12	)

Net (loss)			$	(1,335	)	$	(3,978	)	$	(3,125	)	$	(1,649	)	$	(12,293	)

(1): During the quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the money natural gas hedges for the fourth quarter of 2005, and the years ending December 31, 2006 and 2007, and realized a loss of $8.0 million. We subsequently hedged similar volumes at higher prices.
(2): The natural gas 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 natural gas prices. Therefore, the mark to market of these instruments was recorded in our current earnings. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. Further, these amounts represent non-cash charges.
(3): 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 in our current earnings. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. Further, these amounts represent non-cash charges.

	Period from March 14, 2003 (inception) through December 31, 2003
							Quarter Ended March 31,
				Year Ended December 31, 2004			Quarter Ended March 31,
				Year Ended December 31, 2004			2004			2005
							(unaudited)
	(in thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities	$	929		$	11,381		$	1,595		$	(7,138	)
Net cash used in investing activities		(36,408	)		(62,402	)		(20,612	)		(1,801	)
Net cash provided by financing activities		57,521			31,167			—			7,971
Capital expenditures	$	52,356		$	47,508		$	4,791		$	1,782
Other Financial Information (unaudited):
Distributable cash flow	$	1,469		$	10,080		$	2,122		$	2,457

		As of December 31,
		As of December 31,				As of March 31, 2005
		2003		2004		As of March 31, 2005
						(unaudited)
		(in thousands)
Balance Sheet Data:
Cash and cash equivalents(1)		$	22,043	$	2,188	$	1,220
Other current assets			1,714		5,094		4,558
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization			53,036		97,123		97,886
Property, plant and equipment, net of accumulated depreciation			370		1,387		1,317
Other assets			2,486		542		606

	Total assets	$	79,649	$	106,334	$	105,587

Current liabilities		$	20,319	$	9,968	$	12,659
Long-term debt			41,518		72,750		80,766
Other long-term liabilities			3,123		12,905		13,744
Members' capital			14,689		10,711		(1,582	)

	Total liabilities and members' capital	$	79,649	$	106,334	$	105,587

(1): 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 December 31, 2004 were 119.8 Bcfe, of which approximately 98% were natural gas and 62% were classified as proved developed. At May 31, 2005, we operated 1,303, or 96%, of our 1,360 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 30 years based on our 2004 year end reserve report and annualized production for the quarter ended March 31, 2005. As of December 31, 2004, we had identified 235 proved undeveloped drilling locations and 461 additional drilling locations. As of December 31, 2004, we had a leasehold interest in approximately 104,805 net acres in the Appalachian Basin, 77% of which have additional drilling potential. From inception through December 31, 2004, we added 17.2 Bcfe of proved reserves through our drilling activities, at a finding and development cost of $0.99 per Mcfe.

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

	Total	1,234		$	82.5

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 December 31, 2004, we had 119.8 Bcfe of estimated net proved reserves with a PV-10 of $215.0 million, a 72% increase over December 31, 2003, when we had 69.8 Bcfe of estimated net proved reserves with a PV-10 of $126.3 million. Our December 31, 2003 and 2004 PV-10 was determined using a NYMEX price of $5.97 and $6.18 per Mcf of natural gas, respectively, and $32.76 and $43.00 per Bbl of oil, respectively. Oil accounts for less than 2% 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 field 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 106 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, as hedged, 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.

			Period from March 14, 2003 (inception) through December 31, 2003
									Increase (Decrease)					Quarter Ended March 31,						Increase (Decrease)
						Year Ended December 31, 2004			Increase (Decrease)					Quarter Ended March 31,						Increase (Decrease)
						Year Ended December 31, 2004			Amount			Percent		2004			2005			Amount			Percent
														(unaudited)
			(in thousands, except per unit data)
Revenues:
	Natural gas and oil sales		$	3,323		$	21,232		$	17,909		539	%	$	3,955		$	6,146		$	2,191		55	%
	Realized gain (loss) on natural gas swaps			163			(2,240	)		(2,403	)	(1,474	%)		(170	)		(8,575	)		(8,405	)	4,944	%
	Unrealized (loss) on natural gas swaps			(1,600	)		(8,765	)		(7,165	)	448	%		(2,683	)		(6,580	)		(3,897	)	145	%
	Natural gas marketing income			—			520			520		—			—			814			814		—
	Other income			4			160			156		3,900	%		20			74			54		270	%

		Total revenue		1,890			10,907			9,017		477	%		1,122			(8,121	)		(9,243	)	(824	%)
Expenses:
	Operating expenses		$	917		$	5,460		$	4,543		495	%	$	1,145		$	1,834		$	689		60	%
	Natural gas marketing expense			—			482			482		—			—			790			790		—
	General and administrative expenses			845			1,583			738		87	%		220			490			270		123	%
	Depreciation, depletion and amortization			972			3,749			2,777		286	%		572			1,046			474		83	%

		Total expenses		2,734			11,274			8,540		312	%		1,937			4,160			2,223		115	%
Other Income and (Expenses):
	Interest and financing expenses		$	(517	)	$	(3,530	)	$	(3,013	)	583	%	$	(823	)	$	20		$	843		(102	%)
Net Production:
	Total production (MMcfe)			802			3,385			2,583		322	%		639			977			338		53	%
	Average daily production (Mcfe/d)			3,748			9,274			5,526		147	%		7,100			10,856			3,756		53	%
Average Sales Prices per Mcfe:
	Average sales prices (including hedges)		$	5.07		$	5.74		$	0.67		13	%	$	5.57		$	5.85		$	0.28		5	%
	Average sales prices (excluding hedges)			4.87			6.43			1.56		32	%		5.84			6.53			0.69		12	%
Average Unit Costs per Mcfe:
	Operating expenses		$	1.14		$	1.61		$	0.47		41	%	$	1.79		$	1.88		$	0.09		5	%
	General and administrative expenses			1.05			0.47			(0.58	)	(55	%)		0.35			0.50			0.15		43	%
	Depreciation, depletion and amortization			1.21			1.11			(0.10	)	(8	%)		0.90			1.07			0.17		(19	%)

Quarter Ended March 31, 2005 Compared to Quarter Ended March 31, 2004

Revenue

The increase in revenue from natural gas and oil sales was due primarily to the increase in production to 977 Mcfe during the quarter ended March 31, 2005 from 639 Mcfe during the quarter ended March 31, 2004, due to the two acquisitions completed in 2004, as well as the drilling of 10 wells during the first quarter of 2005. In addition to the increase in production, the average natural gas sales price increased during the quarter ended March 31, 2005 as compared to the quarter ender March 31, 2004.

Natural gas and oil sales, before realized and unrealized gains and losses on natural gas swaps, increased to approximately $6.1 million from $4.0 million during the quarter ended

March 31, 2005 as compared to the quarter ender March 31, 2004. The key revenue measurements were as follows:

		Quarter Ended March 31,
		Quarter Ended March 31,		Percentage Increase (Decrease)
		2004	2005	Percentage Increase (Decrease)
Net Production:
	Total production (MMcfe)	639	977	53	%
	Average daily production (Mcfe/d)	7,100	10,856	53	%
Average Sales Prices per Mcfe:
	Average sales price (including hedges)	$5.57	$5.85	5	%
	Average sales price (excluding hedges)	5.84	6.53	12	%

Hedging Activities

During the quarter ended March 31, 2005, we hedged approximately 89% of our production, which resulted in revenues that were $0.6 million less than we would have achieved at unhedged prices. During the quarter ended March 31, 2004, we hedged approximately 47% of our production, which resulted in revenues that were $0.2 million less then we would have achieved at unhedged prices. During the quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the-money natural gas hedges for the fourth quarter of 2005, and the years ending December 31, 2006, and 2007 and realized a loss of $8.0 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 values 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 $1.8 million for the quarter ended March 31, 2005 from $1.1 million during the quarter ended March 31, 2004, 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.

	Quarter Ended March 31,
	Quarter Ended March 31,				Percentage Increase (Decrease)
	2004		2005		Percentage Increase (Decrease)
Operating expenses per Mcfe	$	1.79	$	1.88	5	%

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 by approximately $0.3 million or 122% during the quarter ended March 31, 2005 as compared to

the quarter ended March 31, 2004. General and administrative expenses per Mcfe of production were as follows:

	Quarter Ended March 31,
	Quarter Ended March 31,				Percentage Increase (Decrease)
	2004		2005		Percentage Increase (Decrease)
General and administrative expenses per Mcfe	$	0.35	$	0.50	43	%

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 additional 106 wells we expect to drill in 2005 and to perform the functions associated with being a public company.

Depreciation, depletion and amortization increased to $1.0 million for the quarter ended March 31, 2005 from $0.6 million during the quarter ended March 31, 2004 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.

Interest and financing expenses were ($19,606) for the quarter ended March 31, 2005 compared to $0.8 million for the quarter ended March 31, 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 $1.0 million gain and a $0.5 million loss in our current earnings for the quarter ended March 31, 2005 and the quarter ended March 31, 2004, respectively. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. Further, these amounts represent non-cash charges. Cash payments for interest increased to $1.2 million for the quarter ended March 31, 2005 from $0.3 million for quarter ended March 31, 2004 primarily due to increased debt levels associated with the two acquisitions made in 2004.

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

Revenue

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.

Natural gas and oil sales, before realized and unrealized gains and losses on natural gas swaps, 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	%

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. The increase in the loss was due to the increase in natural gas prices from 2003 to 2004. 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.

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 $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 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 administration expenses in relation to the amount production and the number of wells operated. For the period from March 14, 2003 (inception) through December 31, 2003 as compared to the year ended December 31, 2004, general and

administrative expenses increased by approximately $0.7 million, which represented an 87% increase. 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	%)

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 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. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. 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.

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 quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the money natural gas hedges for the fourth quarter of 2005, and the years ending December 31, 2006 and 2007 and realized a loss of $8.0 million. As a result, working capital and member's capital were reduced by $8.0 million and were ($6.9) million and ($1.6) million, respectively, at March 31, 2005. We subsequently hedged similar volumes at higher prices, which will result in substantially higher cash flow from operations for those future periods.

Cash Flow from Operations

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.

Net cash (used in) provided by operating activities was $(7.1) million and $1.6 million for the quarters ended March 31, 2005 and 2004, respectively. The decrease in net cash provided by operating activities was due substantially to the realized hedging loss during the quarter. During the quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the-money hedges for the fourth quarter of 2005, and the years ending December 31, 2006 and 2007 and realized a loss of $8.0 million. We subsequently hedged similar volumes at higher prices. Changes in current assets and liabilities reduced cash flow from operations by $1.6 million and $0.5 million for the quarters ended March 31, 2005 and 2004, respectively.

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 exclusively use fixed price swaps to hedge NYMEX natural gas prices, which does not include the additional net premium we typically realize in the Appalachian Basin. At May 31, 2005, we had in place natural gas swap contracts covering significant portions of our estimated 2005 through 2007 natural gas production. For the twelve month period ending September 30, 2006, we currently have fixed price swaps in place for a total hedged amount of 4,931 MMMBtu, which represents approximately 79% of our total expected production volume of 6,226 MMcfe. The average hedge price is $7.53 per MMBtu. We currently have entered into fixed price swaps for a total hedged amount of 4,952 MMMBtu at an average price of $7.47 per MMBtu for 2006 and 4,528 MMMBtu at an average price of $7.03 per MMBtu for 2007.

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 creditworthy major financial institutions deemed by management as competent and competitive market makers.

The following table summarizes, for the periods indicated, our hedges in place at May 31, 2005 through December 2007. Currently, we exclusively use fixed price swaps as our mechanism for hedging commodity prices. These transactions require no cash payment upfront and are settled on a monthly basis. For natural gas swaps, 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 25^th day of the month following the production month.

	Fixed Price Swaps
Period	Hedged Volume (MMMBtu)	Average Price ($/MMBtu)
June 2005	298	$	5.28
3^rd Quarter 2005	879	$	5.38
4^th Quarter 2005	1,239	$	7.70
12 Months Ending September 30, 2006	4,931	$	7.53
Year 2006	4,952	$	7.47
Year 2007	4,528	$	7.03

Investing Activities — Acquisitions and Capital Expenditures

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, 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, and $0.4 million for furniture, fixtures and equipment.

Our capital expenditures were $1.8 million and $4.8 million for the quarters ended March 31, 2005 and 2004, respectively. The total for the quarter ended March 31, 2005 includes $1.7 million for drilling, development, and exploitation of natural gas properties and $0.1 million for the acquisition of additional working interest on our current wells. The total for the quarter ended March 31, 2004 includes $3.8 million for drilling, development, and exploitation of natural gas properties, $0.9 million for the acquisition of additional working interest in our current wells, and $0.1 million for furniture, fixtures, and equipment.

We currently anticipate our capital budget will be $20.2 million for 2005. The capital budget, which predominantly consists of capital for drilling, also includes amounts for infrastructure projects and equipment. As of May 31, 2005, we had $10.5 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 $45.5 million, assuming the current borrowing base of $109 million. The amount and timing of these capital expenditures is largely discretionary and within our control. If natural gas prices decline to levels below acceptable levels, we could choose to defer a portion of these 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 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 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 million. In 2004, the borrowing base was increased to $73 million.

Under the prior credit facility and as of December 31, 2003 and 2004, we had borrowed $41.8 million and $72.6 million, respectively. 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 March 31, 2005, we had borrowed $75.6 million. As of March 31, 2005, the applicable weighted average interest rate was 4.6%.

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 ratio were calculated based on tax basis financial statements. At December 31, 2003 and 2004, we were in compliance with all covenants.

On April 11, 2005, we entered into a new $200 million secured revolving credit facility with BNP Paribas (administrative agent) and RBC Capital Markets (syndication agent), as Co-Lead Arrangers and Bookrunners, 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 $109 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 May 31, 2005, we had borrowings of approximately $98.5 million outstanding under our new credit facility, bearing interest at an interest rate of 5.1%. 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; and
•: pay $8.0 million in connection with the cancelled (before their original settlement date) out-of-the money natural gas hedges for the fourth quarter of 2005, and the years ending December 31, 2006 and 2007.

We anticipate that $35.0 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 against which enforcement proceedings are brought or that are not stayed pending appeal;
•: 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) if a majority of our directors are replaced by persons not approved by our board of directors.

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
Credit facility(3)			—		—		72,605		—		—		—		72,605
Office and office equipment leases(4)			116		115		87		89		38		—		445
Asset retirement obligation			—		—		—		—		—		3,857		3,857

	Total	$	174	$	176	$	72,757	$	153	$	52	$	4,193	$	77,505

(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): 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 May 31, 2005, approximately $98.5 million was outstanding under our new credit facility. 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.

(4): Includes potential continuing lease payments under our existing office lease. We anticipate moving our principal office to a new facility during the third quarter in 2005. Our existing lease, which expires in 2009, allows us to sublease our existing facility with the approval of the lessor. If we are unable to sublease our existing 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, Inc., 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 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 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 & 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

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.

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.

We currently use the "Net-Back" method of accounting for transportation arrangements of its natural gas sales. We sell natural gas at the wellhead and 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.

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. 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 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 the derivatives that were established in 2004 and 2003, the instruments were not specifically designated as hedges under SFAS No. 133, even though they protected the company from changes in commodity prices. Therefore, the mark to market of these instruments was recorded in our current earnings. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in current earnings. Further, these amounts represent non-cash charges.

the derivative's fair value. Any ineffective portion of the derivative instrument's change in fair value is recognized immediately in earnings.

Acquisitions

The establishment of our initial asset base since inception in March 2003 has included seven 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 made 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.

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 the FSP. 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.

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. 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 that we will sell in 2005 was a liability of $2.7 million, which we owe to the counterparty. A 10% increase in the index natural gas prices above the December 31, 2004 prices for 2005

would increase the liability by $1.4 million; conversely, a 10% decrease in the natural gas price would decrease the liability by $1.4 million.

As of March 31, 2005, the fair market value of our derivative positions was a liability of $17.2 million, which we owe to the counterparty. The hedges for the remainder of 2005 and through December 2007 are summarized in the table presented above under " — Cash Flow from Operations."

Interest Rate Risks

At March 31, 2005, we had debt outstanding of $80.8 million, of which $75.6 million incurred interest at floating rates in accordance with our prior 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 are effective and settled 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 are effective and settled 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 the 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 effective and 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.

The interest rate swaps that were established in 2003 and 2004 were not specifically designated as hedges under SFAS No. 133, even though they protect the company from changes in interest rates. Therefore, the mark to market of these instruments was recorded in our current earnings. Subsequent to March 31, 2005, we anticipate that the new derivative agreements will be designated and effective as hedges and the mark to market will no longer be recorded in 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 that increase distributable cash flow per unit. 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 seven acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate purchase price of $82.5 million, with total proved reserves of 100.9 Bcfe, or an acquisition cost per Mcfe of $0.82. Our seven acquisitions included 1,234 producing wells and we have subsequently drilled 126 wells with a success rate of 100% as of May 31, 2005. At May 31, 2005, our production was approximately 12.8 MMcfe per day from 1,360 wells.

Our proved reserves at December 31, 2004 were 119.8 Bcfe, of which approximately 98% were natural gas and 62% were classified as proved developed. At May 31, 2005, we operated 1,303, or 96%, of our 1,360 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 30 years based on our 2004 year end reserve report and annualized production for the quarter ended March 31, 2005. As of December 31, 2004, we had identified 235 proved undeveloped drilling locations and 461 additional drilling locations. As of December 31, 2004, we had a leasehold interest in 104,805 net acres in the Appalachian Basin, 77% of which have additional drilling potential. From inception through December 31, 2004, we added 17.2 Bcfe of proved natural gas reserves through drilling activities, at a finding and development cost of $0.99 per Mcfe.

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

	Total	1,234		$	82.5

Business Strategy

Our goal is to provide stability and growth in distributions to our unitholders through a combination of continued successful drilling, acquisitions that increase distributable cash flow per unit, 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 distributable cash per unit;
•: 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 May 31, 2005, we drilled 126 wells with a success rate of 100%. From inception through December 31, 2004, our finding and development cost was $0.99 per Mcfe. Our average well takes five days to drill and is expected to have an average cost of $200,000 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 seven acquisitions with an average purchase price of $0.82 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 December 31, 2004, we had leases totaling 104,805 net acres with 235 identified proved developed drilling locations and 461 additional identified drilling locations. We continually acquire new lease positions to increase potential drilling locations.
•: Operating Control — As of May 31, 2005, we operated 1,303, or 96%, of our total 1,360 producing wells and we will operate 100 of the 106 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 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.
•: Long Life Reserves — Our average reserve life is 30 years based on our 2004 year end reserves and annualized production for the quarter ended March 31, 2005.
•: Production Diversification — At May 31, 2005, our production was approximately 12.8 MMcfe per day from 1,360 producing wells from four states in the Appalachian Basin, including 771 wells in Pennsylvania, 517 wells in West Virginia, 61 wells in New York and 11 wells in Virginia. Our largest well accounts for less than 2% 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 Mcfe 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 pay 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 $200,000, 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 December 31, 2004, we spent $17.0 million and drilled 90 wells, all of which produce in commercial quantities with an average finding and development cost of $0.99 per Mcfe. 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 December 31, 2004, we had 235 proved undeveloped drilling locations (specific drilling locations as to which Schlumberger Data & Consulting Services assigned proved undeveloped reserves as of such date) and we had identified 461 additional unproved drilling locations (specific drilling locations as to which Schlumberger Data & 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 $20.2 million to drill 106 wells, 100 of which we will operate. As of May 31, 2005, we had drilled 36 out of our planned 106 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 Mcfe, 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 Mcfe 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 exclusively use fixed price swaps 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, and December 31, 2004, based on reserve reports prepared by Schlumberger Data & Consulting Services. A copy of the reserve report prepared by our independent petroleum engineers is attached as Appendix D. 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 PV-10 values shown in the table are not intended to represent the current market value of our estimated natural gas and oil reserves.

On April 27, 2005, we purchased properties in West Virginia and western Virginia from Columbia Natural Resources, LLC for $4.3 million. As of April 30, 2005, these properties included estimated net proved reserves of 3.8 Bcfe, which reserves are not included in the following table.

			As of December 31,
			2003			2004
Reserve Data:
Estimated net proved reserves(1):
	Natural gas (Bcf)			68.9			118.9
	Oil (MMBbls)			0.2			0.1
		Total (Bcfe)		69.8			119.8
Proved developed (Bcfe)				41.8			74.4
Proved undeveloped (Bcfe)				28.0			45.4
Proved developed reserves as a percentage of total proved reserves				59.9	%		62.1	%
PV-10 (in millions)(2)			$	126.3		$	215.0
Representative Natural Gas and Oil Prices(3):
	Natural gas — NYMEX Henry Hub per MMBtu		$	5.97		$	6.18
	Oil — NYMEX WTI per Bbl			32.76			43.00

(1): Excludes estimated proved reserves as of December 31, 2004 of 3.8 Bcfe associated with the Columbia Natural Resources properties we purchased on April 27, 2005.
(2): 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 54.
(3): 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.

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 PV-10 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 & Consulting Services to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither Schlumberger Data & 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 & 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)
						Quarter Ended March 31,
				Year Ended December 31, 2004		Quarter Ended March 31,
				Year Ended December 31, 2004		2004		2005
Net Production:
	Total production (MMcfe)		802		3,385		639		977
	Average daily production (Mcfe/d)		3,748		9,274		7,100		10,856
Average Sales Prices per Mcfe:
	Average sales prices (including hedges)	$	5.07	$	5.74	$	5.57	$	5.85
	Average sales prices (excluding hedges)		4.87		6.43		5.84		6.53
Average Unit Costs per Mcfe:
	Operating expenses	$	1.14	$	1.61	$	1.79	$	1.88
	General and administrative expenses		1.05		0.47		0.35		0.50
	Depreciation, depletion and amortization		1.21		1.11		0.90		1.07

(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 quarter ended March 31, 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	Quarter Ended March 31, 2005
Gross:
	Productive		90	10
	Dry		—	—

		Total	90	10

Net:
	Productive		82	8
	Dry		—	—

		Total	82	8

Summary of Exploitation Projects

We are currently pursuing an active exploitation strategy. For 2005, we have budgeted $20.2 million for development drilling, production facilities and other exploitation related projects to implement this strategy. We intend to drill 106 wells in 2005, 100 of which will be operated by us. Of those 100 wells, we estimate that 50 will be located in West Virginia and 50 will be located in Pennsylvania.

Natural Gas Gathering Activities

We own and operate an extensive network of natural gas gathering systems comprised of 350 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 90% of our current production and will gather 100 of the 106 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 quarter ended March 31, 2005, sales of natural gas to Dominion, Cabot, UGI Energy Services, Equitable and Amerada Hess accounted for approximately 37%, 21%, 13%, 12% and 8%, respectively or an aggregate of approximately 91% of our total volumes. 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 May 31, 2005, we had 52 full time employees, including two geologists, four petroleum engineers and eight land professionals. Of our 52 full time employees, 16 work in our Pittsburgh office, two in our Houston office, and 34 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 5,000 square feet of office space in Pittsburgh, Pennsylvania at 1700 North Highland Road, Suite 100, where our principal offices are located. The lease for our Pittsburgh office expires in March 2009. During the third quarter of 2005, we anticipate to move to a new 13,000 square foot office location in Pittsburgh, Pennsylvania to accommodate our growing operations. 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

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 directors will be elected annually as described below. The board intends to appoint four functioning committees concurrently with the closing 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. At the time of closing 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. At the time of closing 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. At the time of closing 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 April, 2003. From April 1991 to March 2003, Mr. Linn was President of Allegheny Interests, Inc., an oil and gas 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, an Appalachian Basin natural gas and oil company which was sold to Columbia Natural Gas Company in 1999. 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 Vice Chairman for the 2003 to 2005 term and 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. Prior to joining 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. Mr. Rockov has 12 years of investment banking experience in all aspects of the energy industry and has held various senior positions with Dain Rauscher Wessels and Rauscher Pierce Refsnes, Inc., two predecessor entities to 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 2003, Mr. Merriam operated as a Senior Engineer for Schlumberger Holditch — Reservoir Technology, an oil and gas consulting company, conducting economic and reservoir evaluations of oil and natural gas properties, from March 2001 to March 2003. From October 1999 to January 2001 he was the Vice President of Exploration and Production at North Coast Energy, Inc., a publicly traded independent oil and gas 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. Prior to joining Linn Energy in 2003, Mr. Keddie formed Gateway Resources Management, LLC, a professional land services business, in October 1999, which led to employment with EOG Resources, Inc. from January 2001 to March 2003. At EOG, Mr. Keddie held the position of Project Landman and was responsible for various land services in the Appalachian Basin with a special emphasis on coalbed methane projects. 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. Prior to joining 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. Mr. Robinson was the member-in-charge of the accounting and auditing department of Toothman Rice PLLC, an independent accounting firm which specializes in the oil and gas industry. Mr. Robinson served in various functions with Toothman Rice from July 2002 to April 2005. Prior to joining Toothman Rice, Mr. Robinson was with Arthur Andersen from August 1997 to May 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 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, Celero Energy, LP, Stratagem Energy Corp. and EnergyQuest Resources, LP.

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 American Locker Group and 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.

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 if his employment is terminated in the first 12 months and equal to 36 months of his highest annual salary during the prior 36 months if terminated thereafter. 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 June 2, 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, 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.

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. 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 our employees and directors and employees of 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 units, provided that no more than 25% of such units (as adjusted) may be delivered as payment with respect to restricted units and phantom units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. 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 may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our board of directors and the compensation committee of the board also 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. The plan will expire on the earlier of the tenth anniversary of its adoption or its termination by the board of directors or the compensation committee. Awards then outstanding will continue pursuant to the terms of their grants.

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. 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 may 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. 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 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.

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 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 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 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 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 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 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 and members of our board of directors containing such terms as the committee shall determine. Unit appreciation rights will have an exercise price that may 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 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.

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' over-allotment option, 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)		7,296,038	45.4	%
Michael C. Linn		2,263,328	14.1	%
Kolja Rockov(2)		198,257	1.2	%
Gerald W. Merriam		301,666	1.9	%
Roland P. Keddie		301,666	1.9	%
Toby R. Neugebauer(3)		7,296,038	45.4	%
George A. Alcorn		—	—
Terrence S. Jacobs		—	—
Jeffrey C. Swoveland		—	—
	All executive officers and directors as a group (10 persons)	3,064,917	19.1	%

(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 132,171 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.

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.

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 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' over-allotment option 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' over-allotment option, we anticipate that we will redeem $60.0 million, $3.0 million and $1.5 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' over-allotment option, we anticipate that Quantum Energy Partners will own 7,296,038 units, Michael C. Linn, Gerald W. Merriam and Roland P. Keddie will own in the aggregate approximately 2,866,660 units and non-affiliated equity investors will own approximately 187,869 units. Any net proceeds from the exercise of the underwriters' over-allotment option 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	$	60.0 million cash 7,296,038 units	$	205.9 million
Non-affiliated equity investors(3)	$	386,242	$	1.5 million cash 187,869 units	$	5.3 million
Michael C. Linn	$	737,500	$	3.0 million cash 2,263,328 units	$	48.3 million
Gerald W. Merriam	$	100,000		301,666 units	$	6.0 million
Roland P. Keddie	$	100,000		301,666 units	$	6.0 million

(1): Assuming no exercise of the underwriters' over-allotment option.
(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:

•: 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."

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

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.

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.

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 "Cash Distribution Policy."
•: 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

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 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.

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 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 units.

Issuance of Additional Securities

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and rights 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 rights to which the units are not entitled.

The holders of units will not have preemptive 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 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 75% 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 over-allotment option is not exercised, our management and Quantum Energy Partners will hold, directly and indirectly, an aggregate of 10,360,955 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 % 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, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions and the representations described below, that we will be treated as a partnership, and each of our operating subsidiaries (other than Linn Operating, 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 % 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 approximate distribution 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 50,000 barrels of oil (or the equivalent amount of natural gas) on any day during the taxable year or in the retail marketing of oil and gas 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.

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 12-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 application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a

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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, even though that position may be 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. 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, other foreign persons and regulated investment companies 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. Effective for taxable years of a regulated investment company beginning after October 22, 2004, the American Jobs Creation Act of 2004 generally treats income from the ownership of units in a "qualified publicly traded partnership" as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded

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partnership. For taxable years of a regulated investment company beginning on or before October 22, 2004, very little of our income will be treated as derived from a permitted source.

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.

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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 and Assessable Penalties,"
•: 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.
KeyBanc Capital Markets, a Division of McDonald Investments Inc.

	Total	5,510,000

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 $2.9 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.

We have granted to the underwriters an option to purchase up to an aggregate of 826,500 additional units at the initial price to the public less the underwriting discount set forth on the

134

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. 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, in its 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 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.

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.

•: 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 the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing units in the open market.

135

•: 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 the over-allotment option. If the underwriters sell more units than could be covered by the over-allotment option, 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."

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

136

•: 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 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.

137

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 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 period from April 1, 2003 through May 31, 2003, the acquisition from Waco Oil and Gas Co., Inc. for the period from April 1, 2003 through October 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 period from April 1, 2003 through April 30, 2004 and the acquisition from Cabot Oil & Gas Corporation for the period from April 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.

Information included in this prospectus regarding our estimated quantities of natural gas and oil reserves was prepared by Schlumberger Data & Consulting Services, independent petroleum engineers, as stated in their reserve report with respect thereto. The reserve report of Schlumberger Data & 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.

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 Judiciary Plaza, 450 Fifth Street, N.W., Room 1024, 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 Room 1024, Judiciary Plaza, 450

138

Fifth Street, N.W., 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.

139

INDEX TO FINANCIAL STATEMENTS


Linn Energy, LLC
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, as of December 31, 2003 and 2004 and March 31, 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 three month period ended March 31, 2004 and 2005
Consolidated Statements of Members' Capital, for the period from March 14, 2003 (Inception) to December 31, 2003 and year ended December 31, 2004 and for the three month period ended March 31, 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 three month period ended March 31, 2004 and 2005
Notes to Consolidated Financial Statements, December 31, 2003 and 2004 and for the three month period ended March 31, 2004 and 2005
Natural Gas and Oil Property Acquired from Emax Oil Company
Independent Auditors' Report
Statement of Revenues and Direct Operating Expenses, for the period April 1, 2003 through May 31, 2003
Notes to Consolidated Financial Statements, April 1, 2003 through May 31, 2003
Natural Gas and Oil Property Acquired from Lenape Resources, Inc.
Independent Auditors' Report
Statement of Revenues and Direct Operating Expenses, for the period April 1, 2003 through July 31, 2003
Notes to Consolidated Financial Statements, April 1, 2003 through July 31, 2003
Natural Gas and Oil Property Acquired from Cabot Oil & Gas Corporation
Independent Auditors' Report
Statement of Revenues and Direct Operating Expenses, for the period April 1, 2003 through September 30, 2003
Notes to Consolidated Financial Statements, April 1, 2003 through September 30, 2003
Natural Gas and Oil Property Acquired from Waco Oil & Gas Company
Independent Auditors' Report
Statement of Revenues and Direct Operating Expenses, for the period April 1, 2003 through October 31, 2003
Notes to Consolidated Financial Statements, April 1, 2003 through October 31, 2003
Natural Gas and Oil Property Acquired from Mountain V Oil & Gas, Inc.
Independent Auditors' Report
Statement of Revenues and Direct Operating Expenses, for the period January 1, 2004 through April 30, 2004 and for the period April 1, 2003 through December 31, 2003
Notes to Consolidated Financial Statements, April 1, 2003 through April 30, 2004

F-1

Natural Gas and Oil Property Acquired from Westar Energy, Inc., Pentex Energy, Inc. and Seahorse Exploration, Inc.

Report of Independent Public Accounting Firm

Statement of Revenues and Direct Operating Expenses, nine month periods ended December 31, 2003 and September 30, 2004

Notes to Consolidated Financial Statements, April 1, 2003 through September 30, 2004

Linn Energy, LLC

Unaudited Pro Forma Combined Statement of Operations, for the year ended December 31, 2004

Notes to Unaudited Pro Forma Combined Statement of Operations, year ended December 31, 2004

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 AS OF MARCH 31, 2005

				As of December 31,
				As of December 31,				As of March 31, 2005
				2003		2004		As of March 31, 2005
								(unaudited)
Assets
Current assets:
	Cash and cash equivalents			$	22,042,504	$	2,188,244	$	1,220,213
	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		3,865,707
		Fair value of natural gas and interest rate swaps (note 3 and 7)			27,700		—		113,657
		Other			207,198		82,539		120,132
	Inventory				63,806		109,985		110,513
	Prepaid expenses and other current assets				98,972		93,782		348,130

			Total current assets		23,756,453		7,281,746		5,778,352

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		103,439,632
		Less accumulated depreciation, depletion, and amortization			946,123		4,559,714		5,553,381

					53,036,024		97,122,591		97,886,251

Property, plant, and equipment:
	Land				45,000		47,500		47,500
	Buildings and leasehold improvements				39,138		468,600		470,349
	Vehicles				184,453		689,892		640,456
	Furniture and equipment				127,522		342,487		364,667

					396,113		1,548,479		1,522,972
	Less accumulated depreciation				25,996		161,724		205,782

					370,117		1,386,755		1,317,190

Other assets:
	Prepaid drilling costs				2,300,643		362,095		404,958
	Equity investment				110,313		69,685		59,604
	Operating bonds				75,342		110,699		141,478

					2,486,298		542,479		606,040

			Total assets	$	79,648,892	$	106,333,571	$	105,587,833

See accompanying notes to consolidated financial statements.

F-4

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2003 AND 2004 AND AS OF MARCH 31, 2005

			As of December 31,
			As of December 31,						As of March 31, 2005
			2003			2004			As of March 31, 2005
									(unaudited)
Liabilities and Members' Capital
Current liabilities:
	Current portion of long-term notes payable (note 9)		$	—		$	58,113		$	58,732
	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			1,793,077
	Current portion of natural gas swaps fair value (note 7)			718,901			3,456,944			7,911,929
	Revenue distribution			583,794			2,493,145			2,277,826
	Accrued interest payable (note 3)			222,594			411,245			112,938
	Gas purchases payable			—			481,993			504,499

		Total current liabilities		20,318,937			9,967,574			12,659,001

Long-term liabilities:
	Long-term portion of notes payable (notes 9 and 16)			—			539,867			5,525,026
	Credit facility (note 3)			41,517,954			72,210,107			75,240,834
	Long-term portion of interest rate swaps (note 3)			188,928			1,408,629			605,254
	Asset retirement obligation (note 10)			2,053,077			3,856,584			3,896,827
	Long-term portion of natural gas swaps fair value (note 7)			880,953			7,639,555			9,242,850

		Total long-term liabilities		44,640,912			85,654,742			94,510,791

		Total liabilities		64,959,849			95,622,316			107,169,792
Members' capital:
	Members' capital			16,023,743			16,023,743			16,023,743
	Accumulated loss			(1,334,700	)		(5,312,488	)		(17,605,702	)

				14,689,043			10,711,255			(1,581,959	)

		Total liabilities and members' capital	$	79,648,892		$	106,333,571		$	105,587,833

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 THREE MONTH PERIOD ENDED MARCH 31, 2004 AND 2005

			Period from March 14, 2003 (inception) to December 31, 2003
									Three Month Period Ended March 31,
						Year Ended December 31, 2004			Three Month Period Ended March 31,
						Year Ended December 31, 2004			2004			2005
									(unaudited)
Revenues:
	Natural gas and oil sales		$	3,323,465		$	21,231,640		$	3,955,440		$	6,146,326
	Realized gain (loss) on natural gas swaps (note 7)			162,890			(2,239,506	)		(170,175	)		(8,575,226	)
	Unrealized (loss) on natural gas swaps (note 7)			(1,599,854	)		(8,764,855	)		(2,683,098	)		(6,580,361	)
	Natural gas marketing income			—			520,340			—			813,638
	Other income			3,778			160,131			20,383			74,219

				1,890,279			10,907,750			1,122,550			(8,121,404	)

Expenses:
	Operating expenses			916,638			5,459,503			1,144,967			1,834,222
	Natural gas marketing expense			—			481,993			—			789,667
	General and administrative expenses			845,633			1,583,054			220,659			489,474
	Depreciation, depletion and amortization			972,119			3,749,318			572,434			1,046,269

				2,734,390			11,273,868			1,938,060			4,159,632

				(844,111	)		(366,118	)		(815,510	)		(12,281,036	)

Other income and (expenses):
	Interest income			34,139			7,379			3,096			290
	Interest and financing expense (note 3)			(516,883	)		(3,530,360	)		(823,230	)		19,606
	Investment (loss)			(2,929	)		(56,126	)		(14,032	)		(10,081	)
	(Loss) on sale of assets			(4,916	)		(32,563	)		—			(21,993	)

				(490,589	)		(3,611,670	)		(834,166	)		(12,178	)

		Net (loss)	$	(1,334,700	)	$	(3,977,788	)	$	(1,649,676	)	$	(12,293,214	)

See accompanying notes to consolidated financial statements.

F-6

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS' CAPITAL

FOR THE PERIOD
FROM MARCH 14, 2003 (INCEPTION) TO DECEMBER 31, 2003
AND YEAR ENDED DECEMBER 31, 2004
AND FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2005

	Members' Capital			Accumulated Loss			Total Members' Capital
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 three months ended March 31, 2005 (unaudited)		—			(12,293,214	)		(12,293,214	)

Balance as of March 31, 2005 (unaudited)	$	16,023,743		$	(17,605,702	)	$	(1,581,959	)

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 THREE MONTH PERIOD ENDED MARCH 31, 2004 AND 2005

					Period from March 14, 2003 (inception) to December 31, 2003
											Three Month Period Ended March 31,
								Year Ended December 31, 2004			Three Month Period Ended March 31,
								Year Ended December 31, 2004			2004			2005
											(unaudited)
Cash flow from operating activities:
	Net (loss)				$	(1,334,700	)	$	(3,977,788	)	$	(1,649,676	)	$	(12,293,214	)
	Adjustments to reconcile net (loss) to net cash provided by operating activities:
		Depreciation, depletion and amortization				972,119			3,749,318			572,434			1,046,269
		Amortization of deferred financing fees				20,454			123,403			25,208			45,727
		Loss on sale of assets				4,916			32,563			—			21,993
		Loss from equity investment				2,929			56,126			14,032			10,081
		Accretion of asset retirement obligation				14,683			73,501			16,203			24,800
		Unrealized loss on natural gas swaps				1,599,854			8,764,855			2,683,098			6,580,361
		Unrealized loss (gain) on interest rate swaps				188,928			1,258,634			460,889			(955,965	)
		Changes in assets and liabilities:
			(Increase) decrease in accounts receivable			(1,523,471	)		(3,366,264	)		(589,449	)		903,896
			(Increase) in inventory			—			(179	)		(230	)		(528	)
			(Increase) decrease in prepaid expenses and other assets			(98,972	)		5,190			28,648			(254,348	)
			(Increase) decrease in operating bonds			(75,342	)		(35,357	)		258			(30,779	)
			Increase (decrease) in accounts payable and accrued expenses			376,471			1,338,981			(278,375	)		(1,234,124	)
			(Decrease) increase in natural gas swaps receivable/payable			(27,700	)		759,490			34,225			(522,081	)
			Increase (decrease) in revenue distribution			583,794			1,909,351			274,145			(215,319	)
			Increase in asset retirement obligation			2,299			18,754			3,579			10,809
			Increase (decrease) in accrued interest payable			222,594			188,651			—			(298,307	)
			Increase in gas purchases payable			—			481,993			—			22,506

				Net cash provided by (used in) operating activities		928,856			11,381,222			1,594,989			(7,138,223	)

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	)		(4,678,511	)		(1,752,693	)
	Purchases of property and equipment					(409,613	)		(1,518,966	)		(112,527	)		(29,058	)
	Proceeds from sale of assets					8,584			384,037			—			24,028
	(Increase) decrease in prepaid drilling cost					(2,300,643	)		1,938,548			2,188,536			(42,863	)
	Purchase of equity investment					(113,242	)		(15,498	)		—			—

				Net cash (used in) investing activities		(36,407,595	)		(62,402,212	)		(20,611,840	)		(1,800,586	)

Cash flow from financing activities:
	Proceeds from notes payable					—			604,358			—			5,000,000
	Principal payments on notes payable					—			(6,378	)		—			(14,222	)
	Proceeds from credit facility					41,800,000			30,805,000			—			3,000,000
	Deferred financing fees					(302,500	)		(236,250	)		—			(15,000	)
	Capital contributions by members					16,323,743			—			—			—
	Return on capital					(300,000	)		—			—			—

				Net cash provided by financing activities		57,521,243			31,166,730			—			7,970,778

				Net increase (decrease) in cash		22,042,504			(19,854,260	)		(19,016,851	)		(968,031	)
Cash and cash equivalents:
	Beginning					—			22,042,504			22,042,504			2,188,244

	Ending				$	22,042,504		$	2,188,244		$	3,025,653		$	1,220,213

		Cash payments for interest			$	84,907		$	1,959,672		$	337,133		$	1,188,939
Supplemental disclosures of noncash flow information:
	Increase in accounts payable related to acquisitions				$	407,839		$	903,910		$	—		$	—
	Increase in property acquisition payable					18,009,338			—			—			—
	Increase in inventory related to acquisitions					63,806			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			23,141			4,634

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 THREE MONTH PERIOD ENDED
MARCH 31, 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 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 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 & 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.

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.

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 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

F-13

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.

(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): Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141 — Business Combinations, which requires the purchase method of accounting for business

F-14

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, 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.

F-15

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 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.

F-16

•: 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.
•: 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.

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 March 31, 2005, the Company had borrowed $75.6 million (unaudited). As of March 31, 2005, the applicable weighted average interest rate was 4.6% (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

F-17

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 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 March 31, 2005, the total fair value of the interest rate swap agreement was a liability of $491,597. The current portion of $113,657 is recorded as a receivable on the balance sheet. (Losses) gains due to changes in the fair value of $(460,889) and $955,965 for the quarters ended March 31, 2004 and 2005, respectively, are recorded in interest and financing expense on the accompanying consolidated statements of operations (unaudited).

F-18

As of December 31, 2003 and 2004 and March 31, 2005, the credit facility consists of the following:

	December 31, 2003			December 31, 2004			March 31, 2005 (unaudited)
Outstanding balance	$	41,800,000		$	72,605,000		$	75,605,000
Less deferred financing fees, net of amortization of $20,454, $143,857 and $189,584 (unaudited)		(282,046	)		(394,893	)		(364,166	)

	$	41,517,954		$	72,210,107		$	75,240,834

Accrued interest was $222,594, $411,245 and $112,938 (unaudited) at December 31, 2003 and 2004, and March 31, 2005, respectively.

(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. 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, 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.

(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.

F-19

(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.

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 Swaps

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 to hedge a portion of its forecasted natural gas sales.

F-20

The natural gas swap contracts are not designated as hedges and, accordingly, the changes in fair value were recorded in current period earnings:

	December 31
	December 31						March 31, 2005
	2003			2004			March 31, 2005
Net unrealized gain (loss) at balance sheet date expected to be settled within next 12 months	$	(718,901	)	$	(2,725,154	)	$	(7,703,703	)
Net unrealized gain (loss) at balance sheet date expected to be settled beyond next 12 months		(880,953	)		(7,639,555	)		(9,242,850	)
Outstanding notional amounts of hedges in MMBtu's (in thousands)		5,625			12,628			11,758
Maximum number of months hedges outstanding		58			61			58

In addition to the short-term unrealized amounts above, the Company also has realized a current asset of $27,700 and current liabilities of $731,790 and $208,226 as of December 31, 2003 and 2004, and March 31, 2005 respectively, for realized gains or losses which were not paid or received as of year-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 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.

F-21

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.

(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

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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 are included in the total asset retirement obligation on the accompanying consolidated balance sheets.

F-23

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 quarter ended March 31, 2005:

	December 31, 2003		December 31, 2004		March 31, 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		4,634
Cash withheld during the current period from unrelated third parties who own working interests		2,299		18,754		10,809
Current period accretion expense		14,683		73,501		24,800

Carrying amount of asset retirement obligations at December 31	$	2,053,077	$	3,856,584	$	3,896,827

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 cost:
	Property acquisition costs, proved	$	51,659,634	$	29,256,320
	Development costs		286,418		16,732,586

		$	51,946,052	$	45,988,906

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

F-24

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	$	51,946,052	$	91,030,608
Undeveloped properties		—		6,904,350
Capitalized asset retirement cost		2,036,095		3,747,347

		53,982,147		101,682,305
Less accumulated depreciation, depletion, and amortization		946,123		4,559,714

	$	53,036,024	$	97,122,591

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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 swaps			(162,890	)		2,239,506
	Unrealized losses on natural gas swaps			1,599,854			8,764,855

		Net natural gas and oil sales		1,886,501			10,227,279

Expenses:
	Operating expenses			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

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, but does not include the depreciation applicable to 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, Inc., at December 31, 2003 and 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

F-26

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		—		11,673,905

		Beginning of year as revised	—		81,478,905
	New discoveries and extensions:
		Appalachian basin	—		5,566,000
	Acquisitions		70,607,481		36,100,000
	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.

(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 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-27

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		—			27,276,385
Development costs incurred during the period		286,418			16,732,586
Revisions of previous quantity estimates		—			56,771,424
Less change in discount		(232,204,590	)		(204,799,260	)

	$	126,341,459		$	88,692,291

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

F-28

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 payoff 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.

In connection with the new credit facility, the Company converted the 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.

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•: 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 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. Further, on June 1, 2005, Linn Operating, LLC was converted into a corporation and changed its name to Linn Operating, Inc.

F-30

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 Emax Oil Company for the period April 1, 2003 through May 31, 2003. This financial statement is the responsibility of Linn Energy, LLC'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 Emax Oil Company as described in Note 1 for the period April 1, 2003 through May 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-31

LINN ENERGY, LLC

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM EMAX OIL COMPANY

FOR THE PERIOD APRIL 1, 2003 THROUGH MAY 31, 2003

Revenues-natural gas and oil sales	$	150,325
Direct operating expenses		0

Excess of revenues over direct operating expenses	$	150,325

See accompanying notes to statement of revenues and direct operating expenses.

F-32

LINN ENERGY, LLC
(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM EMAX OIL COMPANY)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APRIL 1, 2003 THROUGH MAY 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 Emax Oil Company (Emax) for the period April 1, 2003 through May 31, 2003. 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 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 Emax 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. 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 and severance taxes. During this time period the company did not employ any well tenders or incur any other direct operating expenses.

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 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 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 revenue and expenses during the reporting period. Actual results could differ from those estimates.

(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

F-33

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. 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		5,193,045
		Production	(17,017	)
	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 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 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.

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-34

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	$	14,831
Future production costs		(2,225	)
Future development and abandonment cost		(42	)

Future net cash flows		12,564
10% annual discount for estimated timing of cash flows		(7,139	)

Standardized measure of discounted future net cash flows	$	5,425

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	$	6,135
Sales of natural gas and oil produced, net of production expenses		(150	)
Changes in prices and production costs		(1,270	)
Accretion of discount		710

End of period	$	5,425

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 speculative 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-35

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.

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-36

LINN ENERGY, LLC

STATEMENT 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-37

LINN ENERGY, LLC
(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM LENAPE RESOURCES, INC.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 and severance taxes.

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.

F-38

(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

			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.

F-39

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-40

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 Cabot Oil & Gas Corporation for the period April 1, 2003 through September 30, 2003. This financial statement is the responsibility of Cabot Oil & Gas Corporation's management. Our responsibility is to express an opinion on this financial statement based on our audit.

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 Cabot Oil & Gas Corporation as described in Note 1 for the period April 1, 2003 through September 30, 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-41

LINN ENERGY, LLC

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM CABOT OIL & GAS CORPORATION

FOR THE PERIOD APRIL 1, 2003 THROUGH SEPTEMBER 30, 2003

Revenues-natural gas and oil sales	$	2,018,104
Direct operating expenses		397,388

Excess of revenues over direct operating expenses	$	1,620,716

See accompanying notes to statement of revenues and direct operating expenses.

F-42

LINN ENERGY, LLC
(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM CABOT OIL & GAS CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APRIL 1, 2003 THROUGH SEPTEMBER 30, 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 Cabot Oil & Gas Corporation (Cabot) for the period April 1, 2003 through September 30, 2003. 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 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 Cabot 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 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 exploitation expenditures related to the Property were insignificant in the relevant period. Accordingly, the historical statement 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.

(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

F-43

(a): Reserve Quantity Information

			Natural gas (Mcfe)
Proved developed and undeveloped reserves:
	March 31, 2003		14,243,335
		Production	(376,832	)
	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 is a disclosure requirement under Statement of Financial Accounting Standards No. 69.

F-44

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	$	70,858
Future production costs		(10,629	)
Future development and abandonment cost		(67	)

Future net cash flows		60,162
10% annual discount for estimated timing of cash flows		(34,186	)

Standardized measure of discounted future net cash flows	$	25,976

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	$	28,565
Sales of natural gas and oil produced, net of production expenses		(1,621	)
Changes in prices and production costs		(3,557	)
Accretion of discount		2,589

End of period	$	25,976

F-45

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 Waco Oil & Gas Company for the period April 1, 2003 through October 31, 2003. This financial statement is the responsibility of Waco Oil & Gas Company. Our responsibility is to express an opinion on this financial statement based on our audit.

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, 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 oil and gas 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 oil and gas property acquired from Waco Oil & Gas Company as described in Note 1 for the period April 1, 2003 through October 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-46

LINN ENERGY, LLC

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM WACO OIL & GAS COMPANY

FOR THE PERIOD APRIL 1, 2003 THROUGH OCTOBER 31, 2003

Revenues-natural gas and oil sales	$	3,221,030
Direct operating expenses		479,128

Excess of revenues over direct operating expenses	$	2,741,902

See accompanying notes to statement of revenues and direct operating expenses.

F-47

LINN ENERGY, LLC
(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM WACO OIL & GAS COMPANY)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APRIL 1, 2003 THROUGH OCTOBER 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 Waco Oil & Gas Company (Waco) for the period April 1, 2003 through October 31, 2003. The Property was purchased by Linn Energy, LLC (the Company) on October 31, 2003, for approximately $30.63 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 Waco 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 exploitation expenditures related to the Property were insignificant in the relevant period. Accordingly, the historical statement of revenues and direct operating expenses of Waco'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-48

(2) Supplemental Financial Information for Natural Gas and Oil Producing Activities (Unaudited)

(a): Reserve Quantity Information

			Natural gas (Mcfe)
Proved developed and undeveloped reserves:
	March 31, 2003		48,112,880
		Production	(664,431	)

	October 31, 2003		47,448,449

Proved developed reserves:
	October 31, 2003		24,099,379

(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.

F-49

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		$	109,652
	Future production costs		(16,448	)
	Future development and abandonment cost		(454	)

Future net cash flows			92,750
10% annual discount for estimated timing of cash flows			(52,703	)

Standardized measure of discounted future net cash flows		$	40,047

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	$	49,517
Sales of natural gas and oil produced, net of production expenses		(2,742	)
Changes in prices and production costs		(16,198	)
Accretion of discount		9,470

End of period	$	40,047

F-50

INDEPENDENT AUDITORS' REPORT

To the Members
Linn Energy, LLC

We have audited the accompanying statements of revenues and direct operating expenses of the oil and gas property acquired from Mt. V. Oil & Gas for the periods January 1, 2004 through April 30, 2004 and April 1, 2003 through December 31, 2003. These financial statements are the responsibility of Mt. 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 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 oil and gas 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 presents fairly, in all material respects, the revenues and direct operating expenses of the oil and gas property acquired from Mt. V. Oil & Gas as described in Note 1 for the period January 1, 2004 through April 30, 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
April 27, 2005

F-51

LINN ENERGY, LLC

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES —
NATURAL GAS AND OIL PROPERTY ACQUIRED FROM
MOUNTAIN V OIL & GAS, INC.

FOR THE PERIOD APRIL 1, 2003 THROUGH DECEMBER 31, 2003
AND
FOR THE PERIOD JANUARY 1, 2004 THROUGH APRIL 30, 2004

	2003		2004
Revenues—natural gas and oil sales	$	2,067,735	$	712,151
Direct operating expenses		581,411		185,474

Excess of revenues over direct operating expenses	$	1,486,324	$	526,677

See accompanying notes to statements of revenues and direct operating expenses.

F-52

LINN ENERGY, LLC
(NATURAL GAS AND OIL PROPERTY ACQUIRED FROM MOUNTAIN V OIL & GAS, INC.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APRIL 1, 2003 THROUGH DECEMBER 31, 2003
AND
JANUARY 1, 2004 THROUGH APRIL 30, 2004

(1) Basis of presentation

The accompanying financial statements presents the revenues and direct operating expenses of the natural gas and oil property (the Property) acquired from Mountain V Oil & Gas, Inc. (Mt. V.) for the periods April 1, 2003 through December 31, 2003 and January 1, 2004 through April 30, 2004. The Property was purchased by Linn Energy, LLC (the Company) on May 7, 2004, for approximately $12.17 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.

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 and severance taxes.

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 exploitation expenditures related to the Property were insignificant in the relevant period. Accordingly, the historical statement 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-53

(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 (Mcf)
Proved developed and undeveloped reserves:
	March 31, 2003		17,654,322
		Production	(552,733	)

	April 30, 2004		17,101,589

Proved developed reserves:
	April 30, 2004		10,136,594

(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 requirement under Statement of Financial Accounting Standards No. 69.

F-54

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		$	52,111		$	55,549
	Future production costs		(7,817	)		(8,332	)
	Future development and abandonment cost		(308	)		(308	)

Future net cash flows			43,986			46,909
10% annual discount for estimated timing of cash flows			(24,994	)		(26,656	)

Standardized measure of discounted future net cash flows		$	18,992		$	20,253

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	$	21,326		$	18,992
Sales of natural gas and oil produced, net of production expenses		(1,486	)		(527	)
Changes in prices and production costs		(3,182	)		3,049
Accretion of discount		2,334			1,261

End of period	$	18,992		$	20,253

F-55

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 oil and gas 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-56

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-57

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 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-58

(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 January 1, 2005. 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-59

(a): Reserve Quantity Information

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	28,588
		Production	—	(4,121	)

	December 31, 2003		1	24,467

	January 1, 2004		1	24,467
		Production	—	(3,469	)

	September 30, 2004		1	20,998

Proved developed reserves:
	April 1, 2003		1	18,593
		Production	—	(4,121	)

	December 31, 2003		1	14,472

	January 1, 2004		1	14,472
		Production	—	(3,469	)

	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-60

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	)		(81,949	)

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 oil and gas 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 speculative 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-61

LINN ENERGY, LLC

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

The following unaudited pro forma combined statement of operations for the year ended December 31, 2004 is 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) and Pentex Energy, Inc. (Pentex) 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 and Pentex properties as if the transactions had occurred on January 1, 2004. The acquisitions from Mountain V and Pentex were completed as of May 7, 2004 and September 30, 2004, respectively, and accordingly the operating results related to the acquired properties are included in our historical results from those dates. The transaction 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 statement of operations is presented for illustrative purposes only, and does not purport to be indicative of the 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 statement 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 and Pentex and the notes thereto included elsewhere in this prospectus.

		Linn Energy, LLC Historical			Mountain V January 1, 2004 through May 7, 2004		Pentex January 1, 2004 through September 30, 2004		Pro Forma Adjustments			Pro Forma
Revenues:
	Natural gas and oil revenue	$	21,231,640		$	712,151	$	2,210,531	$	—		$	24,154,322
	Realized gain (loss) on natural gas swaps		(2,239,506	)		—		—		—			(2,239,506	)
	Unrealized (loss) on natural gas swaps		(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		—			13,830,432

Expenses:
	Operating expenses		5,459,503			185,474		493,652		—			6,138,629
	Natural gas and marketing expense		481,993			—		—		—			481,993
	General and administrative expense		1,583,054			—		—		41,109	(c)		1,624,163
	Depreciation, depletion, and amortization		3,749,318			—		—		728,927	(a)		4,478,245

			11,273,868			185,474		493,652		770,036			12,723,030

			(366,118	)		526,677		1,716,879		(770,036	)		1,107,402

Other income and (expense)
	Interest income		7,379			—		—		—			7,379
	Interest and financing expense		(3,530,360	)		—		—		(620,313)	(b)		(4,150,673	)
	Investment (loss)		(56,126	)		—		—		—			(56,126	)
	(Loss) on sale of assets		(32,563	)		—		—		—			(32,563	)

			(3,611,670	)		—		—		(620,313	)		(4,231,983	)

	Net (loss)	$	(3,977,788	)	$	526,677	$	1,716,879	$	(1,390,349	)	$	(3,124,580	)

F-62

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2004

1. Pro Forma Adjustments

The unaudited pro forma statements of income have been adjusted to:

a. record incremental depreciation, depletion, and amortization expense, using the units-of-production method, resulting from the acquisition of the Mountain V and Pentex properties;

b. record interest expense associated with debt of approximately $26.6 million incurred under the old credit facility to fund the purchase price. Applicable interest rates for the acquisitions were 4.1% and 4.3% for Mountain V and Pentex, respectively; and

c. record accretion expense related to asset retirement obligation on properties acquired from Mountain V and Pentex.

We did not incur any incremental increase in general and administrative expense as a result of these acquisitions.

2. Oil and Gas Revenue Disclosures

The following table sets forth certain unaudited pro forma information concerning our proved oil and gas reserves for the year ended December 31, 2004, giving effect to the Mountain V and Pentex transactions as if they had occurred on January 1, 2004. The oil and gas reserves 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:

Proved Oil and Natural Gas Reserves

	MMcfe
	Linn Energy		Mountain V		Pentex		Pro Forma

January 1, 2004	69,805		17,654		24,467		111,926
Extension, discoveries, and other additions	5,566		—		—		5,566
Revisions of previous estimates	11,674		—		—		11,674
Production	(3,385	)	(553	)	(3,469	)	(7,407	)
Acquisition	36,100		(17,101	)	(20,998	)	(1,999	)

December 31, 2004	119,760		—		—		119,760

F-63

LINN ENERGY, LLC

NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATION—(Continued)

The following table sets forth unaudited pro forma information for the principal sources of changes in discounted future net cash flows from our proved oil and gas for the year ended December 31, 2004, and giving effect to the acquisition of the Mountain V and Pentex properties as if it had occurred on January 1, 2004. The discounted future net cash flows from proved oil and gas reserves are already included in our information as of December 31, 2004. Cash flows relating to the Mountain V and Pentex properties are based on our evaluation of reserves and on information provided by Mountain V and Pentex. 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 oil and gas properties acquired from Mountain V and Pentex included herein, for a discussion of the assumptions used in preparing the information presented.

The following table sets forth the principal sources of change in discounted future net cash flows (dollars in thousands):

	Linn Energy			Mountain V			Pentex			Pro Forma
Standardized measure at beginning of year	$	126,341		$	18,992		$	10,237		$	155,570
Sales and transfers of oil and gas produced, net of production costs		(16,608	)		(527	)		(1,717	)		(18,852	)
Extensions and discussions, net of future production and development costs		27,276			—			—			27,276
Change in estimated future development costs		17,341			—			—			17,341
Net changes in prices and production costs		15,008			3,049			33,472			51,529
Development cost incurred during the period		16,733			—			—			16,733
Revisions of quantities		56,771			—			3,262			60,033
Change in discount		(204,799	)		1,261			(3,763	)		(207,301	)
Acquisition		176,970			(22,775	)		(41,491	)		112,704

Net increase (decrease) in standardized measure		88,692			(18,992	)		(10,237	)		59,463

Standardized measure at end of year	$	215,033		$	—		$	—		$	215,033

F-64

APPENDIX A

FORM OF
SECOND AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT
OF
LINN ENERGY, LLC

A-1

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 demonstrates 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. Proved natural gas and oil 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 shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable 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.

PV-10. 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 SEC (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%.

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.

Successful well. A well that we have completed or as to which we have a defined plan to complete.

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

ESTIMATED AVAILABLE CASH

The following table shows the calculation of estimated available cash and should be read in conjunction with "Cash Available for Distribution" and historical consolidated financial statements included in this prospectus. This calculation of available cash does not include any deduction for the establishment of reserves for operations, capital expenditures, debt service requirements and cash distributions to our unitholders for any quarter subsequent to March 31, 2005. The pro forma financial data gives effect to the properties acquired from Mountain V Oil & Gas, Inc. and Pentex Energy, Inc. in 2004 as if they occurred on January 1, 2004. For a discussion of the ability of our board of directors to establish cash reserves, see "Cash Distribution Policy."

	Pro Forma for the Year Ended December 31, 2004			Three Months Ended March 31, 2005
	(unaudited)
	(in thousands)
Net (loss)	$	(3,125	)	$	(12,293	)
Plus: Depreciation, depletion and amortization		4,478			1,046
Plus: Amortization of deferred financing fees		123			46
Plus: Loss on sale of assets		32			22
Plus: Loss from equity investment		56			10
Plus: Accretion of asset retirement obligation		115			25
Plus: Unrealized loss on natural gas swaps		8,765			6,580
Plus: Unrealized loss (gain) on interest rate swaps		1,259			(956	)
Plus: Realized loss on cancelled natural gas swaps(1)		—			7,977

Distributable cash flow	$	11,703		$	2,457

Plus: Available working capital borrowings (2)		—			—
Less: Incremental general and administrative expenses (3)		(1,400	)		(350	)

Estimated available cash (4)	$	10,303		$	2,107

(1): During the quarter ended March 31, 2005, we cancelled (before their original settlement date) out-of-the-money natural gas hedges for the fourth quarter of 2005, and for the years ending December 31, 2006 and 2007, and realized a loss of $8.0 million. We subsequently hedged similar volumes at higher prices.
(2): In 2004, our credit facility did not permit borrowings for distribution to our members. Upon completion of this offering, we will have the ability to borrow under the terms of our 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.

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(3): 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.
(4): The amount of available cash needed to pay the initial quarterly distribution for one quarter and for four quarters on the units to be outstanding immediately after this offering is:

		One Quarter			Four Quarters
		(in thousands)
Units		$			$

The pro forma amounts reflected above would have been sufficient to cover the following percentages of the initial quarterly distribution on the units outstanding for the year ended December 31, 2004 and for the quarter ended March 31, 2005:

		Year Ended December 31, 2004		Quarter Ended March 31, 2005
Units			%		%

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APPENDIX D

RESERVE REPORT

Data and Consulting Services
1310 Commerce Drive Park Ridge 1 Pittsburgh, PA 15275-1011 Tel: 412-787-5403 Fax: 412-787-2906
28 March, 2005
Linn Energy, LLC South Mark Executive Suites Suite 100 1700 N. Highway Avenue Pittsburgh, PA 15241

Dear Gentlemen:

At the request of Linn Energy, LLC (Linn Energy), Schlumberger Data and Consulting Services (DCS) has prepared a reserve and economic evaluation of certain proved and probable oil and gas interests as of December 31, 2004. These properties are located in various counties of New York, Pennsylvania, and West Virginia. Unescalated December 30, 2004 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). Table 2 summarizes the Probable Oil and Gas Reserve values. 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 DECEMBER 31, 2004

		Proved Producing Reserves	Proved Non-producing Reserves	Proved Undeveloped Reserves	Total Proved Reserves
Remaining Net Reserves
Oil — Mbbls		141.386	0.000	0.000	141.386
Gas — MMscf		72,323.477	1,194.070	45,393.637	118,911.188
Income Data (M$)
Future Net Revenue		516,391.844	8,596.988	315,138.094	840,126.938
Deductions
	Operating Expense	96,955.797	966.619	19,033.250	116,955.680
	Production Taxes	16,723.202	555.246	12,438.211	29,716.658
	Investment	0.000	0.000	41,417.000	41,417.000
	Future Net Income (FNI)	402,712.781	7,075.125	242,249.578	652,037.562
Discounted PV @ 10% (M$)		147,682.734	2,795.915	64,555.039	215,033.750

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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.

TABLE 2

ESTIMATED NET INCOME
CERTAIN PROBABLE OIL AND GAS INTERESTS
SEC PRICING & ESCALATION
LINN ENERGY, LLC
AS OF DECEMBER 31, 2004

		Probable
Remaining Net Reserves
Oil — Mbbls		0.000
Gas — MMscf		30,769.396
Income Data (M$)
Future Net Revenue		212,194.828
Deductions
	Operating Expense	12,246.112
	Production Taxes	8,309.996
	Investment	29,049.828
Future Net Income (FNI)		162,588.938
Discounted PV @ 10% (M$)		29,341.072

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.

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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), proved undeveloped (PUD), and probable (PRB) 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 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). All probable reserves conform to the definitions approved by the Society of Petroleum Engineers, Inc. (SPE) Board of Directors, March 7, 1997. Both of these reserve definitions are presented in Exhibit 1 of this report. The SEC recognizes only proved reserves. The probable reserves contained in this report should not be summarized with the proved values.

We included in the proved undeveloped category only reserves assigned to undeveloped locations Linn Energy has plans to drill in the next four 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 income (cashflow) is future net revenue less net lease operating, transportation, processing, and marketing expenses, and state severance or production taxes. 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. Future plugging, abandonment, and salvage costs are not included

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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 December 30, 2004 Spot prices adjusted for local differentials, gravity and Btu where applicable. Adjustments were made for transportation, treating, or gathering costs based on actual data.

The operating costs were based on a fixed per well monthly operating expense and variable operating costs for gas and water where applicable. The fixed and variable costs were determined from actual averages for the wells. Severance and ad valorem production taxes were included in this evaluation. Future abandonment costs for the wells were not included in the cash flow projections.

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.

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 not 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.

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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

5,510,000 Units

Representing Limited Liability Company Interests

P R O S P E C T U S

RBC CAPITAL MARKETS

LEHMAN BROTHERS

A.G. EDWARDS

KEYBANC CAPITAL MARKETS

, 2005

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	$	15,662
NASD filing fee		*
Nasdaq National Market listing fee		*
Printing and engraving expenses		*
Accounting fees and expenses		*
Legal fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*

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.

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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 RBC Capital Markets, 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 that are signatory thereto and BNP Paribas, as administrative agent
10.3*	—	Form of Linn Energy, LLC Long-Term Incentive Plan
10.4	—	Stakeholders' Agreement
10.5*	—	Employment Agreement dated as of June 2, 2005, among Linn Energy, LLC, Linn Operating, Inc. and Michael C. Linn
10.6*	—	Employment Agreement dated as of June 2, 2005, among Linn Energy, LLC, Linn Operating, Inc. and Kolja Rockov
21.1	—	List of subsidiaries of Linn Energy, LLC
23.1	—	Consent of KPMG LLP
23.2	—	Consent of Toothman Rice, PLLC
23.3	—	Consent of Elms, Faris & Co., LP
23.4	—	Consent of Schlumberger Data & Consulting Services
23.5*	—	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
23.6*	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
24.1	—	Powers of Attorney (included on the signature page)
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.

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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 June 3, 2005.

		LINN ENERGY, LLC
		By:		/s/ MICHAEL C. LINN Michael C. Linn President and Chief Executive Officer

POWER OF ATTORNEY

The undersigned directors and officers of Linn Energy, LLC hereby constitute and appoint Michael C. Linn and Kolja Rockov, each with full power to act and with full power of substitution and resubstitution, our true and lawful attorneys-in-fact and agents with full power to execute in our name and behalf in the capacities indicated below any and all amendments (including post-effective amendments and amendments thereto) to this registration statement and to file the same, with all exhibits and other documents relating thereto and any registration statement relating to any offering made pursuant to this registration statement that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act with the Securities and Exchange Commission and hereby ratify and confirm all that such attorney-in-fact or his substitute shall lawfully do or cause to be done by virtue hereof.

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)	June 3, 2005
/s/ KOLJA ROCKOV Kolja Rockov	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	June 3, 2005
/s/ DONALD T. ROBINSON Donald T. Robinson	Chief Accounting Officer (Principal Accounting Officer)	June 3, 2005
/s/ TOBY R. NEUGEBAUER Toby R. Neugebauer	Chairman	June 3, 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 RBC Capital Markets, 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 that are signatory thereto and BNP Paribas, as administrative agent
10.3*	—	Form of Linn Energy, LLC Long-Term Incentive Plan
10.4	—	Stakeholders' Agreement
10.5*	—	Employment Agreement dated as of June 2, 2005, among Linn Energy, LLC, Linn Operating, Inc. and Michael C. Linn
10.6*	—	Employment Agreement dated as of June 2, 2005, among Linn Energy, LLC, Linn Operating, Inc. and Kolja Rockov
21.1	—	List of subsidiaries of Linn Energy, LLC
23.1	—	Consent of KPMG LLP
23.2	—	Consent of Toothman Rice, PLLC
23.3	—	Consent of Elms, Faris & Co., LP
23.4	—	Consent of Schlumberger Data & Consulting Services
23.5*	—	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
23.6*	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
24.1	—	Powers of Attorney (included on the signature page)
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.

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