Edgar Filing: Linn Energy, LLC

Linn Energy, LLC 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the fiscal year ended December 31, 2005

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the transition period from to

Commission file number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)


Delaware		65-1177591
(State of organization)		(I.R.S. Employer Identification No.)

650 Washington Road
8th Floor
Pittsburgh, PA		15228
(Address of principal executive offices)		(Zip Code)

(412) 440-1400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Title of Class

Units Representing Limited Liability Company Interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No þ

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check-mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ

The aggregate market value of our voting and non-voting common equity held by non-affiliates of the registrant was approximately $261.0 million on May 8, 2006 based on $20.00 per unit, the last reported sales price of the units on The Nasdaq National Market on such date. As of May 8, 2006, there were 27,832,500 units outstanding.

Documents Incorporated By Reference: None

TABLE OF CONTENTS


		Page

Part I
Item 1.	Business		5
Item 1A.	Risk Factors		18
Item 1B.	Unresolved Staff Comments		30
Item 2.	Properties		31
Item 3.	Legal Proceedings		32
Item 4.	Submission of Matters to a Vote of Security Holders		32
Part II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		33
Item 6.	Selected Financial Data		34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		39
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		56
Item 8.	Financial Statements and Supplementary Data		57
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		57
Item 9A.	Controls and Procedures		57
Item 9B.	Other Information		59
Part III
Item 10.	Directors and Executive Officers of the Registrant		59
Item 11.	Executive Compensation		63
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		66
Item 13.	Certain Relationships and Related Transactions		70
Item 14.	Principal Accountant Fees and Services		71
Part IV
Item 15.	Exhibits and Financial Statement Schedules		71
Signatures			74

PART I

As commonly used in the natural gas and oil industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:

GLOSSARY OF TERMS

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.

Bcf. One 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. One 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. One decatherm, equivalent to one million British thermal units.

Developed acres. Acres spaced or assigned to productive wells.

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

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.

NYMEX. The 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.

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.

Proved reserves. Proved natural gas and oil reserves are the estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of produceable natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Standardized Measure. Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the 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%. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Linn Energy Holdings, LLC, which is not subject to income taxes.

Successful well. A well capable of producing natural gas and/or oil in commercial quantities.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

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

Workover. Operations on a producing well to restore or increase production.

Restatement Overview

This Annual Report on Form 10-K for the year ended December 31, 2005 reports the consolidated financial statements of Linn Energy, LLC (the “Company”) for the year ended December 31, 2005 and amends and restates the prior year consolidated financial statements as of December 31, 2003 and 2004, and for the period March 14, 2003 (inception) to December 31, 2003, the year ended December 31, 2004, and the nine months ended September 30, 2004 and 2005. The restatement also affected production and operational data as restated and included in Item 6, “Selected Financial Data.”

As previously announced in a Current Report on Form 8-K as filed with the Securities and Exchange Commission on April 3, 2006, the Company identified that certain aspects of the Company’s accounting for the purchase price of acquisitions did not properly recognize the acquisition date for natural gas and oil property acquisitions as required by Statement of Financial Accounting Standards (“SFAS”) No. 141 — Business Combinations. The Company further evaluated its natural gas and oil accounting for both acquisitions and operations and identified that corrections were needed to reflect the purchase accounting as of the appropriate acquisition date for natural gas and oil property acquisitions, capitalize certain expenditures for lease acquisition costs, correct depreciation, depletion and amortization, and properly report accounts receivables and general and administrative expenses for fees charged to third parties.

This non-cash restatement had the following effect on our net loss:


		Period from						Nine months ended
		March 14, 2003						September 30,
		(inception) to			Year ended
		December 31, 2003			December 31, 2004			2004			2005

Net (loss) as previously reported		$	(1,334,700	)	$	(3,977,788	)	$	(8,357,298	)	$	(62,855,997	)
Adjustments:
	Acquisition date for purchase accounting		(1,066,229	)		(1,855,735	)		(1,457,712	)		(187,546	)
	Lease acquisition costs		46,120			367,526			290,928			102,602
	Development drilling costs		—			128,253			128,253			—
	Depreciation, depletion and amortization		409,673			92,987			(71,465	)		(299,055	)
	Operating receivables		257,131			428,951			183,877			(24,783	)

Restated net (loss)		$	(1,688,005	)	$	(4,815,806	)	$	(9,283,417	)	$	(63,264,779	)

This non-cash restatement had the following effect on our Adjusted EBITDA. Please see “Non-GAAP Financial Measure” on page 38.


		Period from						Nine months ended
		March 14, 2003						September 30,
		(inception) to			Year ended
		December 31, 2003			December 31, 2004			2004			2005

		(In thousands)
Adjusted EBITDA as previously reported		$	1,777		$	12,228		$	7,981		$	10,164
Adjustments:
	Acquisition date for purchase accounting		(1,066	)		(1,855	)		(1,458	)		(188	)
	Lease acquisition costs		46			368			291			103
	Development drilling costs		—			128			128			—
	Operating receivables		257			429			184			(25	)

Restated Adjusted EBITDA		$	1,014		$	11,298		$	7,126		$	10,054

We have also determined that control deficiencies related to the accounting for the Company’s natural gas and oil property acquisitions and certain operational costs represent material weaknesses in our internal control over financial reporting as of December 31, 2005. Please read Item 9A, “Controls and Procedures.”

History of Corrections

As part of its preparation of the consolidated financial statements for the year ended December 31, 2005, the Company undertook a review of its natural gas and oil accounting and identified the following errors which were incorrectly accounted for and needed to be corrected.

1. Through December 31, 2005 the Company had completed nine acquisitions of natural gas properties and related gathering and pipeline assets. Four of the acquisitions occurred in 2003, two occurred in 2004 and three occurred in 2005. When the Company made the acquisitions of natural gas and oil properties, the stated contractual effective date preceded the closing or settlement date. Within a short period of time after settlement, the Company would receive cash or credit for natural gas and oil produced between the contracted effective date and the acquisition settlement date, and the Company would pay or accrue for operational costs within this same period. For acquisitions occurring in 2003 and 2004, amounts between the contracted effective date and the date of closing were previously recognized in the Company’s consolidated statement of operations instead of being recorded as an adjustment to the purchase price of the related acquisition as required under SFAS No. 141 — Business Combinations. These changes also resulted in corresponding changes to depreciation, depletion and amortization.

2. Certain expenditures for lease acquisition costs and development drilling costs were previously recognized as an expense instead of being capitalized as required under SFAS No. 19 — Financial Accounting and Reporting by Oil and Gas Producing Companies.

3. The Company incorrectly recorded the period end accrual and related intercompany elimination for operating and administrative services provided.

4. The consolidated statements of cash flows have been restated for certain changes in current assets and liabilities that are more accurately reported as investing or financing activities.

Please see also Note 20 to the Company’s consolidated financial statements in Item 8, “Financial Statements and Supplementary Data” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The restatement had no effect on our reserve data, Standardized Measure, cash and cash equivalents, or Predecessor Data included in Item 6, “Selected Financial Data”, and has no material effect on the Company’s 2006 guidance as previously reported in the Company’s Current Report on Form 8-K filed with the SEC on March 7, 2006.

All referenced amounts in this Annual Report on Form 10-K for prior periods and prior period comparisons reflect the balances and amounts on a restated basis.


Item 1.	Business

Overview

Linn Energy, LLC is an independent natural gas and oil development and acquisition company. At December 31, 2005, our reserves were located in the Appalachian Basin, primarily in West Virginia, Pennsylvania, New York and Virginia. From our inception in March 2003 through December 31, 2005, we made nine acquisitions of natural gas properties and related gathering and pipeline assets for a restated aggregate purchase price of $201.5 million, with total proved reserves of 160.1 Bcfe, or a restated acquisition cost of $1.26 per Mcfe. These nine acquisitions included 1,914 producing wells and we have drilled 200 wells since inception, 100% of which were successful in producing natural gas in commercial quantities, resulting in a total of 2,114 wells. As part of our business strategy, we continually evaluate opportunities to acquire additional natural gas and oil properties which complement our asset profile both within the Appalachian Basin and elsewhere in the United States.

Our proved reserves at December 31, 2005 were 193.2 Bcfe, of which approximately 99% were natural gas and 65% were classified as proved developed, with a Standardized Measure of $552.1 million. At December 31, 2005, we operated 1,922, or 91%, of our 2,114 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 29 years based on our December 31, 2005 reserve report and annualized production for the quarter ended December 31, 2005. As of December 31, 2005, we had identified 905 drilling locations, of which 373 were proved undeveloped locations and 532 were other locations, and we had leasehold interests in 145,686 net acres in the Appalachian Basin. From inception through December 31, 2005, we added 33.1 Bcfe of proved natural gas and oil reserves through our drilling activities, at a finding and development cost of $1.31 per Mcfe, which includes the estimated development costs for proved undeveloped reserves.

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), Penn West Pipeline, LLC (formerly Chipperco, LLC) and Mid Atlantic Well Service, Inc. We own, directly or indirectly, all of the ownership interests in our operating subsidiaries. Linn Energy Holdings owns all of our interests in natural gas and oil properties, all of our employees are employed by Linn Operating or Mid Atlantic Well Service, Penn West Pipeline owns and operates our natural gas gathering assets and Mid Atlantic Well Service conducts our oilfield service operations.

We completed our initial public offering on January 19, 2006 and our units representing limited liability company interests (“units”) are listed for quotation on The Nasdaq National Market under the symbol “LINE.”

Unless the context requires otherwise, any reference in this Annual Report on Form 10-K to “Linn Energy,” “we,” “our,” “us,” or the “Company” means Linn Energy, LLC and its consolidated subsidiaries.

Acquisition History

As of December 31, 2005, we had completed nine acquisitions of natural gas properties and related gathering and pipeline assets for an aggregate restated purchase price of $201.5 million, with total proved reserves of 160.1 Bcfe, or a restated acquisition cost of $1.26 per Mcfe.


				Restated
				Purchase
Date	Seller	Wells	Location	Price

				(in millions)
May 2003	Emax Oil Company	34	West Virginia	$	3.2
Aug 2003	Lenape Resources, Inc.	61	New York		2.2
Sep 2003	Cabot Oil & Gas Corporation	50	Pennsylvania		15.8
Oct 2003	Waco Oil & Gas Company	353	West Virginia and Virginia		31.5
May 2004	Mountain V Oil & Gas, Inc.	251	Pennsylvania		12.5
Sep 2004	Pentex Energy, Inc.	447	Pennsylvania		15.1
Apr 2005	Columbia Natural Resources, LLC	38	West Virginia and Virginia		4.4
Aug 2005	GasSearch Corporation	130	West Virginia		5.4
Oct 2005	Exploration Partners, LLC	550	West Virginia and Virginia		111.4

	Total	1,914		$	201.5

Business Strategy

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


	•	Executing low risk, low cost development drilling;

	•	Focusing on acquisitions that increase cash available for distribution;

	•	Creating additional value post-acquisition;

	•	Maximizing the value and stability of our cash flows through operating control; and

	•	Reducing commodity price risk through derivatives.

Drilling

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.

Most of our wells are relatively shallow, ranging from 2,500 to 5,500 feet, and drill through as many as ten potential producing zones. Our average well cost for 2005 was $227,000. Many of our wells are completed to multiple producing zones and production from these zones may be commingled. In general, our producing wells have stable production profiles and long-lived production, often with total projected economic lives in excess of 50 years. 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 30 to 60 days after drilling has commenced. 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.

During the year ended December 31, 2005, we drilled 110 wells, and since inception we have spent $43.3 million to drill and complete 200 wells, all of which are capable of producing natural gas in commercial quantities, with an average finding and development cost of $1.31 per Mcfe, which includes the estimated development costs for proved undeveloped reserves. To carry out our 2006 drilling program, we have contracts in place for four third party drilling rigs. We also are purchasing two drilling rigs, at a cost of approximately $2.2 million per rig, which are anticipated to be delivered in late summer or early fall of 2006. As of December 31, 2005, we had 373 proved undeveloped drilling locations (specific drilling locations as to which our independent reserve engineer, Schlumberger Data and Consulting Services, has assigned proved undeveloped reserves as of such date) and we had identified 532 additional unproved drilling locations (specific drilling locations as to which Schlumberger Data and Consulting Services has not assigned any proved reserves as of such date but 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.

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, wells in the Appalachian Basin 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 per well during 2005 was 10.1 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.

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 of our wells produce natural gas of pipeline quality which does not require further treatment by us before delivery to the receiving pipeline.

Our activities are concentrated in the Appalachian Basin in major geologic formations of the Mississippian/ Devonian Sands and Carbonates in West Virginia and southwestern Pennsylvania, 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, 2005, 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 $0.40 and $0.43 per Mcf, respectively. Most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices.

We enter into derivative transactions in the form of hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use fixed price swaps and puts to hedge NYMEX natural gas prices, which do not include the additional net premium we typically realize in the Appalachian Basin. By removing the price volatility from a significant portion of our natural gas production, we have

mitigated, but not eliminated, the potential effects of fluctuating natural gas prices on our cash flow from operations for those periods.

The following table summarizes, as of May 17, 2006, and for the periods indicated, our derivatives presently in place through December 31, 2009. Currently, we use fixed price swaps and puts to manage commodity prices. These transactions are settled based upon the NYMEX price of natural gas at Henry Hub on the final trading day of the month, and settlement occurs on the 3rd day of the production month.


		Year 2006		Year 2007		Year 2008		Year 2009

Fixed Price Swaps:
	Hedged Volume (MMMBtu)		7,412		7,168		8,464		6,205
	Average Price ($/ MMBtu)	$	9.26	$	8.64	$	8.23	$	7.56
Puts:
	Hedged Volume (MMMBtu)		730		2,336		2,013		—
	Average Price ($/ MMBtu)	$	8.83	$	9.11	$	9.50	$	—
Total:
	Hedged Volume (MMMBtu)		8,142		9,504		10,477		6,205
	Average Price ($/ MMBtu)	$	9.22	$	8.75	$	8.47	$	7.56

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, 2004 and 2005, based on reserve reports prepared by Schlumberger Data and Consulting Services. The Standardized Measure values shown in the table are not intended to represent the market value of our estimated natural gas and oil reserves at such dates.


			As of December 31,

			2003			2004			2005

Reserve Data:
Estimated net proved reserves:
	Natural gas (Bcf)			68.9			118.9			191.9
	Oil (MMBbls)			0.2			0.1			0.2
		Total (Bcfe)		69.8			119.8			193.2
Proved developed (Bcfe)				41.8			74.4			125.2
Proved undeveloped (Bcfe)				28.0			45.4			68.0
Proved developed reserves as % of total proved reserves				59.9	%		62.1	%		64.8	%
Standardized Measure (in millions)(1)			$	126.3		$	215.0		$	552.1
Representative Natural Gas and Oil Prices:
	Natural gas — NYMEX Henry Hub per MMBtu		$	5.97		$	6.18		$	10.08
	Oil — NYMEX WTI per Bbl			32.76			43.36			57.98


(1)	Does not give effect to derivative transactions. For a description of our derivative transactions, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations” in this Annual Report on Form 10-K.

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.

Future prices received for production may vary, perhaps significantly, from the prices assumed for purposes of our estimate of Standardized Measure. The Standardized Measure shown should not be construed as the

market value of the reserves at the dates shown. The 10% discount factor used to calculate Standardized Measure, which is required by Financial Accounting Standards Board (“FASB”) pronouncements, is not necessarily the most appropriate discount rate. The Standardized Measure, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.


	*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)		Year Ended
		through		December 31,
		December 31,
		2003(1)		2004
		(Restated)		(Restated)		2005

Net Production:
	Total production (MMcfe)		492		3,112		4,839
	Average daily production (Mcfe/d)		2,299		8,526		13,258
Average Sales Prices:
	Weighted average realized natural gas price (Mcf)	$	5.26	$	5.73	$	6.92
	Weighted average realized price (Mcfe)		5.25		5.74		6.97
Average Unit Costs per Mcfe:
	Operating expenses	$	1.62	$	1.53	$	1.52
	General and administrative expenses		1.59		0.48		0.69
	Depreciation, depletion and amortization		1.14		1.17		1.51


(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 relating to the productive wells in which we owned a working interest as of December 31, 2005. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries. 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		1,922		1,518
Non-operated		192		56

Total		2,114		1,574


	*Developed and Undeveloped Acreage*

The following table sets forth information as of December 31, 2005 relating to our leasehold acreage.


					Undeveloped
	Developed Acreage				Acreage				Total Acreage

	Gross		Net		Gross		Net		Gross		Net

Operated		92,783		92,578		39,175		37,358		131,958		129,936
Non-operated		96,500		15,750		—		—		96,500		15,750

Total		189,283		108,328		39,175		37,358		228,458		145,686


	*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 years ended December 31, 2004 and 2005. We did not conduct 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 generate a reasonable rate of return.


			Year Ended
			December 31,

			2004		2005

Gross wells:
	Productive			90		110
	Dry			—		—

		Total		90		110

Net Development wells:
	Productive			82		105
	Dry			—		—

		Total		82		105

Net Exploratory wells:
	Productive			—		—
	Dry			—		—

		Total		—		—

Natural Gas Gathering Activities

We own and operate an extensive network of natural gas gathering systems comprised of approximately 800 miles of pipeline and associated compression and metering facilities which connect to numerous sales outlets on eight interstate and eight intrastate pipelines, which allows us to more efficiently transport our gas to market. The interstate market outlets are Dominion Transmission Inc. (West Virginia and Pennsylvania), Columbia Gas Transmission Corp. (West Virginia and Pennsylvania), Cranberry Pipeline (West Virginia), Texas Eastern Pipeline (Pennsylvania), Transco Pipeline (Pennsylvania), Equitrans (West Virginia and Pennsylvania), Equitable Gas Company (West Virginia and Pennsylvania), and Carnegie Gas Company (West Virginia). The intrastate market outlets are Dominion Peoples (Pennsylvania), Dominion Hope (West Virginia), TW Phillips Oil & Gas Company,

Inc. (Pennsylvania), Equitable Gas Company (West Virginia and Pennsylvania), Cabot Oil & Gas Corporation (West Virginia), Allegheny Power (West Virginia), National Fuel Gas Distribution (New York) and Lumberport Shinnston Gas Company (West Virginia).

We gather more than 90% of our current production. 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 ensure all production values are realized.

Natural Gas Gathering for Others

We perform limited natural gas gathering activities for others on non-jurisdictional gathering systems through our subsidiary Linn Operating, Inc. 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. 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. Most of Linn Operating’s natural gas gathering lines are not subject to United States Department of Transportation (“US DOT”) safety regulations.

Purchase for Resale

On November 1, 2004, Penn West purchased the Bessie 8 Pipeline in Indiana County, Pennsylvania and began purchasing and re-selling production from other producers connected to it. Penn West buys this third party production and resells it into a Dominion Peoples transmission line. 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.

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. To carry out our 2006 drilling program, we have contracts in place for four third party drilling rigs. We also are purchasing two drilling rigs, at a cost of approximately $2.2 million per rig, which are anticipated to be delivered in late summer or early fall of 2006. In addition, 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 1/8th (12.5%) of revenue 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 1/6th (16.66%) of revenue 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 1/32nd to 1/16th (3.125% to 6.25%) of revenue, which further reduces the net revenue interest available to us to between 84.375% and 81.25% of revenue.

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 most 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 also the mineral owner, allowing us to deal with a single party. 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, 2005, sales of natural gas to Dominion Resources, Inc., Cabot Oil & Gas Corporation, UGI Energy Services, Inc., Amerada Hess Corporation and Equitable Resources, Inc. accounted for approximately 48%, 14%, 10%, 7% and 6%, respectively, of our total volumes, or 85% in the aggregate. If we were to lose any one of our major 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, it could have a detrimental effect on the natural gas market in general and on the volume of natural gas that we are able to sell.


	*Derivative Activity*

We enter into derivative 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 derivative activities, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” and Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” in this Annual Report on Form 10-K.


	*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 human resources 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 has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our drilling program. To carry out our 2006 drilling program, we have contracts in place for four third party drilling rigs. We also are purchasing two drilling rigs, at a cost of approximately $2.2 million per rig, which are anticipated to be delivered in late summer or early fall of 2006.

Competition is also strong for attractive natural gas and oil 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 any 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, 2005, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2006 or that will otherwise have a material impact on our financial position or results of operations.

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

National Environmental Policy Act. Natural gas and oil production activities on federal lands are subject to the National Environmental Policy Act (“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 development and production activities, as well as proposed 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.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act (“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 (“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 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 recategorize 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 development 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 development 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.

Federal Water Pollution Control Act. 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 in substantial compliance with the requirements of the Clean Water Act.

Clean Air Act. 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, the 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 would 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 development 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 Transportation and Pricing. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale of natural gas are 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 occur 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. 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 natural gas and oil 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 opportunity employment. We do not believe that compliance with these laws will have a material adverse effect upon our results of operations.


	*Employees*

As of May 15, 2006, we had 130 full time employees, including three geologists, six petroleum engineers and eight land professionals. Of our 130 full time employees, 29 work in our Pittsburgh office, three work in our Houston office and 98 work 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.

Available Information

Our internet address is http://www.linnenergy.com. We make available free of charge on or through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). The SEC maintains an internet website that contains these reports at http://www.sec.gov. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

Forward-Looking Statements

This Annual Report on Form 10-K contains forward-looking statements within the meaning of federal securities laws that are subject to a number of risks and uncertainties, many of which are beyond our control. These statements may include statements about our:


	•	business strategy;

	•	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 Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in Item 1, “Business;” Item 1A,“Risk Factors;” Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. 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 Annual Report on Form 10-K 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 beyond our control. In addition, management’s assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking statements or events will occur. Actual results may differ materially from those anticipated or implied in

forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this Annual Report on Form 10-K. The forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.


Item 1A.	Risk Factors

Risks Related to Our Business

We may not have sufficient cash flow from operations to pay the quarterly distribution at the current distribution level and future distributions to our unitholders may fluctuate from quarter to quarter.

We may not have sufficient cash flow from operations each quarter to pay the quarterly distribution at the current distribution level. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our Board of Directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:


	•	the amount of natural gas we produce;

	•	the price at which we are able to sell our natural gas production;

	•	the level of our operating costs;

	•	the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon; and

	•	the level of our capital expenditures.

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


	•	our ability to make working capital borrowings under our credit facility to pay distributions;

	•	the costs of acquisitions, if any;

	•	fluctuations in our working capital needs;

	•	timing and collectibility of receivables;

	•	restrictions on distributions contained in our credit facility;

	•	prevailing economic conditions; and

	•	the amount of cash reserves established by our Board of Directors for the proper conduct of our business.

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

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.

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

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

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

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


	•	the domestic and foreign supply of and demand for natural gas;

	•	the price and level of foreign imports;

	•	the level of consumer product demand;

	•	weather conditions;

	•	overall domestic and global economic conditions;

	•	political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;

	•	the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

	•	the impact of the U.S. dollar exchange rates on natural gas and oil prices;

	•	technological advances affecting energy consumption;

	•	domestic and foreign governmental regulations and taxation;

	•	the impact of energy conservation efforts;

	•	the proximity and capacity of natural gas pipelines and other transportation facilities; and

	•	the price and availability of alternative fuels.

In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue.

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

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

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our December 31, 2005 reserve report, our average decline rate for proved developed producing reserves is 8% during the first five years, 5% in the next five years and less than 4% thereafter. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2005, production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

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

No one can measure underground accumulations of natural gas in an exact way. Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our independent petroleum engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per Mcf, then the Standardized Measure of our proved reserves as of December 31, 2005 would decrease from $552.1 million to $503.8 million. Our Standardized Measure is calculated using unhedged natural gas prices and is determined in accordance with the rules and regulations of the SEC. 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. 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 we are able to sell our natural gas; 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 development operations, 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 limitation 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, 2005, Dominion Resources, Inc., Cabot Oil & Gas Corporation, UGI Energy Services, Inc., Amerada Hess Corporation and Equitable Resources, Inc. accounted for approximately 48%, 14%, 10%, 7% and 6%, respectively, of our total volumes, or 85% in the aggregate. To the extent these and other customers reduce the volumes of natural gas that they purchase from us, our revenues and cash available for distribution could decline.

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

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

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

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


	•	the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

	•	the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

	•	the federal Resource Conservation and Recovery Act, 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, 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 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 Item 1, “Business — Operations — Environmental Matters and Regulation” in this Annual Report on Form 10-K.

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

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


	•	unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

	•	unable to obtain financing for these acquisitions on economically acceptable terms; or

	•	outbid by competitors.

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

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


	•	mistaken assumptions about revenues and costs, including synergies;

	•	an inability to integrate successfully the businesses we acquire;

	•	the assumption of unknown liabilities;

	•	limitations on rights to indemnity from the seller;

	•	the diversion of management’s attention from other business concerns; and

	•	customer or key employee losses at the acquired businesses.

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

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

We incurred restated net losses of $1.7 million in the period from March 14, 2003 (inception) through December 31, 2003 and $4.8 million for the year ended December 31, 2004, respectively. We incurred a net loss of $56.4 million for year ended December 31, 2005. 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 the current distribution level.

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 natural gas to be commercially viable after drilling, operating and other costs. If we drill future wells that we identify as dry holes, our drilling success rate would decline and may materially harm our business.

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

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

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

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2005, we had identified 905 drilling locations, of which 373 were proved undeveloped locations and 532 were other locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. In addition, Schlumberger Data and Consulting Services has not assigned any proved reserves to the 532 other drilling locations we have identified and scheduled for drilling and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

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

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


	•	the high cost, shortages or delivery delays of equipment and services;

	•	unexpected operational events;

	•	adverse weather conditions, particularly seasonal weather conditions in the spring;

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

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

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

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

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

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

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas, we currently and may in the future enter into hedging arrangements for a significant portion of our natural gas production. 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 reduction of our liquidity. Under our credit facility, we are prohibited from hedging all of our production, and we therefore retain the risk of a price decrease on our unhedged volumes.

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

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

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

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could 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 by our initial compliance date of December 31, 2007. We identified a material weakness in our internal controls during the course of evaluating disclosure controls and procedures as of December 31, 2005. See Item 9A, “Controls and Procedures” for additional information. 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 certain reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our units.

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

The natural gas and oil industry is intensely competitive, and we compete with other companies that have greater resources. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce natural gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for natural gas and oil 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 ability to pay distributions to our unitholders. Please read Item 1, “Business — Operations — Environmental Matters and Regulation” and “Business — Operations — Other Regulation of the Natural Gas and Oil Industry” in this Annual Report on Form 10-K for a description of the laws and regulations that affect us.

We face possible delisting from The Nasdaq Stock Market, which could result in a limited trading market for our units, and could negatively affect the price of our units.

On April 18, 2006 and May 24, 2006, we received Nasdaq Staff Determination letters indicating that we had failed to comply with the filing requirements for continued listing set forth in Marketplace Rule 4310(c)(14) because we had not timely filed our Annual Report on Form 10-K and our Quarterly Report on Form 10-Q. As a result, our units are subject to delisting from The Nasdaq Stock Market. We have been granted a hearing before a Nasdaq Listing Qualifications Panel to appeal the Staff’s determination. The request for a hearing will stay the potential delisting until the appeal has been heard and the Panel has rendered a formal decision. There is no assurance that our appeal of the Staff’s determination will be successful. If our appeal is not successful and our units are delisted, the trading in our units could be conducted in the over-the-counter market known as the NASD OTC Electronic Bulletin Board, the trading market for our units could become limited and the price of our units could be negatively affected. As a result, you may find it difficult to dispose of, or to obtain accurate quotations as to the market value of, our units.

We may face risks related to the recent restatement of our financial statements.

We restated our financial statements for the period from March 14, 2003 (inception) through December 31, 2003, for the year ended December 31, 2004 and certain financial statement line items for the nine months ended September 30, 2004 and 2005 primarily to correct certain accounting entries related to the acquisition of natural gas and oil properties. As a result of these changes, which primarily affect fiscal 2003 and 2004, revenues were reduced by $944,164 and $1,729,526, respectively, and net loss was increased by $353,305 and $838,018, respectively. Companies that restate their financial statements sometimes face litigation claims and/or SEC proceedings following such a restatement of financial results. Although we are unaware of any pending or threatened claims or proceedings relating to our restatement, if any claim or proceeding were to be commenced and successfully asserted against us, we could face monetary judgments, penalties or other sanctions which could adversely affect our financial condition and could cause the price of our units to decline.

Risks Related to Our Structure

Our management and Quantum Energy Partners own, in the aggregate, a controlling interest in us, with management and Quantum Energy Partners owning approximately 16.2% and 36.4%, respectively, of our units.

Our management and Quantum Energy Partners own or control an aggregate 52.6% of our outstanding units. Accordingly, management and Quantum Energy Partners, acting together, possess a controlling vote on substantially 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.

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 our non-affiliated unitholders 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.

We may issue additional units without unitholder 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:


	•	an individual unitholder’s 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 reduced; and

	•	the market price of the units may decline.

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

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 SEC;

	•	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 similar 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.

As of May 8, 2006, Quantum Energy Partners controlled an aggregate of 10,144,585 units. In addition, we have agreed, upon demand by Quantum, to register for sale units held by Quantum Energy Partners, certain non-affiliated investors and certain members of 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, the market price of our outstanding units may decline.

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.

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 matters.

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 unitholders would generally be taxed as corporate dividends, and no income, gain, loss, deduction or credit would flow through to unitholders. 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 unitholders may be reduced.

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

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

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 U.S. 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.

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 they do not reside in any of those jurisdictions. Unitholders 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, unitholders may be subject to penalties for failure to comply with those requirements. We currently do business and own assets in West Virginia, Pennsylvania, 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.

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

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

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders and in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, 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.


Item 1B.	Unresolved Staff Comments

Not applicable.


Item 2.	Properties

As of December 31, 2005, our producing wells and drilling locations were located as follows:

All of our proved reserves as of December 31, 2005 were located in the Appalachian Basin. For additional information concerning our proved reserves, production, wells, acreage and related matters, see Item 1,“Business — Natural Gas and Oil Data” in this Annual Report on Form 10-K.

Our obligations under our credit facility are secured by mortgages on our natural gas and oil properties. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities — Credit Facility” in this Annual Report on Form 10-K for additional information concerning our credit facility.


	*Offices*

We currently lease approximately 13,000 square feet of office space in Pittsburgh, Pennsylvania at 650 Washington Road, where our principal offices are located. The lease for our Pittsburgh office expires in September 2012. We also lease an additional 5,000 square feet of office space in Pittsburgh, Pennsylvania, for which the lease expires in March 2009. We lease approximately 3,000 square feet of office space in Houston, Texas. The lease for our Houston office expires in April 2008. We also have field offices in Bridgeport and Glenville, West Virginia and Indiana, Pennsylvania. Additionally, we have purchased property in Jane Lew, West Virginia where we intend to centralize certain of our West Virginia operations in 2006.


Item 3.	Legal Proceedings

Effective September 30, 2003, we purchased interests in natural gas and oil wells from Cabot Oil & Gas Corporation for an aggregate restated purchase price of $15.8 million. On September 27, 2005, Power Gas Marketing & Transmission Inc. filed a complaint styled Power Gas Marketing & Transmission, Inc. v. Cabot Oil & Gas Corporation and Linn Energy in the court of common pleas of Indiana County, Pennsylvania against Cabot and Linn Energy alleging that Cabot conveyed such interests to us in breach of purported preferential purchase rights. Power Gas alleges that Linn Energy interfered with Power Gas’ contract rights and demands the right to evaluate whether to exercise its purported preferential purchase rights. We believe that Power Gas’ allegations are without merit, intend to vigorously defend the matter and do not believe that the outcome of the matter would have a material adverse effect on our financial position and results of operations.

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


Item 4.	Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the fourth quarter of 2005.

PART II


Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our units are listed on The Nasdaq National Market under the symbol “LINE.” Our units began trading on January 13, 2006, in connection with our initial public offering. On May 8, 2006, the market price for our units was $20.00 per unit. On that date, there were 27,832,500 units outstanding and approximately 9,000 unitholders.

The Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (the “LLC Agreement”) provides for the distribution of “available cash” (as defined below) on a quarterly basis to our unitholders. 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 distribution with respect to any one or more of the next four quarters.

The amount of available cash will be determined by our Board of Directors for each calendar quarter of our operations beginning with the quarter ended March 31, 2006.

The terms of our secured revolving credit facility permit us to borrow under the facility to pay distributions to unitholders as long there has not been a default or event of default and if the amount of borrowings under the facility is less than 90% of the borrowing base. As we identified the need to restate our financial statements, we obtained necessary waivers of certain covenants to remain in compliance with the terms of the credit facility. The credit facility contains covenants limiting our ability to make distributions other than from available cash. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Credit Facility” in this Annual Report on Form 10-K for further information regarding our secured revolving credit facility.

Use of Securities Act Registration Statement Proceeds

In the first quarter of 2006, Linn Energy, LLC completed its initial public offering of an aggregate of 12,450,000 units representing limited liability company interests (consisting of 11,750,000 units purchased by the underwriters on January 19, 2006 and 700,000 units purchased by the underwriters on February 15, 2006 pursuant to their option to purchase additional units) at an initial public offering price of $21.00 per unit in a firm commitment underwritten initial public offering pursuant to an S-1 Registration Statement (File No. 333-125501) declared effective by the Securities and Exchange Commission on January 12, 2006. RBC Capital Markets Corporation and Lehman Brothers Inc. acted as joint lead-managing underwriters of the offering.

The aggregate initial public offering price for the units issued in our initial public offering was approximately $261.4 million. Net proceeds to the Company (after underwriting discounts of approximately $18.3 million and estimated offering expenses of approximately $6.7 million) were approximately $236.4 million, of which $122.0 million was used to reduce the Company’s then-existing indebtedness, an aggregate of $111.6 million was used to redeem a portion of the limited liability company membership interests and units held

by certain affiliates, and an aggregate of $2.8 million was used to redeem a portion of the limited liability company interests and units held by certain non-affiliates of the Company. See Item 13,“Certain Relationships and Related Transactions — Stakeholders’ Agreement — Redemption and Exchange” for further information. Estimated offering expenses included one-time bonuses aggregating $2.0 million to certain of our executive officers. See Item 11, “Executive Compensation — Employment Agreements; Change of Control Arrangements” for further information regarding these payments.


Item 6.	Selected Financial Data

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

Set forth below is our selected historical consolidated financial data for the periods indicated for Linn Energy, LLC (Successor). The historical financial data for the periods ended December 31, 2003, 2004 and 2005 and the balance sheet data as of December 31, 2003, 2004 and 2005 have been derived from our audited financial statements.

On October 31, 2003, we completed a $31.5 million (restated) acquisition of natural gas and oil assets from Waco Oil & Gas (Predecessor). The historical financial data for the period from January 1, 2003 through October 31, 2003 and the year ended December 31, 2002 have been derived from the audited financial statements of the Predecessor entity. The historical financial data for the year ended December 31, 2001 and the balance sheet data as of December 31, 2001 and 2002 have been derived from the unaudited financial statements of the Predecessor entity.

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 Annual Report on Form 10-K.

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 other financial data may not be meaningful or indicative of future results.

The following tables include a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with U.S. generally accepted accounting principles, or GAAP. Please see “Non-GAAP Financial Measure” on page 38.


			Predecessor						Successor

									Period from
									March 14,
							Period from		2003
							January 1,		(inception)			Year Ended
							2003		through			December 31,
							through		December 31,
							October 31,		2003			2004
			2001		2002		2003		(Restated)			(Restated)			2005

			(unaudited)
			(In thousands)						(In thousands)
Statement of Operations Data:
Revenues:
	Natural gas and oil sales		$	5,382	$	3,779	$	4,705	$	2,379		$	19,502		$	44,645
	Realized gain (loss) on natural gas derivatives(1)			—		—		—		163			(2,239	)		(51,417	)
	Unrealized (loss) on natural gas derivatives(2)			—		—		—		(1,600	)		(8,765	)		(24,776	)
	Natural gas marketing revenue			—		—		—		—			520			4,722
	Other revenue			1,488		698		788		4			160			345

		Total revenues		6,870		4,477		5,493		946			9,178			(26,481	)


			Predecessor									Successor

												Period from
												March 14,
									Period from			2003
									January 1,			(inception)			Year Ended
									2003			through			December 31,
									through			December 31,
									October 31,			2003			2004
			2001			2002			2003			(Restated)			(Restated)			2005

			(unaudited)
			(In thousands)									(In thousands)
Expenses:
	Operating expenses			1,702			2,426			2,204			798			4,756			7,356
	Natural gas marketing expense			—			—			—			—			482			4,401
	General and administrative expenses			3,186			1,047			870			783			1,488			3,332
	Depreciation, depletion and amortization			1,152			1,494			1,185			562			3,656			7,294

		Total expenses		6,040			4,967			4,259			2,143			10,382			22,383

Other Income and (Expenses):
	Interest income			—			—			—			34			7			47
	Interest and financing expenses(3)			(390	)		(352	)		(237	)		(517	)		(3,530	)		(7,040	)
	Loss on equity investment			(57	)		(145	)		(63	)		(3	)		(56	)		(17	)
	Write-off of deferred financing fees			—			—			—			—			—			(364	)
	Gain (loss) on sale of assets			(111	)		(63	)		49			(5	)		(33	)		(39	)

		Total other income and (expenses)		(558	)		(560	)		(251	)		(491	)		(3,612	)		(7,413	)

	Income (loss) before income taxes			272			(1,050	)		983			(1,688	)		(4,816	)		(56,277	)
	Income tax (provision)(4)			—			—			—			—			—			(74	)
Income (loss) before cumulative effect of change in accounting principle				272			(1,050	)		983			(1,688	)		(4,816	)		(56,351	)
Cumulative effect of change in accounting principle				—			—			(757	)		—			—			—

Net income (loss)			$	272		$	(1,050	)	$	226		$	(1,688	)	$	(4,816	)	$	(56,351	)


(1)	During 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas hedges and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices. The remaining $13.1 million of the $51.4 million realized loss relates to losses on derivative positions settled in 2005 at scheduled maturity dates that were not related to the cancellation of out-of-the-money natural gas hedges.

(2)	The natural gas swaps were not specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to changes in natural gas prices. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these amounts represent non-cash charges.

(3)	Includes the unrealized gain (loss) on interest rate swaps that were not specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to changes in interest rates. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these amounts represent non-cash charges.

(4)	Linn Operating, LLC (predecessor to Linn Operating, Inc.) was not subject to federal income tax before converting to a subchapter C-corporation on June 1, 2005. Prior to the conversion and the formation of Mid Atlantic Well Service, Inc. as a wholly owned subchapter C-corporation on October 12, 2005, there was no tax provision included in our consolidated financial statements because all of our taxable income or loss was included in the income tax returns of the individual members.


	Predecessor									Successor

										Period from			Year Ended
							Period from			March 14, 2003			December 31,
							January 1, 2003			(inception) through
							through			December 31, 2003			2004
	2001			2002			October 31, 2003			(Restated)			(Restated)			2005

	(Unaudited)
	(In thousands)									(In thousands)
Cash Flow Data
Net cash provided by (used in) operating activities	$	1,659		$	(40	)	$	1,826		$	(135	)	$	10,351		$	(29,518	)
Net cash (used in) provided by investing activities		(8,831	)		(1,480	)		10,880			(35,344	)		(61,372	)		(150,898	)
Net cash provided by (used in) financing activities		7,473			1,056			(2,415	)		57,521			31,167			189,269
Capital expenditures	$	8,566		$	1,375		$	1,717			32,863			63,594			150,849
Other Financial Information (unaudited):
Adjusted EBITDA(1)										$	1,014		$	11,298		$	21,706


		Predecessor				Successor

						As of December 31,
		As of December 31,
						2003		2004
		2001		2002		(Restated)		(Restated)		2005

		(Unaudited)
		(In thousands)				(In thousands)
Balance Sheet Data:
Cash and cash equivalents(2)		$	1,006	$	542	$	22,043	$	2,188	$	11,041
Other current assets			447		710		1,971		5,892		23,692
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization			12,831		12,829		52,307		95,381		238,858
Property, plant and equipment, net of accumulated depreciation			2,958		2,778		370		1,387		2,525
Other assets			208		168		2,486		577		3,428

	Total assets	$	17,450	$	17,027	$	79,177	$	105,425	$	279,544

Current liabilities		$	3,498	$	3,468	$	20,200	$	10,216	$	86,058
Long-term debt			2,686		1,919		41,518		72,750		206,814
Other long-term liabilities			—		—		3,123		12,939		33,503
Members’ capital (deficit)			11,266		11,640		14,336		9,520		(46,831	)

	Total liabilities and members’ capital	$	17,450	$	17,027	$	79,177	$	105,425	$	279,544


(1)	See “Non-GAAP Financial Measure” on page 38 of this Annual Report on Form 10-K.

(2)	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 Schlumberger Data and Consulting Services, our independent petroleum engineer, and certain summary unaudited information with respect to our production and sales of natural gas and oil. You should refer to Item 1, “Business — Natural Gas and Oil Data — Proved Reserves and Production and Price History,” Item 1A, “Risk Factors,” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in evaluating the material presented below.


			As of December 31,

			2003			2004			2005

Reserve Data:
Estimated net proved reserves:
	Natural gas (Bcf)			68.9			118.9			191.9
	Oil (MMBbls)			0.2			0.1			0.2
		Total (Bcfe)		69.8			119.8			193.2
Proved developed (Bcfe)				41.8			74.4			125.2
Proved undeveloped (Bcfe)				28.0			45.4			68.0
Proved developed reserves as % of total proved reserves				59.9	%		62.1	%		64.8	%
Standardized Measure (in millions)(1)			$	126.3		$	215.0		$	552.1
Representative Natural Gas and Oil Prices:
	Natural gas — NYMEX Henry Hub per MMBtu		$	5.97		$	6.18		$	10.08
	Oil — NYMEX WTI per Bbl			32.76			43.36			57.98


		Period from
		March 14, 2003
		(inception) through		Year Ended
		December 31,		December 31,

		2003(2)		2004
		(Restated)		(Restated)		2005

Net Production:
	Total production (MMcfe)		492		3,112		4,839
	Average daily production (Mcfe/d)		2,299		8,526		13,258
Average Sales Prices:
	Weighted average realized natural gas price (Mcf)	$	5.26	$	5.73	$	6.92
	Weighted average realized price (Mcfe)		5.25		5.74		6.97
Average Unit Costs per Mcfe:
	Operating expenses	$	1.62	$	1.53	$	1.52
	General and administrative expenses		1.59		0.48		0.69
	Depreciation, depletion and amortization		1.14		1.17		1.51


(1)	Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the 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%. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Linn Energy Holdings, LLC, which is not subject to income taxes. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations” in Item 7 to this Annual Report on Form 10-K.

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

NON-GAAP FINANCIAL MEASURE

Adjusted EBITDA

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


	•	Interest expense;

	•	Depreciation, depletion and amortization;

	•	Write-off of deferred financing fees;

	•	(Gain) loss on sale of assets;

	•	(Gain) loss from equity investment;

	•	Accretion of asset retirement obligation;

	•	Unrealized (gain) loss on natural gas swaps;

	•	Realized (gain) loss on cancelled natural gas swaps; and

	•	Income tax provision.

The costs of cancelling natural gas swaps before their original settlement date are the only adjustments to Adjusted EBITDA that require expenditure of cash. These costs were financed with borrowings under our credit facility, and such long term debt is recognized as an increase in cash flow from financing activities.

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

The following table presents a reconciliation of our consolidated net loss to Adjusted EBITDA:


		Period from
		March 14, 2003
		(inception) through			Year Ended
		December 31,			December 31,

		2003			2004
		(Restated)			(Restated)			2005

		(In thousands)
Net (loss)		$	(1,688	)	$	(4,816	)	$	(56,351	)
Plus:
	Interest expense		517			3,530			7,040
	Depreciation, depletion and amortization		562			3,656			7,294
	Write-off of deferred financing fees		—			—			364
	Loss on sale of assets		5			33			39
	Loss from equity investment		3			56			17
	Accretion of asset retirement obligation		15			74			172
	Unrealized loss on natural gas derivatives		1,600			8,765			24,776
	Realized loss on cancelled natural gas derivatives(1)		—			—			38,281
	Income tax provision(2)		—			—			74

Adjusted EBITDA		$	1,014		$	11,298		$	21,706


(1)	During 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas swaps and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices.


(2)	Linn Operating, LLC was not subject to federal income tax before converting to a subchapter C-corporation on June 1, 2005. Prior to the conversion, there was no tax provision included in our consolidated financial statements because all of our taxable income or loss was included in the income tax returns of the individual members.


Item 7.	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 financial statements and related notes included elsewhere in this Annual Report on Form 10-K. 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 Annual Report on Form 10-K, particularly in “Risk Factors” contained in Item 1A of this Annual Report on Form 10-K. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

Our proved reserves at December 31, 2005 were 193.2 Bcfe, of which approximately 99% were natural gas and 65% were classified as proved developed, with a Standardized Measure of $552.1 million. At December 31, 2005, we operated 1,922, or 91%, of our 2,114 wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 29 years based on our December 31, 2005 reserve report and annualized production for the quarter ended December 31, 2005. As of December 31, 2005, we had identified 905 drilling locations, of which 373 were proved undeveloped locations and 532 were other locations, and we had leasehold interests in approximately 145,686 net acres in the Appalachian Basin. From inception through December 31, 2005, we added 33.1 Bcfe of proved reserves through our drilling activities, at a finding and development cost of $1.31 per Mcfe, which includes the estimated development costs for proved undeveloped reserves.

As of December 31, 2005, we had completed nine acquisitions of natural gas properties and related gathering and pipeline assets for a restated aggregate purchase price of $201.5 million, with total proved reserves of 160.1 Bcfe, or a restated acquisition cost of $1.26 per Mcfe.


				Restated
				Purchase
Date	Seller	Wells	Location	Price

				(in millions)
May 2003	Emax Oil Company	34	West Virginia	$	3.2
Aug 2003	Lenape Resources, Inc.	61	New York		2.2
Sep 2003	Cabot Oil & Gas Corporation	50	Pennsylvania		15.8
Oct 2003	Waco Oil & Gas Company	353	West Virginia and Virginia		31.5
May 2004	Mountain V Oil & Gas, Inc.	251	Pennsylvania		12.5
Sep 2004	Pentex Energy, Inc.	447	Pennsylvania		15.1
Apr 2005	Columbia Natural Resources, LLC	38	West Virginia and Virginia		4.4
Aug 2005	GasSearch Corporation	130	West Virginia		5.4
Oct 2005	Exploration Partners, LLC	550	West Virginia and Virginia		111.4

	Total	1,914		$	201.5

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.

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, 2005, we had 193.2 Bcfe of estimated net proved reserves with a Standardized Measure of $552.1 million, a 61% increase in reserves over December 31, 2004, when we had 119.8 Bcfe of estimated net proved reserves with a Standardized Measure of $215.0 million. Our December 31, 2005 and 2004 Standardized Measures were determined using a price of $10.08 and $6.18 per Mcf of natural gas, respectively, and $57.98 and $43.36 per Bbl of oil, respectively. Oil accounts for less than 3% of our production.

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

We utilize the successful efforts method of accounting for our natural gas and oil properties. Leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Generally, if a well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense.

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

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

Our Operations

Our revenues are highly sensitive to changes in natural gas prices and levels of production. As set forth in “— Cash Flow from Operations” below, we have hedged a significant portion of our expected production, which allows us to mitigate, but not eliminate, natural gas price risk. Our expected increase in levels of production as a result of the anticipated drilling of 139 wells during 2006 is dependent on our ability to quickly and efficiently bring the newly drilled wells online. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of increase in our production, which may have an adverse effect on our revenues and as a result, cash available for distribution. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in natural gas prices will affect the ability to drill additional wells and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in natural gas prices may have on the value of our proved reserves and their impact, if any, on any redetermination of the borrowing base under our credit facility.

Production and Operating Costs Reporting

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

Land and Lease Tracking System

As a significant amount of our growth is dependent on drilling new wells, we continuously monitor our lease agreements and our drilling locations to avoid delays. Our monitoring system matches our lease agreements to existing wells and sites for future development allowing management to make real time decisions on which 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			Year Ended
			December 31,			December 31,

			2003			2004
			(Restated)			(Restated)			2005

			(In thousands, except production
			and price data)
Revenues:
	Natural gas and oil sales		$	2,379		$	19,502		$	44,645
	Realized gain (loss) on natural gas derivatives			163			(2,239	)		(51,417	)
	Unrealized (loss) on natural gas derivatives			(1,600	)		(8,765	)		(24,776	)
	Natural gas marketing revenues			—			520			4,722
	Other revenues			4			160			345

		Total revenue		946			9,178			(26,481	)
Expenses:
	Operating expenses		$	798		$	4,756		$	7,356
	Natural gas marketing expense			—			482			4,401
	General and administrative expenses			783			1,488			3,332
	Depreciation, depletion and amortization			562			3,656			7,294

		Total expenses		2,143			10,382			22,383
Other Income and (Expenses):
	Interest and financing expenses		$	(517	)	$	(3,530	)	$	(7,040	)

Net Production:
	Total production (MMcfe)			492			3,112			4,839
	Average daily production (Mcfe/d)			2,299			8,526			13,258
Average Sales Prices:
	Weighted average realized natural gas price (Mcf)		$	5.26		$	5.73		$	6.92
	Weighted average realized price (Mcfe)			5.25			5.74			6.97
Average Unit Costs per Mcfe:
	Operating expenses		$	1.62		$	1.53		$	1.52
	General and administrative expenses			1.59			0.48			0.69
	Depreciation, depletion and amortization			1.14			1.17			1.51

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004


	*Revenue*

Natural gas and oil sales, before realized and unrealized gains and losses on natural gas derivatives, increased to approximately $44.6 million from a restated $19.5 million during the year ended December 31, 2005 as compared to the year ended December 31, 2004. The key revenue measurements were as follows:


		Year Ended
		December 31,				Percentage
						Increase
		2004				(Decrease)
		(Restated)		2005		(Restated)

Net Production:
	Total production (MMcfe)		3,112		4,839		55%
	Average daily production (Mcfe/d)		8,526		13,258		56%
Average Sales Prices:
	Weighted average realized natural gas price (Mcf)	$	5.73	$	6.92		21%
	Weighted average realized price (Mcfe)		5.74		6.97		21%

The increase in revenue from natural gas and oil sales was attributable primarily to the increase in production to 4,839 MMcfe during the year ended December 31, 2005 from a restated 3,112 MMcfe during the year ended December 31, 2004, due to the two acquisitions completed in 2004 and three acquisitions completed in 2005, as well as the drilling of 110 wells during 2005 compared to 90 wells in 2004. In addition to the increase in production, the average natural gas sales price increased during the year ended December 31, 2005 as compared to the year ended December 31, 2004.


	*Derivative Activities*

During the year ended December 31, 2005, we hedged approximately 84% of our natural gas production, which resulted in revenues that were $13.1 million less than we would have achieved at unhedged prices. During the year ended December 31, 2004, we hedged approximately 72% of our natural gas production, which resulted in revenues that were $2.2 million less than we would have achieved at unhedged prices. During the year ended December 31, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas derivatives and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices. Unrealized losses on derivatives were also recorded in the amounts of $24.8 million and $8.8 million in 2005 and 2004, respectively.


	*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 $7.4 million for the year ended December 31, 2005 from a restated $4.8 million for the year ended December 31, 2004, due to the increase in the number of wells as a result of the two acquisitions completed in 2004 and the three acquisitions completed in 2005, as well as the drilling of 90 and 110 wells during 2004 and 2005, respectively. Operating expenses per Mcfe of production were as follows:

Year Ended

December 31,

Percentage

Increase

2004

(Decrease)

(Restated)

2005

(Restated)

Operating expenses per Mcfe

1.53

1.52

General and administrative expenses include the costs of our employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. We monitor general and administrative expenses in relation to the amount of production and the number of wells operated.

General and administrative expenses increased to $3.3 million during the year ended December 31, 2005 as compared to a restated $1.5 million for the year ended December 31, 2004. During 2004 and 2005, the Company capitalized approximately $0.2 million and $1.6 million, respectively, of internal costs related to drilling. Additionally, general and administrative expenses are presented net of approximately $0.6 million (restated) and $1.2 million in 2004 and 2005, respectively, which represents operating expense reimbursements from other working interest owners. The increase in general and administrative expenses was due to our rapidly growing operations and increasing our staffing level to manage the additional wells acquired and drilled in 2004 and 2005. We are continuing to increase staffing levels to manage our active drilling program and to perform the functions associated with being a public company. General and administrative expenses per Mcfe of production were as follows:

Year Ended

December 31,

Percentage

Increase

2004

(Decrease)

(Restated)

2005

(Restated)

General and administrative expenses per Mcfe

0.48

0.69

Depreciation, depletion and amortization increased to $7.3 million for the year ended December 31, 2005 from $3.7 million (restated) for the year ended December 31, 2004 due to the increase in the number of wells as a result of the two acquisitions completed in 2004 and the three acquisitions completed in 2005, as well as the drilling of 90 and 110 wells during 2004 and 2005, respectively.

Interest and financing expenses were $7.0 million for the year ended December 31, 2005 compared to $3.5 million for the year ended December 31, 2004. Our interest rate swaps 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 $1.3 million loss in our current earnings for the years ended December 31, 2005 and December 31, 2004, respectively. Further, these amounts represent non-cash charges. Cash payments for interest expense increased to $6.5 million for the year ended December 31, 2005 from $2.0 million for the year ended December 31, 2004, primarily due to increased debt levels associated with the two acquisitions made in 2004 and the three acquisitions made in 2005.

Income tax expense was $74,464 for the year ended December 31, 2005 compared to $0 in 2004. Because we were structured as a limited liability company through 2004, no tax provision was recorded as all taxable income or loss was included in the income tax returns of the individual members. On June 1, 2005, Linn Operating, LLC (predecessor to Linn Operating, Inc.) converted to subchapter C-corporation status and on November 1, 2005 Mid Atlantic Well Service, Inc., one of our subsidiaries, commenced operations. Income tax expense for 2005 relates to the income attributable to those entities in that period.

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


	*Revenue*

Natural gas and oil sales, before realized and unrealized gains and losses on natural gas derivatives, increased to a restated $19.5 million from a restated $2.4 million for the year ended December 31, 2004 as compared to the period from March 14, 2003 (inception) through December 31, 2003. 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. The key revenue measurements were as follows:


		Period from
		March 14, 2003
		(inception) through		Year Ended		Percentage
		December 31,		December 31,		Increase
		2003		2004		(Decrease)
		(Restated)		(Restated)		(Restated)

Net Production:
	Total production (MMcfe)		492		3,112		533	%
	Average daily production (Mcfe/d)		2,299		8,526		271	%
Average Sales Prices:
	Weighted average realized natural gas price (Mcf)	$	5.26	$	5.73		9	%
	Weighted average realized price (Mcfe)		5.25		5.74		9	%


	*Hedging Activities*

We hedged approximately 72% of our 2004 natural gas production, which resulted in revenues that were $2.2 million less than we would have achieved at unhedged prices. We hedged approximately 43% of our 2003 natural gas production, which resulted in revenues that were $0.2 million higher than we would have achieved at unhedged prices. The loss in 2004 was due to the increase in natural gas prices from 2003 to 2004.


	*Expenses*

Operating expenses increased to a restated $4.8 million for the year ended December 31, 2004 from a restated $0.8 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. Operating expenses per Mcfe of production were as follows:

Period from

March 14, 2003

(inception) through

Year Ended

Percentage

December 31,

Increase

2003

2004

(Decrease)

(Restated)

Operating expenses per Mcfe

1.62

1.53

General and administrative expenses increased to a restated $1.5 million from a restated $0.8 million during the year ended December 31, 2004 as compared to the period from March 14, 2003 (inception) through December 31, 2003. 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. General and administrative expenses per Mcfe of production were as follows:

Period from

March 14, 2003

(inception) through

Year Ended

Percentage

December 31,

Increase

2003

2004

(Decrease)

(Restated)

General and administrative expenses per Mcfe

1.59

0.48

(70

Depreciation, depletion and amortization increased to a restated $3.7 million for the year ended December 31, 2004 from a restated $0.6 million for the period from March 14, 2003 (inception) through December 31, 2003, due to the increase in the number of wells as a result of the two acquisitions completed in 2004, the full year impact in 2004 of the wells acquired in 2003, as well as the drilling of 90 wells during 2004.

Interest and financing expenses were $3.5 million for the year ended December 31, 2004 as compared to $0.5 million for the period from March 14, 2003 (inception) through December 31, 2003. Our interest rate swaps were not specifically designated as hedges under SFAS No. 133, even though they reduced our exposure to changes in interest rates. Therefore, the mark to market of these instruments was recorded as a $1.3 million loss and a $0.2 million loss in our current earnings for the year ended December 31, 2004 and for the period from March 14, 2003 (inception) through December 31, 2003, respectively. Further, these amounts represent non-cash charges. Cash payments for interest expense increased to $2.0 million for the year ended December 31, 2004 from $0.1 million 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

During the period from our formation in March 2003 through 2005, we utilized private equity, proceeds from bank borrowings and cash flow from operations for our capital resources and liquidity. In the first quarter of 2006, we completed our initial public offering of 12,450,000 units which provided proceeds after underwriting discounts of $243.1 million. We used $122.0 million of such amount to reduce indebtedness, $114.4 million to redeem a portion of the membership interests and units held by certain of our affiliated and non-affiliated holders and approximately $6.7 million to pay offering expenses. 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 the 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 year ended December 31, 2005, we cancelled (before their original settlement date) a portion of out-of-the-money natural gas derivatives and realized a loss of $38.3 million. As a result, working capital and members’ capital were reduced by $38.3 million and were $(51.3) million and $(46.8) million, respectively, at December 31, 2005. We subsequently hedged similar volumes at higher prices, which will result in higher cash flow from operations for future periods. At December 31, 2005, our working capital deficit was $(51.3) million, partially due to unrealized losses on natural gas derivatives of $9.2 million, which will not require expenditures of additional cash at maturity as they will be settled with proceeds from the sale of physical natural gas production in the future. Our working capital deficit amount at December 31, 2005 also included $60.0 million of

indebtedness under our subordinated term loan as described under the heading “— Subordinated Term Loan” below. In January 2006, we used $60.0 million of the net proceeds raised in our initial public offering to repay, in full, all indebtedness under the subordinated term loan, and the subordinated term loan was extinguished at that time.

Cash Flow from Operations

Net cash (used in) provided by operating activities was $(29.5) million and a restated $10.4 million for the years ended December 31, 2005 and 2004, respectively. The decrease in net cash provided by operating activities was due substantially to the realized hedging loss during the year. During the year, we cancelled (before their original settlement date) a portion of out-of-the-money hedges and realized a loss of $38.3 million. We subsequently hedged similar volumes at higher prices. Changes in assets and liabilities (reduced) increased cash flow from operations by $(5.3) million and $1.2 million as restated for the years ended December 31, 2005 and 2004, respectively.

Net cash provided by (used in) operating activities as restated was $10.4 million during the year ended December 31, 2004, compared to $(0.1) 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 as restated by $1.2 million in 2004 and reduced cash flow from operations by $(0.8) million in 2003.

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

We enter into derivative arrangements to reduce the impact of natural gas price volatility on our operations. Currently, we use fixed price swaps and puts to reduce our exposure to the volatility in NYMEX natural gas prices, which do not include the additional net premium we typically realize in the Appalachian Basin.

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


		Year 2006		Year 2007		Year 2008		Year 2009

Fixed Price Swaps:
	Hedged Volume (MMMBtu)		7,412		7,168		8,464		6,205
	Average Price ($/ MMBtu)	$	9.26	$	8.64	$	8.23	$	7.56
Puts:
	Hedged Volume (MMMBtu)		730		2,336		2,013		—
	Average Price ($/ MMBtu)	$	8.83	$	9.11	$	9.50	$	—
Total:
	Hedged Volume (MMMBtu)		8,142		9,504		10,477		6,205
	Average Price ($/ MMBtu)	$	9.22	$	8.75	$	8.47	$	7.56

Investing Activities — Acquisitions and Capital Expenditures

Our capital expenditures were $150.8 million and a restated $63.6 million for the years ended December 31, 2005 and 2004, respectively. The total for the year ended December 31, 2005 included $26.6 million for drilling and development of natural gas properties, $111.4 million for the acquisition of Exploration Partners, $4.4 million for the acquisition of CNR, $5.4 million for the acquisition of wells from GasSearch, $1.4 million for the acquisition of additional working interests in our current wells and $1.6 million for furniture, fixtures and equipment. The total for the year ended December 31, 2004 included $16.5 million for drilling and development of natural gas properties, $27.6 million (restated) for acquisitions and $1.5 million for furniture, fixtures and equipment.

We currently anticipate that our drilling budget, which predominantly consists of drilling, infrastructure projects and equipment, will be between $33 million and $34 million for 2006. As of December 31, 2005 and May 12, 2006, we had $17.4 million and $61.4 million, respectively available for borrowing under our credit facility. The amount and timing of our capital expenditures is largely discretionary and within our control. If natural gas prices decline below acceptable levels, we could choose to defer a portion of our planned capital expenditures until later periods. We routinely monitor and adjust our capital expenditures in response to changes in natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and crews. Based upon current natural gas price expectations for 2006, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2006. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Sales and Issuances of Securities. During 2003, we raised $16.0 million, net of costs, from the sale of membership interests to certain members of management and private equity investors, including Quantum Energy Partners. In the first quarter of 2006, we completed our initial public offering of an aggregate 12,450,000 units at an initial public offering price of $21.00 per unit, resulting in net proceeds after underwriting discounts and offering expenses of $236.4 million. See Item 5, “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities — Use of Securities Act Registration Statement Proceeds” for additional information.

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

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

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

On April 11, 2005, we entered into a $200.0 million secured revolving credit facility with BNP Paribas, as administrative agent, Royal Bank of Canada, as syndication agent, and other lenders, which replaced our prior

credit agreement. In connection with the Exploration Partners acquisition in October 2005, the aggregate commitments available under the credit facility were increased to $300.0 million. The amount available for borrowing at any one time is limited to the borrowing base, which as of December 31, 2005 was set at $225.0 million.

As of December 31, 2005, we had aggregate borrowings of $267.0 million outstanding under our credit facility and subordinated term loan. 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;

	•	fund the $4.4 million purchase price of assets from Columbia Natural Resources, LLC;

	•	fund the $5.4 million purchase price of assets from GasSearch Corporation;

	•	pay $38.3 million in connection with the cancelled (before their original settlement date) portion of out-of-the-money natural gas derivatives; and

	•	fund the $111.4 million purchase price of assets from Exploration Partners, LLC.

As described above, we used $122.0 million of the proceeds from our initial public offering to reduce by $62.0 million the indebtedness outstanding under the credit facility and to repay, in full, our $60.0 million subordinated term loan.

On April 7, 2006 we entered into a new $400.0 million Amended and Restated Credit Agreement (the “Credit Agreement”) with BNP Paribas, as administrative agent, Royal Bank of Canada and Societe Generale, as syndication agents, Bank of America, N.A. and Comerica Bank, as documentation agents, and Bank of Scotland, Fortis Capital Corp. and Lehman Commercial Paper Inc., which replaced our prior credit agreement. The Credit Agreement matures on April 13, 2009. The amount available for borrowing at any one time is limited to the borrowing base, which as of the effective date was initially set at $235.0 million. The borrowing base will be redetermined semi-annually by the lenders in their sole discretion, based on, among other things, reserve reports as prepared by reserve engineers taking into account the natural gas and oil prices at such time. Our obligations under the Credit Agreement 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 Credit Agreement are guaranteed by all of our operating subsidiaries and may be guaranteed by any future subsidiaries.

Borrowings under the Credit Agreement are available for acquisition and development 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 (“LIBOR”) plus an applicable margin between 1.00% and 1.75% per annum; or

	•	a domestic bank rate plus an applicable margin between 0% and 0.25% per annum.

Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans. The Credit Agreement 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 Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios 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 obligations under SFAS No. 133, which includes the current portion of natural gas and interest rate swaps.

We have the ability to borrow under the Credit Agreement 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 Agreement is less than 90% of the borrowing base. The Credit Agreement does not require the Company to provide audited consolidated financial statements for the year ended December 31, 2005 until May 30, 2006.

If an event of default exists under the 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:


	•	default by us on the payment of any other indebtedness in excess of $1.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;

	•	bankruptcy or insolvency events involving us or our subsidiaries;

	•	the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;

	•	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;

	•	a change of control, which includes (1) a decrease to 25% or less of our management’s and Quantum Energy Partners’ aggregate ownership in us combined with the acquisition by a third party of more than 35% of our units, or (2) the replacement of a majority of our directors by persons not approved by our Board of Directors; and

	•	certain other customary events of default.

As of May 12, 2006 we had outstanding indebtedness of $173.6 million under the credit facility and additional borrowing ability of $61.4 million.

As we identified the need to restate our financial statements, we obtained necessary waivers of certain covenants to remain in compliance with the terms of the credit facility.

Subordinated Term Loan. On October 27, 2005, we entered into a facility for a $60.0 million second lien senior subordinated term loan (the “subordinated term loan”) with Royal Bank of Canada, as administrative agent, Societe Generale, as syndication agent, and other lenders. The proceeds of the subordinated term loan were used to fund a portion of the purchase price for the acquisition of natural gas and oil properties from Exploration Partners. Covenants on the subordinated term loan are the same as on the credit facility.

As described above, we used $60.0 million of the proceeds from our initial public offering in the first quarter of 2006 to repay in full all amounts owing on the subordinated term loan, and the subordinated term loan was extinguished at that time.

Contractual Obligations. A summary of our contractual obligations as of December 31, 2005 is provided in the following table.


			Payments Due By Year(1)(2)

													After
			2006(3)		2007		2008		2009		2010		2010		Total

			($ in thousands)
Subordinated Term Loan(3)			$	60,000	$	—	$	—	$	—	$	—	$	—	$	60,000
Long-Term Debt Obligations:
		Long-term notes payable		113		121		125		81		47		321		808
		Credit facility(3)		—		—		—		207,000		—		—		207,000
Operating Lease Obligations:
		Office and office equipment leases		447		429		399		343		298		1,496		3,412
Other Long-Term Liabilities:
		Asset retirement obligation		—		—		—		—		—		5,443		5,443

	Total		$	60,560	$	550	$	524	$	207,424	$	345	$	7,260	$	276,663


(1)	This table does not include any liability associated with derivatives.

(2)	This table does not include interest as interest rates are variable and principal balances fluctuate significantly from period to period. Based on the December 31, 2005 subordinated term loan balance of $60.0 million and an interest rate of 8.169%, the annual interest expense would be approximately $4.9 million. Based on the December 31, 2005 credit facility balance of $207.0 million and a weighted average interest rate of 6.11%, the annual interest expense would be approximately $12.6 million.

(3)	With the proceeds from our initial public offering in 2006, we reduced then-existing indebtedness by $122.0 million including the repayment, in full, of the indebtedness under our subordinated term loan.


	*Off-Balance Sheet Arrangements*

As of December 31, 2005, there were no off-balance sheet arrangements that have or are reasonably likely to have a material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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 U.S. generally accepted accounting principles. 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 the preparation of our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in the 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 acquisition costs using all proved reserves. 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 15 of the Notes to the Consolidated Financial Statements, proved reserves are estimated by an independent petroleum engineer, Schlumberger Data and Consulting Services, and are subject to future revisions based on availability of additional information. As described in Note 11 of the Notes to the Consolidated Financial Statements, we follow SFAS No. 143 — Accounting for Asset Retirement Obligations. Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service and are amortized over proved developed 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 charged or 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. No impairments were recorded in 2003, 2004 or 2005.

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

Natural Gas and Oil Reserve Quantities

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

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

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

Revenue Recognition

Sales of natural gas and oil are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. We sell natural gas on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas contracts are customary in the industry.

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

Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at December 31, 2004 or 2005.

Natural gas marketing is recorded on the gross accounting method. Penn West, 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. Penn West 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 Penn West takes title to the natural gas it purchases from the various producers and bears the risks and enjoys the benefits of that ownership. Penn West had natural gas marketing revenues of $520,340 and $4,722,587 and natural gas marketing expenses of $481,993 and $4,400,845 in 2004 and 2005, respectively.

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

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

Derivative Instruments

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 consist of fixed price swaps and puts. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate our interest rate exposure. We account for these activities pursuant to SFAS No. 133 — Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

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

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

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

Acquisitions

The establishment of our asset base through December 31, 2005 has included nine acquisitions of natural gas and oil properties. These acquisitions have been accounted for using the purchase method of accounting.

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

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

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

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

Stock Based Compensation

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

SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. We recorded no stock based compensation expense for the period March 14, 2003 (inception) to December 31, 2003 or for the years ended December 31, 2004 and 2005 as there were no share-based payments made during the respective periods.

Pursuant to the terms of executive employment agreements, in January 2006 we issued 228,909 restricted units vesting in equal installments over two years from our initial public offering date, a unit grant of 114,455 immediately vested units, and aggregate options to purchase 222,500 units, at our initial public offering price, vesting in equal annual installments over three years from our initial public offering date. We will also issue 625,781 unrestricted units if our President and Chief Executive Officer remains employed with us one year from our initial public offering date. Additionally, during the first quarter of 2006, we issued options to purchase, at the fair market value of our units on the grant date, an aggregate 30,000 units to our independent directors pursuant to their compensation arrangements which vested immediately and aggregate options to purchase 203,585 units to certain officers and employees which vest in equal annual installments over three years from the grant date. We estimate that the issuance of these share-based payments will result in approximately $21 million of expense over the three-year period subsequent to the completion of our initial public offering, approximately $17 million of which will be recognized in 2006, which will be accounted for as prescribed by SFAS No. 123(R) — Share-Based Payment.

Newly Adopted Accounting Pronouncements

On March 30, 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“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 was effective for us at the end of the fiscal year ended December 31, 2005. The application of FIN No. 47 did not have a significant impact on our 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, 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 to which they related.

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 was adopted in the third quarter of 2005. The application of FSP No. 19-1 did not have a significant impact on our financial position or results of operations.

In May 2005, the FASB issued SFAS No. 154 — Accounting Changes and Error Corrections, which replaces APB Opinion No. 20 — Accounting Changes, and SFAS No. 3 — Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 changes the requirements for the accounting and reporting of a change in accounting principle. APB Opinion No. 20 previously required that most voluntary changes in an accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. SFAS No. 154 now requires retrospective application of changes in an accounting principle to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. We do not expect the adoption of SFAS No. 154 to have a material impact on our consolidated financial statements.


Item 7A.	Quantitative and Qualitative Disclosures 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 derivative arrangements with respect to a portion of our projected natural gas production through various transactions that reduce our exposure to the volatility 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. At the settlement date, we receive the excess, if any, of the fixed floor over the floating rate. Additionally, we have put options for which we pay the counterparty the fair value at the purchase date. These derivative transactions 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 natural gas prices as of December 31, 2005, the fair value of our derivatives that settle during 2006 was an asset of $1.6 million and a liability of $10.8 million for a net liability of $9.2 million, which we owe to the counterparty. A 10% increase in the index natural gas price above the December 31, 2005 price for 2006 would increase the liability by approximately $7.1 million; conversely, a 10% decrease in the index natural gas price would decrease the liability by approximately $7.1 million.

Our derivatives for 2006 through 2009 are summarized in the table presented above under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations” in this Annual Report on Form 10-K.

Interest Rate Risks

At December 31, 2005, we had debt outstanding of $267.0 million, which incurred interest at floating rates in accordance with our revolving credit facility and subordinated term loan. As of December 31, 2005, the one-month LIBOR was approximately 4.4%. A 1% increase in LIBOR as of December 31, 2005 would result in an estimated $2.7 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 $30.0 million each. One of the interest rate swap agreements settled quarterly in 2005 and the second settles quarterly in 2006, and we are required to pay a rate of 3.2% and 4.3%, respectively, while receiving a floating rate. In 2004, we entered into two additional interest rate swap agreements with a notional amount of $50.0 million each. These interest rate swap agreements settle quarterly in 2007 and 2008, and we are required to pay a rate of 5.2% and 5.7%, respectively, while receiving a floating rate. In 2005, in connection with our new credit facility, we transferred these four interest rate swap agreements to a different third party financial institution. As a consequence of the transfer of these four agreements, the fixed interest rate we pay on each agreement increased by seven basis points.

Also in 2004, we entered into two additional interest rate swap agreements with a notional amount of $20.0 million each. One of the agreements settled quarterly in 2005 and the second settles quarterly in 2006. We are required to pay a rate of 3.1% and 4.4%, respectively, while receiving a floating rate. As of December 31, 2005, the fair value of the interest rate swaps that settle in 2006 was an asset of $0.2 million.

A 1% change in LIBOR as of December 31, 2005 would result in an estimated $1.5 million change in 2006 interest expense associated with our interest swap agreements.

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

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


Item 8.	Financial Statements and Supplementary Data

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-1 through F-31 of this Annual Report on Form 10-K and are incorporated herein by reference.


Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Effective February 25, 2005, KPMG, LLP, a PCAOB registered accounting firm, was engaged as our principal accountant in connection with our initial public offering. Toothman Rice, PLLC, our prior independent accountant, is not a PCAOB registered firm. There were no disagreements on accounting and financial disclosure matters with Toothman Rice PLLC.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures. We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 (e) and 15d-15(e) as of the end of the period covered by this Annual Report on Form 10-K. Based upon this evaluation and the material weakness described below, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures were not effective as of December 31, 2005.

Material weakness in internal control. The Company identified material weaknesses related to polices and procedures to ensure accurate and reliable interim and annual consolidated financial statements. Specifically, the Company lacked (i) personnel with sufficient technical accounting and financial reporting expertise, (ii) adequate review controls over account reconciliations and account analyses, (iii) policies and procedures in place to determine and document the appropriate application of accounting principles and (iv) policies and procedures requiring a detailed and comprehensive review of the underlying information supporting the amounts included in the annual and interim consolidated financial statements and disclosures. These deficiencies resulted in material errors in the accounting for oil and gas acquisitions and capitalization of certain drilling and lease acquisition costs and operating receivables as of and for the period ended December 31, 2003 and the year ended December 31, 2004, and for the nine months ended September 30, 2004 and 2005, for which the Company

restated its consolidated financial statements. In addition, these deficiencies resulted in errors in depreciation, depletion and amortization, lease operating and general and administrative costs, and operating receivables as of and for the year ended December 31, 2005, which were corrected prior to the issuance of the 2005 consolidated financial statements.

In preparing this Annual Report on Form 10-K, we addressed the material weakness in our internal control over financial reporting by significantly expanding our closing process to include additional analyses and other post-closing procedures to provide reasonable assurance that the consolidated financial statements included in this report fairly present in all material respects our consolidated financial position, results of operations and cash flows for the periods presented.

Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting (as defined in Rule 13(a) — 15(f) under the Exchange Act) that occurred during the last quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Remediation activities. During 2006, management identified the material weakness in our internal control over financial reporting and management has taken and is taking the following steps to strengthen our internal control over financial reporting:


	1. We engaged outside consultants with extensive natural gas and oil financial reporting experience to augment our current accounting resources to assist with this Annual Report on Form 10-K and future filings.

	2. We performed additional analysis and other post closing procedures to enable the preparation of accurate consolidated financial statements, including all required disclosures.

	3. We have developed and implemented a process for determining the effective accounting date for an oil and gas property acquisition and formalized procedures necessary to appropriately account for future acquisitions.

While we have taken certain actions to address the material weakness identified, additional measures will be necessary and these measures, along with other measures we expect to take to improve our internal control over financial reporting, may not be sufficient to address the material weakness identified to provide reasonable assurance that our internal control over financial reporting is effective.

Beginning with the fiscal year ending December 31, 2007, Section 404 of the Sarbanes-Oxley Act of 2002 will require us to include an internal control report of management with our Annual Report on Form 10-K. The internal control report must contain (1) a statement of management’s responsibility for establishing and maintaining adequate internal control over financial reporting, (2) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our internal control over financial reporting, (3) management’s assessment of the effectiveness of our internal control over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not our internal control over financial reporting is effective, and (4) a statement that our registered independent public accountants have issued an attestation report on management’s assessment of our internal control over financial reporting.

In order to achieve compliance with Section 404 within the prescribed period, management has begun to assess the adequacy of our internal control over financial reporting, remediate any control weaknesses that may be identified, validate through testing that controls are functioning as designed and implement a continuous reporting and improvement process for internal control over financial reporting. In connection with these efforts, during the fiscal year ended December 31, 2005 we began the process of implementing measures related to the documentation of controls and procedures; segregation of duties, timely reconciliations, and the level of experience in public company accounting among our financial and accounting staff.

We expect to continue to make changes in our internal control over financial reporting during the periods prior to December 31, 2007 in connection with our Section 404 compliance efforts.

Limitations of the effectiveness of internal control. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the internal control system

are met. Because of the inherent limitations of any internal control system, no evaluation of controls can provide absolute assurance that all control issues, if any, within a company have been detected.

Item 9B. Other Information

None.

PART III


Item 10.	Directors and Executive Officers of the Registrant

The following table shows information, as of May 1, 2006, for members of our Board of Directors and our executive officers. Members of our Board of Directors are elected for one-year terms.


Name	Age		Position with Our Company

Michael C. Linn		54	President and Chief Executive Officer
Kolja Rockov		35	Executive Vice President and Chief Financial Officer
Thomas A. Lopus		47	Senior Vice President — Operations
Roland “Chip” P. Keddie		53	Senior Vice President — Secretary
David J. Grecco		39	Vice President and General Counsel
Donald T. Robinson		31	Chief Accounting Officer
Toby R. Neugebauer		35	Chairman
George A. Alcorn		73	Independent Director
Terrence S. Jacobs		62	Independent Director
Jeffrey C. Swoveland		50	Independent Director

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

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

Thomas A. Lopus is the Senior Vice President — Operations. Mr. Lopus joined Linn Operating in April 2006, to oversee all of the Company’s drilling and production, engineering, land and geology operations. From March 2005 to March 2006, Mr. Lopus served as President of PNG Inc., a petroleum engineering consulting business. From February 2002 until March 2005, Mr. Lopus was Senior Vice President — Operations of Equitable Resources, Inc. From February 2000 until February 2002, Mr. Lopus was Vice President of WELLOGIX, an energy software firm based in Houston. From September 1980 until February 2000, Mr. Lopus was employed in various engineering, supervisory and management roles including U.S. Operations Manager for TotalFINA and its predecessor entities. Mr. Lopus is a registered petroleum engineer and currently serves on the Penn State University Industry Advisory Board for Petroleum and Natural Gas Engineering. In addition, he has held a variety of elected and appointed positions with the Society of Petroleum Engineers, Independent Petroleum Association of America and the American Petroleum Institute.

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

David J. Grecco is the Vice President and General Counsel of our company and has served in such capacity since February 2006. Mr. Grecco joined our company as General Counsel in December 2005. From September 1997 until October 2005, Mr. Grecco was employed as an attorney with the law firm Kirkpatrick & Lockhart Nicholson Graham LLP. Prior to that, Mr. Grecco was employed by Rockwell International Corporation from March 1993 through June 1996 most recently serving as Manager, Special Tax Projects, and also practiced as a Certified Public Accountant at Price Waterhouse LLP (PricewaterhouseCoopers) from September 1988 through March 1993.

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

Toby R. Neugebauer is the Chairman of our Board of Directors. Mr. Neugebauer has served as a director of our company since March 2003 and he was appointed as Chairman in January 2006. Mr. Neugebauer is a co-founder and since 1997 has been a Managing Partner of Quantum Energy Partners, a private equity fund specializing in the energy industry and an affiliate of Linn Energy. Prior to co-founding Quantum Energy Partners in 1997, Mr. Neugebauer co-founded Windrock Capital, Ltd., an energy investment banking firm specializing in raising private equity and providing merger, acquisition and divestiture advice for energy companies. Before co-founding Windrock Capital, Ltd. in 1994, Mr. Neugebauer was an investment banker in Kidder, Peabody & Co.’s Natural Resources Group. Mr. Neugebauer currently serves on the boards of Rockford Energy Partners II, LLC, Ensight Energy Partners, LP, Meritage Energy Partners, LLC, Meritage Energy Partners II, LLC, Denali Oil & Gas Partners, LP, Stratagem Energy Corp. and EnergyQuest Resources, LP, all of which are private energy companies.

George A. Alcorn was appointed to our Board of Directors in January 2006. Mr. Alcorn is an independent director and serves as Chairman of our nominating and conflicts committees. 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 was appointed to our Board of Directors in January 2006. Mr. Jacobs is an independent director and serves as Chairman of our audit committee. 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 was appointed to our Board of Directors in January 2006. Mr. Swoveland is an independent director and serves as Chairman of our compensation committee. Mr. Swoveland has served as Chief Financial Officer of Body Media, a life-science company specializing in the design and development of wearable

body monitoring products and services, since September 2000. Mr. Swoveland served as Vice President — Finance and Treasurer of Equitable Resources, Inc., a diversified natural gas company, from July 1999 to September 2000. He served as Interim Chief Financial Officer of Equitable Resources, Inc. from October 1997 to July 1999. Mr. Swoveland currently serves as a member of the board of directors of Petroleum Development Corporation.

Composition of the Board of Directors

Our Board of Directors consists of five members, each of whom will serve as directors until the date of the 2007 annual meeting of unitholders or their earlier death, resignation, or removal. Each of Messrs. George A. Alcorn, Terrence S. Jacobs and Jeffrey C. Swoveland have been determined by the Board of Directors to satisfy the independence requirements of The Nasdaq National Market and SEC rules. Beginning with our 2007 annual meeting of unitholders, 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 of Directors holds 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 telephone conference. 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.

Committees of the Board of Directors

Our Board of Directors established an audit committee, a compensation committee, a conflicts committee, and a nominating committee. Each committee consists of Messrs. Alcorn, Jacobs and Swoveland, each of whom is an independent director. We make available on our website under the “Investor Relations” heading the charters for our audit, compensation, conflicts and nominating committees.

Audit Committee. The audit committee recommends to the Board the independent registered public accounting firm to audit our financial statements and establishes the scope of, and oversees, the annual audit. The committee also approves any other services provided by public accounting firms. The audit committee provides 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, and the independent auditor’s qualifications and independence. The audit committee also oversees 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 is the responsibility of the audit committee to maintain free and open communication between the committee and our independent registered public accounting firm, the internal accounting function and management of our company.

The Board of Directors has determined Mr. Jacobs, the chairman of the audit committee, is an “audit committee financial expert,” as defined under SEC rules.

Compensation Committee. The compensation committee reviews the compensation and benefits of our executive officers, establishes and reviews general policies related to our compensation and benefits and administers our Long-Term Incentive Plan. The compensation committee determines the compensation of our executive officers. During fiscal year 2005, we had no compensation committee, and our pre-offering Board of Directors determined executive compensation.

Conflicts Committee. The conflicts committee reviews specific matters that the Board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to our company. Our limited liability company agreement provides 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. The nominating committee nominates candidates to serve on our Board of Directors and approves director compensation. The nominating committee also is responsible for developing and 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.

Audit Committee Report

The primary purpose of the audit committee is to assist the Board of Directors in fulfilling its responsibility to oversee the Company’s financial reporting activities. The audit committee meets with the Company’s independent registered public accounting firm and reviews the scope of their audit, report and recommendations. The audit committee also has sole authority for the selection of the Company’s independent registered public accounting firm. The audit committee members reviewed and discussed the audited financial statements for the year ended December 31, 2005 with management. The audit committee also discussed all matters required to be discussed by Statement of Auditing Standard No. 61 with the Company’s independent registered public accounting firm, KPMG, LLP. The audit committee reviewed the written disclosures and the letter from KPMG, LLP, as required by Independence Standards Board No. 1 and has discussed the independence of KPMG, LLP with representatives of such firm.

Based on their review and the discussions described above, the audit committee recommended to the Board of Directors that the Company’s audited financial statements be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 and be filed with the SEC.

AUDIT COMMITTEE:

Terrence S. Jacobs (Chairman)

George A. Alcorn

Jeffrey C. Swoveland

Communication with the Board of Directors

Unitholders may communicate with the Board of Directors regarding corporate governance matters by mailing all such communications to the following address:

Chair of Nominating Committee

c/o Linn Energy, LLC

650 Washington Road

8th Floor

Pittsburgh, PA 15228

Attention: Vice President and General Counsel

Director Compensation

Each independent director (as determined by the Board of Directors pursuant to applicable Nasdaq listing standards) serving on the Board of Directors of the Company receives an annual cash retainer of $25,000. Additionally, each independent director serving on the audit committee of the Company receives cash compensation of $25,000. The chairmen of the Company’s audit, compensation, nominating and conflicts committees receive an additional $2,000. In connection with his or her initial appointment or election to the

Board of Directors, each independent director is entitled to receive an option to acquire 10,000 units of the Company at an exercise price equal to the fair market value of the units on the grant date, vesting immediately. Upon any subsequent re-election to the Board of Directors, each independent director is entitled to receive an option to acquire 10,000 units of the Company at an exercise price equal to the fair market value of the units on the grant date, vesting over 3 years from the grant date in annual 1/3 increments, with certain exceptions.

Prior to our initial public offering in January 2006, there were no compensation arrangements in effect for service as a director of our company.

Code of Ethics

The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and other senior financial officers, and which meets the definition of a “code of ethics” under applicable SEC rules. The Company’s Code of Ethics for Chief Executive Officer and Senior Financial Officers is available free of charge on the internet at the Company’s website located at http://www.linnenergy.com under the “Investor Relations” heading. The Company intends to post on its website any amendments to such code, or any waiver from a provision of the code relating to the elements of a “code of ethics” under SEC rules, where such waiver is to the principal executive officer, principal financial officer, principal accounting officer or controller (or persons performing similar functions).

All of the Company’s directors, officers and employees are subject to the Company’s Code of Business Conduct and Ethics, which is also available free of charge on the internet at the website address and location set forth above.


Item 11.	Executive Compensation

The following table sets forth information concerning the compensation for services rendered in all capacities to Linn Energy, LLC and its subsidiaries for the years ended December 31, 2005 and 2004 for our President and Chief Executive Officer and our four other most highly compensated executive officers.

Summary Compensation Table


				Annual Compensation

								Other Annual			All Other
		Year		Salary($)		Bonus($)		Compensation(1)($)			Compensation(2)($)

Michael C. Linn			2005		200,000		—		—		$	8,400
	President and Chief		2004		118,750		200,000		—			—
	Executive Officer
Kolja Rockov(3)			2005		159,848		100,000		—		$	—
	Executive Vice President		2004		—		—		—			—
	and Chief Financial Officer
Gerald W. Merriam(4)			2005		140,000		50,000		—		$	8,400
	Executive Vice President—		2004		115,572		50,000		—			—
	Engineering Operations
Roland P. Keddie			2005		130,000		40,000		—		$	7,200
	Senior Vice President—		2004		105,000		50,000		—			—
	Secretary
Donald T. Robinson(5)			2005		70,833		40,000		34,021	(6)	$	2,817
	Chief Accounting Officer		2004		—		—		—			—


(1)	Except as described, the value of perquisites and other personal benefits did not exceed the lesser of either $50,000 or 10% of the total annual salary and bonus reported for each named executive officer.

(2)	Amounts shown reflect company matching contributions under the Company’s 401(k) Plan.

(3)	Mr. Rockov commenced employment with us in March 2005.

(4)	Effective April 7, 2006, Mr. Merriam resigned his position with the Company.


(5)	Mr. Robinson commenced employment with us in April 2005.

(6)	Amount represents a reimbursement by the Company of relocation costs and expenses.

Employment Agreements; Change-of-Control Arrangements

We have entered into an employment agreement with Michael C. Linn, our President and Chief Executive Officer, effective upon the closing of our initial public offering on January 19, 2006. 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, Mr. Linn received, upon completion of our initial public offering, an option to purchase 111,250 units at an exercise price of $21.00 per unit and a one-time cash bonus in the amount of $500,000. Mr. Linn will also receive, if he remains employed by us at such time, a grant of 625,781 units on the first anniversary of the completion of our initial public offering.

The unit grant will be fully vested upon issuance. The unit option award vests 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 piggyback 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 our initial public offering or the date on which Quantum Energy Partners holds less than 50% of the units it owned immediately following our initial public offering.

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

We entered into an employment agreement effective as of September 15, 2005 with Kolja Rockov, our Executive Vice President and Chief Financial Officer. Mr. Rockov’s employment agreement provides for an annual base salary of $200,000 subject to annual increase, plus a guaranteed cash bonus of not less than $100,000 for the fiscal year ending December 31, 2005, and incentive compensation payable at the discretion of our Board of Directors for the remainder of the term of employment. In addition, under his employment agreement, Mr. Rockov received, upon completion of our initial public offering, a grant of an aggregate 343,364 units and restricted units and an option to purchase 111,250 units at an exercise price of $21.00 per unit. Mr. Rockov also received a one-time cash bonus in the amount of $1.5 million.

The restricted unit award vests in equal installments over two years and the unit option award vests 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 piggyback 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 our initial public offering or the date on which Quantum Energy Partners holds less than 50% of the units it owned immediately following our initial public offering.

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. 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.

On April 13, 2006 Linn Operating, Inc. (“Linn Operating”), a wholly-owned subsidiary of Linn Energy, LLC, and Linn Energy, LLC entered into an employment agreement, effective as of April 3, 2006 (the “Employment Agreement”) with Thomas A. Lopus, providing for the employment by Linn Operating of Mr. Lopus as Senior Vice President — Operations. The Employment Agreement provides for an annual base salary of $175,000 subject to annual increase. The Employment Agreement also provides for a guaranteed bonus in 2006 of not less than $125,000 (“Guaranteed Bonus”) and thereafter, incentive compensation payable at the discretion of the Company’s board of directors. In addition, under the Employment Agreement Mr. Lopus is entitled to receive:


	•	an option to purchase 50,000 units at an exercise price of $19.74 per unit subject to a service based three-year vesting schedule (the


“Service Based Option”);


	•	a second option to purchase 25,000 units at an exercise price of $19.74 per unit subject to a specified service requirement and a performance based


vesting schedule; and


	•	a grant of 20,000 restricted units subject to a specified service requirement


and a performance based vesting schedule.

The Service Based Option 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. Lopus’ death or disability.

The performance based unit option award and restricted unit grant (the “Performance Awards”) vest upon the later of the date the performance goal for each tier is achieved, and the date of the required service period for each tier set forth in the third column of the following schedule:


Tier	Performance Goal		Service Period

	Company’s annualized
	distribution rate is at least:
Tier A	$	1.92 per unit		March 31, 2007
Tier B	$	2.30 per unit		March 31, 2008
Tier C	$	2.76 per unit		March 31, 2009

In the event the performance goal applicable to a particular tier is not met on or before December 31, 2009, that tier shall be forfeited as of December 31, 2009. Upon a change of control or a termination without cause, with good reason or upon Mr. Lopus’ death or disability the Performance Awards vest to the extent that the applicable performance goals set have been met with respect to each tier on or before the date of termination.

In the event of termination by Linn Operating other than for cause or termination by Mr. Lopus for good reason, the Employment Agreement provides for severance payments, if prior to the April 3, 2007, in 12 monthly installments and, if after April 3, 2007, in 24 monthly installments in an amount equal to one-twelfth (1/12th) of his highest Base Salary in effect at any time during the 36 months prior to the date of termination (“Highest Base Salary”). In the event of termination by Linn Operating other than for cause or termination by Mr. Lopus for good reason, on or prior to December 31, 2006 he will be entitled to a cash payment equal to his pro-rata Guaranteed Bonus. If, within one year of a change of control, we terminate his employment other than for cause or Mr. Lopus terminates his employment for good reason, he will be entitled to receive a lump-sum payment equal to, his Highest Base Salary if prior to April 3, 2007, two times his Highest Base Salary if on or after April 3, 2007 and the Company’s annualized distribution rate at the time of the change of control is at least $2.30 per unit, three times his Highest Base Salary if on or after April 3, 2008 and before December 31, 2009 and the Company’s annualized distribution rate at the time of the change of control is at least $2.76 per unit or up to three times his Highest Base Salary if on or after December 31, 2009 depending upon whether or not the foregoing specified annual distribution rates were achieved by the Company in the specified time periods set forth above.

The Employment Agreement prohibits Mr. Lopus 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. Lopus within one year of a change of control.

Effective April 14, 2006 (following the expiration of a seven-day revocation period), Linn Operating, Inc., Linn Energy, LLC, Linn Energy Holdings, LLC, Penn West Pipeline, LLC and Mid Atlantic Well Service, Inc. (collectively, the “Company”) entered into a separation agreement and general release (the “Separation Agreement”) with Mr. Gerald Merriam, formerly our Executive Vice President— Engineering Operations. Under the terms of the Separation Agreement Mr. Merriam received a severance payment of $217,600 less all applicable withholdings.

Mr. Merriam has agreed to release the Company and its predecessors, successors, affiliates, shareholders, unitholders, directors, officers, employees and agents from all claims arising from the beginning of time to the date of the Separation Agreement, including but not limited to claims relating to Mr. Merriam’s employment relationship with the Company, termination of such relationship and his capacity as a unitholder of the Company.

Additionally, Mr. Merriam has agreed to make himself available to the Company from time to time for a period not to exceed one year to provide consulting services to the Company at a rate of $100 per hour.


Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth the beneficial ownership of our units, as of May 8, 2006, by:


	•	each person known by us to beneficially own 5% or more of our units;

	•	each member of our Board of Directors;

	•	each of our named executive officers; 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 of May 8, 2006. 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.


				Percentage
		Units		of Units
		Beneficially		Beneficially
Name of Beneficial Owner(1)		Owned		Owned

Quantum Energy Partners(2)			10,144,585		36.4	%
Michael C. Linn			3,662,122		13.2	%
Kolja Rockov(3)			343,764		1.2	%
Gerald W. Merriam(4)			475,622		1.7	%
Roland P. Keddie			475,622		1.7	%
Donald T. Robinson			1,200		*
Toby R. Neugebauer(5)			10,244,585		36.8	%
George A. Alcorn(6)			12,000		*
Terrence S. Jacobs(6)			12,000		*
Jeffrey C. Swoveland(6)			10,000		*
	All executive officers and directors as a group (10 persons)(7)		14,781,793		53.1	%


	*	Less than 1% of class.


(1)	The address of each beneficial owner, unless otherwise noted, is c/o Linn Energy, LLC, 650 Washington Road, 8th Floor, Pittsburgh, PA 15228.

(2)	Based solely on information furnished in the Schedule 13D/ A (Amend. No. 1) filed by QEP, QEM-LP and QEM-LLC (each as defined below) with the SEC on February 17, 2006. Quantum Energy Partners owns its units through Quantum Energy Partners II, LP (“QEP”). QEP is controlled by its general partner, Quantum Energy Management II, LP (“QEM-LP”), which is controlled by its general partner, Quantum Energy Management II, LLC (“QEM-LLC”), an affiliate of Quantum Energy Partners. QEP, QEM-LP and QEM-LLC can be contacted at the following address: c/o Quantum Energy Partners, 777 Walker Street, Suite 2530, Houston, Texas 77002.

(3)	Includes 228,909 restricted units that vest in equal installments over a two-year period and 400 units as custodian under certain UGMA accounts for immediate family members as to which Mr. Rockov disclaims beneficial ownership.

(4)	Mr. Merriam resigned from the Company in April 2006.

(5)	Includes 10,144,585 units beneficially owned by Quantum Energy Partners and affiliated entities as described in note (2) above. Mr. Neugebauer, a principal of Quantum Energy Partners, could be deemed to beneficially own the units 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.

(6)	Includes 10,000 units receivable upon the exercise of a unit option that is exercisable within 60 days of the date of the table set forth above.

(7)	Includes 10,144,585 units beneficially owned by Quantum Energy Partners and its affiliated entities which could be deemed to be beneficially owned by our Chairman, Toby R. Neugebauer, a principal of Quantum Energy Partners, as to which Mr. Neugebauer disclaims beneficial ownership in excess of his indirect pecuniary interest. Also includes an aggregate of 30,000 units receivable upon the exercise of options that are held by certain of our directors and that are exercisable within 60 days of the date of the table set forth above. Excludes 475,622 units beneficially owned by Mr. Merriam.

Equity Compensation Plan Information

Our Long-Term Incentive Plan (“the Plan”) pursuant to which we may issue equity compensation to our employees, consultants and directors of Linn Energy, LLC and its affiliates was adopted in connection with our initial public offering in January 2006. As of December 31, 2005, no awards had been made pursuant to the Plan. Below is a summary of certain terms regarding the Plan.

Long-Term Incentive Plan

Immediately prior to the pricing of our initial public offering, we adopted the Linn Energy, LLC Long-Term Incentive Plan for employees, consultants and directors of Linn Energy, LLC and its affiliates who perform services for us. For purposes of the plan, our affiliates include Linn Operating, Inc. The long-term incentive plan consists of unit grants, unit options, restricted units, phantom units and unit appreciation rights. The long-term incentive plan limits the number of units that may be delivered pursuant to awards to 3.9 million units (which include the awards to Michael C. Linn and Kolja Rockov under their employment agreements pursuant to which 737,031 and 454,614 units may be delivered, respectively), provided that no more than 500,000 of such units (as adjusted) may be issued as restricted units. The plan is administered by the compensation committee of our Board of Directors.

Our Board of Directors and the compensation committee of the Board have the right to alter or amend the 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 to the participant without the consent of the participant.

Unit Grants. A unit grant is a unit that vests immediately upon issuance. In the future, the compensation committee may make unit grants under the plan to employees and members of our Board.

Unit Options. A unit option is a right to purchase a unit at a specified price. In the future, the compensation committee may make option grants under the plan to employees and members of our Board containing such terms as the committee shall determine. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee, although vesting may accelerate upon the achievement of specified financial objectives. In addition, the unit options will become exercisable upon a change in control of our company, unless provided otherwise by the committee. If a grantee’s employment, consulting relationship or membership on the Board of Directors terminates for any reason, the grantee’s unvested unit options will be automatically forfeited unless, and to the extent, the option agreement or the compensation committee provides otherwise.

Upon exercise of a unit option (or a unit appreciation right, as defined below, 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. In the future, the compensation committee may make additional grants of restricted units under the plan to employees, consultants and directors containing such terms as the compensation committee shall determine. The compensation committee will determine the period over which restricted units (and distributions related to such units) will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of our company, as defined in the plan, unless provided otherwise by the committee.

If a grantee’s employment, consulting relationship or membership on the Board of Directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. Units to be delivered as

restricted units may be units issued by us, units acquired by us in the open market, units already owned by us, units acquired by us from any other person or any combination of the foregoing. If we issue new units upon the grant of the restricted units, the total number of units outstanding will increase.

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

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

If a grantee’s employment, consulting relationship or membership on the Board of Directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. Units to be delivered upon the vesting of phantom units may be units issued by us, 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. 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 make grants of unit appreciation rights under the plan to employees, consultants and directors containing such terms as the committee shall determine. Unit appreciation rights will have an exercise price that will not be less than the fair market value of the units on the date of grant. In general, unit appreciation rights will become exercisable over a period determined by the compensation committee. In addition, the unit appreciation rights will become exercisable upon a change in control of our company, unless provided otherwise by the committee. If a grantee’s employment, consulting relationship or membership on the Board of Directors terminates for any reason, the grantee’s unvested unit appreciation rights will be automatically forfeited unless, and to the extent, the grant agreement or compensation committee provides otherwise.


Item 13.	Certain Relationships and Related Transactions

Stakeholders’ Agreement

Prior to filing our registration statement relating to our initial public offering, we and all of the holders of pre-initial public offering membership interests in us, including Quantum Energy Partners, non-affiliated equity investors and certain 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 affiliates.

We refer to this agreement as our “Stakeholders’ Agreement.” The Stakeholders’ Agreement resulted from arm’s-length negotiations among the parties, some of which are our affiliates. Toby R. Neugebauer, our Chairman, is a principal of Quantum Energy Partners.

Redemption and Equity Exchange. Pursuant to the terms of the Stakeholders’ Agreement, at the closing of our initial public offering, a portion of our pre-offering members’ membership interests were redeemed for cash with proceeds from the offering, and immediately following such redemption, the remaining membership interests of all our pre-offering members were exchanged for units. Each pre-offering member was allocated cash and/or units based on a formula tied to the initial public offering price of $21.00 per unit. In addition, in connection with the exercise by the underwriters of their overallotment option in our initial public offering, Quantum Energy Partners and the pre-offering non-affiliated members of our Company received cash in exchange for a portion of their units held immediately following our initial public offering.

The following table sets forth the cash consideration and/or units received by our pre-offering members pursuant to the redemption transactions and equity exchange described above.


	Consideration
	Received in Redemption
	Transactions and
Pre-Offering Member	Equity Exchange

Quantum Energy Partners(1)	$	108.6 million cash
		10,144,585 units
Non-affiliated equity investors(1)	$	2.8 million cash
		261,185 units
Michael C. Linn	$	3.0 million cash
		3,662,122 units
Gerald W. Merriam		475,622 units
Roland P. Keddie		475,622 units


(1)	Amounts shown give effect to the redemption of a portion of such member’s units with the proceeds received by the Company pursuant to the exercise by the underwriters of their over allotment option.

Registration Rights. Pursuant to the Stakeholders’ Agreement, Quantum Energy Partners has the right to require, for the benefit of itself and certain non-affiliated equity investors, the registration of the units acquired by them upon consummation of our initial public 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, the 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.

Other

Effective December 1, 2005, Mr. Eric P. Linn was appointed President of Mid Atlantic Well Service, Inc., a wholly owned subsidiary of Linn Energy, LLC. Mr. Linn’s annual base salary is $125,000 and he is provided

with use of a company vehicle. Mr. Linn is the brother of our President and Chief Executive Officer, Michael C. Linn.


Item 14.	Principal Accountant Fees and Services

We engaged our principal accountant, KPMG, LLP, in February 2005 in connection with our initial public offering. As part of this engagement, during 2005 KPMG audited our financial statements for the period from March 14, 2003 (inception) through December 31, 2003 and for the year ended December 31, 2004. KPMG also performed audit services for the fiscal year ended December 31, 2005, as well as the restatement audits for the period ended December 31, 2003, the year ended December 31, 2004 and the nine months ended September 30, 2004 and 2005. The amounts shown below in Audit Fees relate to all periods mentioned above with the exception of the audit related fees billed in connection with the initial public offering which is listed seperately below.

Below is information concerning fees billed by our principal accountant:

Audit Fees: The aggregate fees billed for financial statement audit or services provided in connection with statutory or regulatory filings were $1,187,822.

Audit-Related Fees: The aggregate audit-related fees billed by KPMG, LLP were $553,900. Audit-related services consisted of services related to the initial public offering.

Tax Fees: There were no fees billed by our principal accountant relating to professional services for tax compliance, advice or planning.

All Other Fees: There were no other fees billed by our principal accountant for services other than those described above.

Audit Committee Pre-Approval Policies and Practices

Prior to our initial public offering in January 2006, each type of audit service provided by Toothman Rice PLLC and KPMG, LLP was approved on an individual basis by management in advance of the rendering of such service. Following our initial public offering, our audit committee must pre-approve any audit and permissible non-audit services performed by our independent registered public accounting firm. Additionally, the audit committee has oversight responsibility to ensure the independent registered public accounting firm is not engaged to perform certain enumerated non-audit services, including but not limited to bookkeeping, financial information system design and implementation, appraisal or valuation services, internal audit outsourcing services and legal services.

PART IV


Item 15.	Exhibits and Financial Statement Schedules

(a)(1) and (2) Financial Statements

The consolidated financial statements of Linn Energy, LLC are listed on the Index to Financial Statements to this Annual Report beginning on page F-1.

(a)(3)Exhibits

The following documents are filed as a part of this Annual Report or incorporated by reference:

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

EXHIBIT INDEX


Exhibit Number				Description

	3	.1	—	Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on June 30, 2005) (the “Form S-1”)
	3	.2	—	Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to the Form S-1)
	3	.3	—	Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Linn Energy, LLC on January 19, 2006)
	4	.1*	—	Form of specimen unit certificate for the units of Linn Energy, LLC
	10	.1	—	Credit Agreement dated as of April 11, 2005, among Linn Energy, LLC (f/k/a Linn Energy Holdings, LLC), the Lenders from time to time party thereto, BNP Paribas, as administrative agent, and Royal Bank of Canada, as syndication agent (incorporated herein by reference to Exhibit 10.1 to the Form S-1)
	10	.2	—	First Amendment and Consent to Credit Agreement dated as of May 3, 2005, among Linn Energy, LLC (f/k/a Linn Energy Holdings, LLC), the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent (incorporated herein by reference to Exhibit 10.2 to the Form S-1)
	10	.3	—	Second Amendment to Credit Agreement dated as of August 12, 2005, among Linn Energy, LLC, the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent (incorporated herein by reference to Exhibit 10.3 to Amendment No. 1 to the Registration Statement on Form S-1 filed by Linn Energy, LLC on September 19, 2005 (“Amendment No. 1”)
	10	.4	—	Letter Agreement dated as of August 24, 2005, among Linn Energy, LLC, the Lenders signatory thereto and BNP Paribas, as administrative agent (incorporated herein by reference to Exhibit 10.4 to Amendment No. 1)
	10	.5	—	Third Amendment to Credit Agreement dated as of October 27, 2005, among Linn Energy, LLC, the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent (incorporated herein by reference to Exhibit 10.5 to Amendment No. 2 to the Registration Statement on Form S-1 filed by Linn Energy, LLC on October 31, 2005 (“Amendment No. 2”))
	10	.6	—	Fourth Amendment to Credit Agreement dated as of December 19, 2005, among Linn Energy, LLC, the Guarantors signatory thereto, the Lenders signatory thereto and BNP Paribas, as administrative agent (incorporated herein by reference to Exhibit 10.6 to Amendment No. 5 to the Registration Statement on Form S-1 filed by Linn Energy, LLC on January 3, 2006 (“Amendment No. 5”)
	10	.7	—	Second Lien Senior Subordinated Term Loan Agreement dated as of October 27, 2005, among Linn Energy, LLC, Royal Bank of Canada, as administrative agent, Societe Generale, as syndication agent, and the Lenders signatory thereto (incorporated herein by reference to Exhibit 10.6 to Amendment No. 2)
	10	.8	—	First Amendment to Credit Agreement and Consent dated as of November 22, 2005, among Linn Energy, LLC, Royal Bank of Canada, as administrative agent, and the Lenders signatory thereto (incorporated herein by reference to Exhibit 10.7 to Amendment No. 3 to the Registration Statement on Form S-1 filed by Linn Energy, LLC on November 25, 2005 (“Amendment No. 3”))
	10	.9	—	Second Amendment to Credit Agreement and Consent dated as of December 19, 2005, among Linn Energy, LLC, Royal Bank of Canada, as administrative agent, and the Lenders signatory thereto (incorporated herein by reference to Exhibit 10.9 to Amendment No. 5)
	10	.10	—	Intercreditor and Subordination Agreement dated as of October 27, 2005, among Linn Energy, LLC, Royal Bank of Canada, as subordinated administrative agent, and BNP Paribas, as administrative agent for the senior revolving lenders (incorporated herein by reference to Exhibit 10.7 to Amendment No. 2)


Exhibit Number				Description

	10	.11	—	Form of Asset Purchase Agreement dated as of October 1, 2005, between Exploration Partners, LLC and others, as Seller, and Linn Energy Holdings, LLC and others, as Purchaser (incorporated herein by reference to Exhibit 10.8 to Amendment No. 2)
	10	.12†	—	Form of Linn Energy, LLC Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.10 to Amendment No. 4 to the Registration Statement on Form S-1 filed by Linn Energy, LLC on December 14, 2005 (“Amendment No. 4”))
	10	.13†	—	Form of Unit Option Agreement pursuant to the Linn Energy, LLC Long-Term Inceptive Plan (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Linn Energy, LLC on February 21, 2006)
	10	.14	—	Stakeholders’ Agreement (incorporated herein by reference to Exhibit 10.4 to Form S-1)
	10	.15†	—	Amended and Restated Employment Agreement, dated as of December 14, 2005 between Linn Operating, Inc. and Michael C. Linn (incorporated herein by reference to Exhibit 10.12 to Amendment No. 4)
	10	.16†	—	Second Amended and Restated Employment Agreement, dated as of September 15, 2005 between Linn Operating, Inc. and Kolja Rockov (incorporated herein by reference to Exhibit 10.12 to Amendment No. 2)
	10	.17	—	Memorandum of Understanding Regarding Compensation Arrangements for Members of the Linn Energy, LLC Board of Directors (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Linn Energy, LLC on February 21, 2006)
	10	.18†	—	Employment Agreement, dated effective as of April 3, 2006 between Linn Operating, Inc. and Thomas A. Lopus (incorporation herein by reference to Exhibit 10.1 to the current Report on Form 8-K filed by Linn Energy, LLC on April 18, 2006 (the “April 18, 2006 Form 8-K”)
	10	.19†	—	Linn Energy, LLC Long-Term Incentive Plan Restricted Unit Agreement, dated effective as of April 13, 2006 between Linn Energy, LLC and Thomas A. Lopus (incorporated herein by reference to Exhibit 10.2 to the April 18, 2006 Form 8-K)
	10	.20†	—	Linn Energy, LLC Long-Term Incentive Plan Option Agreement, dated effective as of April 13, 2006 between Linn Energy, LLC and Thomas A. Lopus (incorporated herein by reference to Exhibit 10.3 to the April 18, 2006 Form 8-K)
	10	.21†	—	Separation Agreement and General Release, dated effective as of April 7, 2006 between Linn Energy, LLC and its subsidiaries and Gerald Merriam (incorporated herein by reference to Exhibit 10.4 to the April 18, 2006 Form 8-K)
	10	.22	—	Amended and Restated Credit Agreement dated as of April 7, 2006 among Linn Energy, as borrower, BNP Paribas, as administration agent, Royal Bank of Canada and Societe Generale, as Syndication agents, Bank of America, N.A. and America Bank, as documentation agents, and lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Linn Energy, LLC on April 13, 2006)
	10	.23*	—	First Amendment to Amended and Restated Credit Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lender signatory thereto, effective as of May 5, 2006
	21	.1*	—	List of subsidiaries of Linn Energy, LLC
	23	.1*	—	Consent of KPMG, LLP for Linn Energy, LLC
	23	.2*	—	Consent of Schlumberger Data and Consulting Services
	31	.1*	—	Rule 13a-14(a)/15d-14(a) Certification of Michael C. Linn, President and Chief Executive Officer of Linn Energy, LLC
	31	.2*	—	Rule 13a-14(a)/15d-14(a) Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
	32	.1*	—	Section 1350 Certification of Michael C. Linn, President and Chief Executive Officer of Linn Energy, LLC
	32	.2*	—	Section 1350 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC


	*	Filed herewith.


	†	Management contract or compensatory plan or arrangement.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Pittsburgh, State of Pennsylvania, on the 31st day of May 2006.


	LINN ENERGY, LLC


	By:	/s/ MICHAEL C. LINN



	Michael C. Linn
	President and
	Chief Executive Officer


	By:	/s/ KOLJA ROCKOV



	Kolja Rockov
	Executive Vice President and
	Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below on the dates indicated by the following persons on behalf of the Registrant and in the capacities indicated.


Signature	Title	Date


/s/ MICHAEL C. LINN Michael C. Linn	President and Chief Executive Officer (Principal Executive Officer)	May 31, 2006

/s/ KOLJA ROCKOV Kolja Rockov	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	May 31, 2006

/s/ DONALD T. ROBINSON Donald T. Robinson	Chief Accounting Officer (Principal Accounting Officer)	May 31, 2006

/s/ TOBY R. NEUGEBAUER Toby R. Neugebauer	Chairman	May 31, 2006

/s/ GEORGE A. ALCORN George A. Alcorn	Independent Director	May 31, 2006

/s/ TERRENCE S. JACOBS Terrence S. Jacobs	Independent Director	May 31, 2006

/s/ JEFFREY C. SWOVELAND Jeffrey C. Swoveland	Independent Director	May 31, 2006

INDEX TO FINANCIAL STATEMENTS


	Page

Linn Energy, LLC and Subsidiaries
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets, as of December 31, 2004 and 2005		F-3
Consolidated Statements of Operations, for the period from March 14, 2003 (Inception) to December 31, 2003 and years ended December 31, 2004 and 2005		F-5
Consolidated Statements of Members’ Capital (Deficit), for the period from March 14, 2003 (Inception) to December 31, 2003 and years ended December 31, 2004 and 2005		F-6
Consolidated Statements of Cash Flows, for the period from March 14, 2003 (Inception) to December 31, 2003 and years ended December 31, 2004 and 2005		F-7
Notes to Consolidated Financial Statements, December 31, 2003, 2004 and 2005		F-8

F-1

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, 2004 and 2005 and the related consolidated statements of operations, members’ capital (deficit) and cash flows for the period from March 14, 2003 (inception) to December 31, 2003 and for the years ended December 31, 2004 and 2005. 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, 2004 and 2005, and the results of their operations and their cash flows for the period ended December 31, 2003 and the years ended December 31, 2004 and 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note (20) to the consolidated financial statements, the Company restated its 2003 and 2004 consolidated financial statements.

/s/ KPMG LLP

Pittsburgh, Pennsylvania

May 31, 2006

F-2

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2004 AND 2005


					As of December 31,

					2004
					(Restated)		2005

Assets
Current assets:
	Cash and cash equivalents				$	2,188,244	$	11,041,346
	Receivables:
		Natural gas and oil, net of allowance for doubtful accounts of $50,000 in 2004 and $100,000 in 2005				5,462,775		17,103,422
		Other				82,539		650,168
	Fair value of interest rate swaps (note 3)					—		201,938
	Inventory					109,985		67,513
	Current portion of natural gas derivatives (note 8)					142,960		1,601,495
	Prepaid expenses and other current assets					93,782		4,067,309

			Total current assets			8,080,285		34,733,191

Natural gas and oil properties (successful efforts accounting method) (note 13):
	Natural gas and oil properties and related equipment					97,772,698		243,985,544
	Pipelines					1,536,878		5,579,920

						99,309,576		249,565,464
	Less accumulated depreciation, depletion, and amortization					3,928,802		10,707,358

						95,380,774		238,858,106

Property, plant, and equipment:
	Land					47,500		202,500
	Buildings and leasehold improvements					468,600		607,776
	Vehicles					689,892		1,317,362
	Furniture and equipment					342,487		888,194

						1,548,479		3,015,832
	Less accumulated depreciation					161,724		490,717

						1,386,755		2,525,115

Other assets:
	Prepaid drilling costs					362,095		434,801
	Equity investment					69,685		—
	Long-term portion of natural gas derivatives (note 8)					34,562		2,794,796
	Operating bonds					110,699		197,867

						577,041		3,427,464

				Total assets	$	105,424,855	$	279,543,876

See accompanying notes to consolidated financial statements.

F-3

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2004 AND 2005


			As of December 31,

			2004
			(Restated)			2005			2005 Pro Forma

									(Unaudited)
									(Note 18)
Liabilities and Members’ Capital (Deficit)
Current liabilities:
	Current portion of long-term notes payable (note 10)		$	58,113		$	112,904
	Subordinated term loan (note 3)			—			59,501,375
	Current portion of interest rate swaps (note 3)			38,933			—
	Accounts payable and accrued expenses			3,132,286			5,571,637
	Current portion of natural gas derivatives (note 8)			3,599,904			12,093,937
	Revenue distribution			2,493,145			6,081,978
	Accrued interest payable (note 3)			411,245			1,447,721
	Gas purchases payable			481,993			1,207,710
	Other current liabilities			—			40,552

		Total current liabilities		10,215,619			86,057,814

Long-term liabilities:
	Long-term portion of notes payable (note 10)			539,867			694,815
	Credit facility (note 3)			72,210,107			206,118,790
	Long-term portion of interest rate swaps (note 3)			1,408,629			662,916
	Asset retirement obligation (note 11)			3,856,584			5,442,612
	Long-term portion of natural gas derivatives (note 8)			7,674,117			27,139,353
	Other long-term liabilities			—			258,480

		Total long-term liabilities		85,689,304			240,316,966

		Total liabilities		95,904,923			326,374,780

Members’ capital (deficit):
	Members’ capital			16,023,743			16,023,743		$	140,023,743
	Accumulated loss			(6,503,811	)		(62,854,647	)		(64,854,647	)

				9,519,932			(46,830,904	)	$	75,169,096

		Total liabilities and members’ capital (deficit)	$	105,424,855		$	279,543,876

See accompanying notes to consolidated financial statements.

F-4

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE PERIOD

FROM MARCH 14, 2003 (INCEPTION) TO DECEMBER 31, 2003

AND YEARS ENDED DECEMBER 31, 2004 AND 2005


			Period from
			March 14,
			2003
			(inception) to			Year Ended December 31,
			December 31,
			2003			2004
			(Restated)			(Restated)			2005

Revenues:
	Natural gas and oil sales		$	2,379,301		$	19,502,114		$	44,644,593
	Realized gain (loss) on natural gas derivatives (note 8)			162,890			(2,239,506	)		(51,417,870	)
	Unrealized (loss) on natural gas derivatives (note 8)			(1,599,854	)		(8,764,855	)		(24,775,625	)
	Natural gas marketing revenue			—			520,340			4,722,587
	Other revenue			3,778			160,131			345,449

				946,115			9,178,224			(26,480,866	)

Expenses:
	Operating expenses			798,236			4,756,071			7,356,134
	Natural gas marketing expense			—			481,993			4,400,845
	General and administrative expenses			782,849			1,487,964			3,331,924
	Depreciation, depletion and amortization			562,446			3,656,332			7,293,832

				2,143,531			10,382,360			22,382,735

				(1,197,416	)		(1,204,136	)		(48,863,601	)

Other income and (expenses):
	Interest income			34,139			7,379			47,157
	Interest and financing expense (note 3)			(516,883	)		(3,530,360	)		(7,039,556	)
	Loss from equity investment			(2,929	)		(56,126	)		(16,714	)
	Write-off of deferred financing fees (note 3)			—			—			(364,166	)
	(Loss) on sale of assets			(4,916	)		(32,563	)		(39,492	)

				(490,589	)		(3,611,670	)		(7,412,771	)

Loss before income taxes				(1,688,005	)		(4,815,806	)		(56,276,372	)
	Income tax (provision) (note 4)			—			—			(74,464	)

		Net (loss)	$	(1,688,005	)	$	(4,815,806	)	$	(56,350,836	)

Pro forma (loss) per unit (unaudited) (note 18)
	Pro forma (loss) per unit		$	(0.06	)	$	(0.17	)	$	(2.03	)
	Pro forma units outstanding			27,812,500			27,812,500			27,812,500

See accompanying notes to consolidated financial statements.

F-5

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL (DEFICIT)

FOR THE PERIOD

FROM MARCH 14, 2003 (INCEPTION) TO DECEMBER 31, 2003

AND YEARS ENDED DECEMBER 31, 2004 AND 2005


	Members’			Accumulated			Total Members’
	Capital			Loss			Capital (Deficit)

Contributions	$	16,323,743		$	—		$	16,323,743
Return of capital (note 5)		(300,000	)		—			(300,000	)
Net loss for period from March 14, 2003 (inception) to December 31, 2003 (restated)		—			(1,688,005	)		(1,688,005	)

Balance as of December 31, 2003 (restated)		16,023,743			(1,688,005	)		14,335,738
Net loss for year ended December 31, 2004 (restated)		—			(4,815,806	)		(4,815,806	)

Balance as of December 31, 2004 (restated)		16,023,743			(6,503,811	)		9,519,932
Net loss for the year ended December 31, 2005		—			(56,350,836	)		(56,350,836	)

Balance as of December 31, 2005	$	16,023,743		$	(62,854,647	)	$	(46,830,904	)

See accompanying notes to consolidated financial statements.

F-6

LINN ENERGY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE PERIOD FROM MARCH 14, 2003 (INCEPTION) TO

DECEMBER 31, 2003 AND YEARS ENDED DECEMBER 31, 2004 AND 2005


					Period from
					March 14,
					2003
					(inception) to			Year Ended December 31,
					December 31,
					2003			2004
					(Restated)			(Restated)			2005

Cash flow from operating activities:
	Net (loss)				$	(1,688,005	)	$	(4,815,806	)	$	(56,350,836	)
	Adjustments to reconcile net (loss) to net cash provided by (used in) operating activities:
		Depreciation, depletion and amortization				562,446			3,656,332			7,293,832
		Amortization of deferred financing fees				20,454			123,403			455,165
		Write-off of deferred financing fees				—			—			364,166
		Loss on sale of assets				4,916			32,563			39,492
		Loss from equity investment				2,929			56,126			16,714
		Accretion of asset retirement obligation				14,683			73,501			172,426
		Unrealized loss on natural gas derivatives				1,599,854			8,764,855			24,775,625
		Unrealized loss (gain) on interest rate swaps				188,928			1,258,634			(986,584	)
		Changes in assets and liabilities:
			(Increase) in accounts receivable			(1,780,602	)		(3,724,712	)		(12,208,276	)
			(Increase) decrease in inventory			—			(179	)		42,472
			(Increase) decrease in prepaid expenses and other assets			(98,972	)		5,190			(441,619	)
			Increase in accounts payable and accrued expenses			257,698			1,562,839			2,670,232
			(Decrease) increase in natural gas derivatives			(27,700	)		759,490			(1,035,125	)
			Increase in revenue distribution			583,794			1,909,351			3,588,833
			Increase in asset retirement obligation			2,299			18,754			24,439
			Increase in accrued interest payable			222,594			188,651			1,036,476
			Increase in other liabilities			—			—			299,032
			Increase in gas purchases payable			—			481,993			725,717

				Net cash provided by (used in) operating activities		(134,684	)		10,350,985			(29,517,819	)

Cash flow from investing activities:
	Acquisition and development of natural gas and oil properties					(32,453,799	)		(62,074,739	)		(149,210,712	)
	Purchases of property and equipment					(409,613	)		(1,518,966	)		(1,638,556	)
	Proceeds from sale of assets					8,584			334,037			115,130
	(Increase) decrease in prepaid drilling cost					(2,300,643	)		1,938,548			(72,706	)
	Payments for operating bonds					(75,342	)		(35,357	)		(87,168	)
	Purchase of equity investment					(113,242	)		(15,498	)		(3,625	)

				Net cash (used in) investing activities		(35,344,055	)		(61,371,975	)		(150,897,637	)

Cash flow from financing activities:
	Proceeds from notes payable					—			604,358			65,294,952
	Principal payments on notes payable					—			(6,378	)		(5,085,213	)
	Principal payment on credit facility					—			—			(75,605,000	)
	Proceeds from credit facility					41,800,000			30,805,000			210,000,000
	Deferred offering costs					—			—			(3,531,908	)
	Deferred financing fees					(302,500	)		(236,250	)		(1,804,273	)
	Capital contributions by members					16,323,743			—			—
	Return on capital					(300,000	)		—			—

				Net cash provided by financing activities		57,521,243			31,166,730			189,268,558

				Net increase (decrease) in cash		22,042,504			(19,854,260	)		8,853,102
Cash and cash equivalents:
	Beginning					—			22,042,504			2,188,244

	Ending				$	22,042,504		$	2,188,244		$	11,041,346

				Cash payments for interest	$	84,907		$	1,959,672		$	6,509,501
				Cash paid for income taxes		—			—			—
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			1,389,163

See accompanying notes to consolidated financial statements.

F-7

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2003, 2004 AND 2005


(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 in April 2005 under the laws of the State of Delaware. Linn owns 100% of Linn Energy Holdings, LLC (“Holdings”), Linn Operating, Inc. (“Operating”), Penn West Pipeline, LLC (“Penn West”), and Mid Atlantic Well Service, Inc. (“Mid Atlantic”). Holdings was formed on March 14, 2003 and began its primary operations effective April 1, 2003. Its wholly owned subsidiaries were Linn Operating, LLC and Penn West. On April 6, 2005 Linn was formed as a holding company and as a result Holdings became a wholly owned subsidiary of the Company. The Company is an independent natural gas company focused on the development and acquisition of natural gas properties in the Appalachian Basin, primarily in West Virginia, Pennsylvania, New York and Virginia.


*(b)*	*Basis of Presentation*

The accompanying consolidated financial statements include the accounts of Linn and its wholly owned operating subsidiaries, Holdings, Operating, Penn West and Mid Atlantic. 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 accounts receivable 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.


*(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.

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LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 11, the Company follows SFAS No. 143. Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed 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. No impairments were recorded in 2003, 2004, or 2005.


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

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

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

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


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

Property, plant and equipment other than natural gas and oil properties is carried at cost. Depreciation is provided principally on the straight-line method over useful lives as follows:


Buildings and leasehold improvements			7-39 years
Furniture and equipment			3-7 years
Vehicles			5 years

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LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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*

Linn Energy, LLC, Holdings, and Penn West are limited liability companies treated as partnerships for federal and state income tax purposes with all income tax liabilities and/or benefits being passed through to the members. As such, no federal or state income taxes for these entities have been provided for in the accompanying financial statements except as described below.

The Company’s wholly owned subsidiaries, Operating (formed on June 1, 2005) and Mid Atlantic (formed on October 12, 2005), are Subchapter C-corporations subject to corporate income taxes. Thus, it is necessary to provide for federal and state income taxes related to Operating and Mid Atlantic. Deferred income taxes are recorded under the asset and liability method. Deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. A deferred tax liability of $74,464 has been included in other long-term liabilities as of December 31, 2005. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities. The provision for income taxes in 2005 relates to the operations of Operating and Mid Atlantic.


*(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. As of December 31, 2005, these transactions were in the form of swaps and puts. 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 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. None of the Company’s commodity or interest rate derivatives have been designated as hedges and therefore the change in the fair value of the derivatives is included in income.

F-10

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(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 U.S. generally accepted accounting principles. Actual results could differ from those estimates. The estimates that are particularly significant to the financial statements include estimates of natural gas and oil reserves, future cash flows from natural gas and oil properties, depreciation, depletion and amortization, asset retirement obligations and the fair value of derivatives.


*(l)*	*Revenue Recognition*

Sales of natural gas and oil are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Company on a monthly basis. Virtually all of the Company’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company’s revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry.

Gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total gas production. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. The Company did not have any significant gas imbalance positions at December 31, 2004 or 2005.

Natural gas marketing is recorded on the gross accounting method. Penn West, 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. Penn West 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 Penn West takes title to the natural gas it purchases from the various producers and bears the risks and enjoys the benefits of that ownership. Penn West had natural gas marketing revenues of $520,340 and $4,722,587 and natural gas marketing expenses of $481,993 and $4,400,845 in 2004 and 2005, respectively.

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 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. For the period March 13, 2003 (inception) through December 31, 2003 and the year ended December 31, 2004 the restated operating fees netted against general and administrative expense were $80,073 and $598,160, respectively. For the year ended December 31, 2005, the operating fees netted against general and administrative expenses were $1,196,146.

F-11

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(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, 2004 and 2005. Please read notes 3 and 8 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 years ended December 31, 2004 and 2005 were $302,500, $236,250 and $1,804,273, respectively. These debt issuance costs are amortized over the life of the debt agreement. For the period from March 14, 2003 (inception) through December 31, 2003 and the years ended December 31, 2004 and 2005, amortization expense of $20,454, $123,403 and $455,165, respectively, is included in interest expense.


*(o)*	*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, 2004 and 2005 was $16,323,743, of which Quantum Energy Partners’ share was $15,000,000.

Pursuant to applicable provisions of the Delaware Limited Liability Company Act (the “Delaware Act”) and the Second Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (the “Agreement”), members have no liability for the debts, obligations and liabilities of the Company, except as expressly required in the Agreement or the Delaware Act. Pursuant to the terms of the Agreement, unitholders are entitled to vote on the following matters:


	•	the annual election of members of the Company’s Board of Directors;

	•	specified amendments to the Agreement;

	•	the merger of the Company or the sale of all or substantially all of the Company’s assets; and

	•	the dissolution of the Company.

The Company will remain in existence unless and until dissolved in accordance with the terms of the Agreement.


*(p)*	*Revenue Distribution*

Revenue distribution on the consolidated balance sheet of $2,493,145 and $6,081,978 represents amounts owed to working interest and royalty interest owners as of December 31, 2004 and 2005, respectively.


*(q)*	*Deferred Offering Costs*

Prepaid expenses include costs incurred in connection with the Company’s planned initial public offering (“IPO”). The Company reclassified these deferred offering costs to members’ capital upon receipt of the proceeds from the IPO during the first quarter of 2006 (see note 17). As of December 31, 2004 and 2005, prepaid expenses included $0 and $3,531,908, respectively, in deferred offering costs.


*(r)*	*Stock Based Compensation*

The Company accounts for stock based compensation pursuant to SFAS No. 123(R) — Share-Based Payment. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other

F-12

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

equity-based compensation issued to employees in the income statement and eliminates the alternative to use the intrinsic value method of accounting that was provided in SFAS No. 123, which generally results in no compensation expense recorded in the financial statements related to the issuance of equity awards to employees. It establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all companies to apply a fair-value-based measurement method in accounting for generally all share-based payment transactions with employees. On March 29, 2005, the SEC staff issued Staff Accounting Bulletin (“SAB”) No. 107 — Share-Based Payment, to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. The Company recorded no stock based compensation expense for the period March 14, 2003 (inception) to December 31, 2003 or for the years ended December 31, 2004 and 2005 as there were no share-based payments made during the respective periods. See note 17 regarding share-based payments granted subsequent to December 31, 2005.


*(s)*	*Reclassifications*

Certain 2003 and 2004 balances and disclosures have been reclassified to conform to the 2005 presentation.


*(t)*	*Recent Accounting Standards*

On March 30, 2005, the Financial Accounting Standards Board (“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 was effective for the Company at the end of the fiscal year ended December 31, 2005. The Company has evaluated and adopted FIN No. 47 which had no 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 Company adopted the FSP in the third quarter of 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The Company’s application of this FSP did not have a significant impact on the Company’s financial position or results of operations.

F-13

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In May 2005, the FASB issued SFAS No. 154 — Accounting Changes and Error Corrections, which replaces Accounting Principles Bulletin (“APB”) Opinion No. 20 — Accounting Changes, and SFAS No. 3 — Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 changes the requirements for the accounting and reporting of a change in accounting principle. APB Opinion No. 20 previously required that most voluntary changes in an accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. SFAS No. 154 now requires retrospective application of changes in an accounting principle to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. The Company does not expect the adoption of SFAS No. 154 to have a material impact on its consolidated financial statements.


*(u)*	As discussed in note 20, the Company restated its 2003, 2004 and nine months ended September 30, 2004 and 2005 consolidated financial statements.


(2)	Major Acquisitions

The Company consummated the following acquisitions of natural gas and oil properties during 2004 and 2005. The purchase prices represent the total cash consideration plus the net liabilities assumed. Results of operations for each acquisition are included in the consolidated statements of operations as of the acquisition dates noted below:


	•	On May 7, 2004, from Mountain V Oil and Gas, Inc. (“Mountain V”), 251 producing wells, tangible wellhead equipment, production facilities, and real estate in western Pennsylvania, for a restated purchase price of $12.5 million.

	•	On September 30, 2004, from Pentex Energy, Inc. (“Pentex”), 447 producing wells, operating rights, oil field equipment, vehicles, inventory, office equipment, furniture and fixtures, and real estate in western Pennsylvania, for a restated purchase price of $15.1 million.

	•	On April 27, 2005, from Columbia Natural Resources, LLC (“CNR”), 38 producing wells, tangible wellhead equipment and a gathering system in West Virginia and western Virginia, for a purchase price of $4.4 million.

	•	On August 31, 2005, from GasSearch Corporation (“GasSearch”), 130 producing wells and tangible wellhead equipment in West Virginia, for a purchase price of $5.4 million.

	•	On October 27, 2005, from Exploration Partners, LLC (“Exploration Partners”), 550 producing wells, oil field equipment and tangible wellhead equipment in West Virginia and Virginia, for a purchase price of $111.4 million.

The following table represents the fair values of the assets acquired and liabilities assumed at the date of the acquisitions:


													Exploration
	Mountain V			Pentex			CNR			GasSearch			Partners

	(in thousands)
Natural gas and oil receivable	$	658		$	910		$	—		$	97		$	2,418
Natural gas and oil properties		12,225			14,373			4,396			5,422			111,081
Property, plant and equipment		230			503			—			—			307
Other assets		—			265			—			—			—
Accounts payable		—			(903	)		—			(13	)		(230	)
Asset retirement obligation		(601	)		(1,070	)		(74	)		(200	)		(944	)

Net cash consideration	$	12,512		$	14,078		$	4,322		$	5,306		$	112,632

F-14

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following unaudited pro forma information presents the financial information of the Company as if the acquisitions of Mountain V, Pentex, CNR, GasSearch and Exploration Partners had occurred on January 1, 2004.


	Year Ended December 31,

	2004 (Restated)						2005

	As Reported			Pro Forma			As Reported			Pro Forma

	(In thousands)						(In thousands)
Natural gas and oil sales	$	19,502		$	35,900		$	44,645		$	59,533

Net (loss)	$	(4,816	)	$	(7,029	)	$	(56,351	)	$	(55,129	)


(3)	Debt


	*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, 2004, the Company had borrowed $72.6 million on the credit facility and the applicable weighted average interest rate was 4.1%.

The Agreement required the Company to, among other things, maintain a minimum working capital balance and achieve certain earnings-related ratios, and limited the amount of indebtedness and certain distributions. The working capital and earnings-related ratios were calculated based on tax basis financial statements. At December 31, 2004, the Company was in compliance with the Agreement’s covenants.

On April 11, 2005, the Company entered into a $200 million secured revolving credit agreement with a group of banks including BNP Paribas and RBC Capital Markets. The funds from the new credit facility were used to pay off the balance outstanding on the old credit facility in place as of December 31, 2004. The credit facility matures on April 11, 2009. The Company’s obligations under the credit facility are secured by mortgages on its natural gas and oil properties as well as a pledge of all ownership interests in its operating subsidiaries. In October 2005, the aggregate commitments available under the credit facility were increased to $300 million. The amount available for borrowing at any one time is limited to the borrowing base, which at December 31, 2005 was $225 million. The outstanding balance on the new credit facility accrues interest at a rate of LIBOR plus an applicable margin of between 1.250% and 1.875% or the prime rate plus an applicable margin between 0.000% to 0.375%. The applicable weighted average interest rate on the outstanding balance as of December 31, 2005 was 6.110%. Interest is payable quarterly and at the maturity date. The 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.

As we identified the need to restate our financial statements, we were unable to provide audited financial statements to the lenders within 90 days after the end of our fiscal year. Therefore, we obtained necessary waivers of certain covenants to remain in compliance with the terms of the credit facility. The waivers grant the Company 90 days to provide the required financial statements to the lenders.

F-15

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As a result of the credit facility, the Company wrote off $364,166 of deferred financing cost related to the old credit agreement which is reflected in the accompanying statement of operations for 2005.

As of December 31, 2004 and 2005, the credit facility consisted of the following:


	December 31,			December 31,
	2004			2005

Outstanding balance	$	72,605,000		$	207,000,000
Less deferred financing fees, net of amortization of $143,857 and $160,124		(394,893	)		(881,210	)

	$	72,210,107		$	206,118,790

Accrued interest was $411,245 and $1,052,898 at December 31, 2004 and 2005, respectively.

See also note 17 regarding the subsequent amended and restated credit agreement.


	*Subordinated Term Loan*

On October 27, 2005, the Company entered into a facility for a $60 million second lien senior subordinated term loan (“the subordinated term loan”) with Royal Bank of Canada, Societe Generale and other lenders. The proceeds from the subordinated term loan were used to pay for the acquisition of existing natural gas wells and related equipment. The subordinated term loan matures on April 30, 2006. The balance is secured by mortgages on the Company’s natural gas and oil properties as well as a pledge of all ownership interests in its operating subsidiaries. The balance was paid in full in January 2006 with proceeds from our initial public offering (see note 17). Borrowings on the subordinated term loan bear interest at a rate equal to, at the Company’s election, either (i) the London interbank offered rate (“LIBOR”) plus an applicable margin of 3.875% or (ii) a domestic bank rate plus an applicable margin of 2.375%. The rate applicable to the debt was 8.169% percent as of December 31, 2005. The Company amortized the deferred financing costs on this subordinated term loan based upon the effective interest rate method. Under this method the effective interest rate was approximately 10.727% as of December 31, 2005. Covenants on the subordinated term loan are the same as on the credit facility. As of December 31, 2005, the Company was in compliance with all covenants of the subordinated term loan.

As of December 31, 2005, the subordinated term loan consisted of the following:


	December 31,
	2005

Outstanding balance	$	60,000,000
Less deferred financing fees, net of amortization of $249,312		(498,625	)

	$	59,501,375

Accrued interest was $394,823 at December 31, 2005.


	*Interest Rate Swaps*

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 first agreement was effective and matured in 2005 and the second agreement is effective in 2006 and matures in 2007. The Company was required to pay interest quarterly at a rate of 3.17% and 4.33%, respectively. In 2005, the Company received quarterly payments based on the three-month LIBOR rate.

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 are effective and mature in 2007 and 2008. The Company will pay quarterly interest at a rate of 5.23% and 5.72%, respectively. The Company will receive quarterly payments based on the three-month LIBOR rate.

F-16

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 first interest rate swap agreement was effective and matured in 2005 and the second agreement is effective and matures in 2006, and the Company is required to pay quarterly interest payments at a rate of 3.08% and 4.42%, respectively. In 2005, the Company received quarterly payments base on the three-month LIBOR rate.

In connection with the new credit facility, the Company converted its initial four interest rate swap agreements to a new third party financial institution. The terms of the four new interest rate swap agreements are as follows:


	•	Agreement effective in April 2005 for $30 million. The Company made quarterly interest payments during 2005 at a rate of 3.24%. The agreement matures in January 2006.

	•	Agreement effective in January 2006 for $30 million. The Company is required to make quarterly interest payments during 2006 at a rate of 4.4%. The agreement matures in January 2007.

	•	Agreement effective in January 2007 for $50 million. The Company is required to make quarterly interest payments during 2007 at a rate of 5.3%. The agreement matures in December 2007.

	•	Agreement effective in January 2008 for $50 million. The Company is required to make quarterly interest payments during 2008 at a rate of 5.79%. The agreement matures in December 2008.

The Company receives quarterly interest payments at 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. As of December 31, 2005, the total fair value of the interest rate swap agreements was a liability of $460,978. The current portion of $201,938 is recorded as an asset on the balance sheet. Unrealized (losses) gains due to the change in the fair value of $(188,928) in 2003, $(1,258,634) in 2004 and $986,584 in 2005 are recorded in interest and financing expense in the accompanying consolidated statements of operations. The Company minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties. The interest rate swaps were not designated as hedges and, accordingly, the change in fair value was recorded in current period earnings.


(4)	Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. As such, it is not a taxable entity and does not directly pay federal and state income tax. Its taxable income or loss, which may vary substantially from the net income or net loss reported in the consolidated statements of income, is includable in the federal and state income tax returns of each member. Accordingly, no recognition has been given to federal and state income taxes for the operations of the Company except as described below. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each member’s tax attributes in the Company.

On June 1, 2005, Linn Operating, LLC was converted to a Subchapter C-corporation. Additionally, on October 12, 2005, the Company incorporated Mid Atlantic Well Service, Inc. Prior to June 1, 2005, the Company and its subsidiaries were structured as limited liability companies treated as partnerships or disregarded entities for federal income tax purposes. The income tax provision attributable to the Company’s Subchapter

F-17

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

C-corporation subsidiaries’ losses before income taxes consisted of the following for the year ended December 31, 2005:


	Current		Deferred		Total

2005:
U.S. federal	$	—	$	56,712	$	56,712
State		—		17,752		17,752

	$	—	$	74,464	$	74,464

As of December 31, 2005, Mid Atlantic Well Service, Inc. had approximately $6,000 of net operating loss carryforwards for federal income tax purposes, which expire in 2025.

Significant components of Operating’s and Mid Atlantic’s deferred tax assets and liabilities as of December 31, 2005 were as follows:


Deferred tax assets:
	Net operating loss carryforwards		$	2,579
	Charitable contribution carryforwards			24,034
	Allowance for doubtful accounts			40,270

		Total deferred tax assets		66,883

Deferred tax liabilities:
	Properties and equipment principally due to differences in depreciation			141,347

		Total deferred tax liabilities		141,347

		Net deferred tax liabilities	$	74,464

Income tax expense differed from amounts computed by applying the federal income tax rate of 34% to pre tax income as a result of the following at December 31, 2005:


Federal, U.S. statutory rate	$	(19,134,748	)	(34.00	)%
State, net of federal tax benefit		11,716		0.02	%
Loss from non-taxable entities		19,168,182		34.06	%
Other items		29,314		0.05	%

Provision for income taxes	$	74,464		0.13	%

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.


(5)	Related Party Transactions

Under the terms of its limited liability company agreement, Linn paid to Quantum, the majority member, a fee of 2.0% of each capital contribution made to the Company by Quantum. Management believes the 2% fee was fair value. The 2% fee was initially negotiated on an arms-length basis among unrelated third parties. Fees

F-18

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

paid during the period from March 14, 2003 (inception) through December 31, 2003 and the years ended December 31, 2004 and 2005 were $300,000, $0 and $0, respectively. The payments were recognized as a return of capital on the consolidated statements of members’ capital.

On December 1, 2003, the Company entered into an assignment and bill of sale with Linn Resources, LLC, a related party, for the purchase of all of Linn Resources’ interests in 2 wells and related equipment. The purchase price for this transaction was approximately $150,000. The purchase price was determined based on the price paid for working interests from an unrelated third party during 2003 and thus management believes this transaction was conducted at fair value.

Mr. Eric P. Linn was appointed President of Mid Atlantic Well Service, Inc., a wholly owned subsidiary of Linn Energy, LLC, effective December 1, 2005. Mr. Linn’s annual base salary is $125,000 and he is provided with use of a company vehicle. Mr. Linn is the brother of the Company’s President and Chief Executive Officer, Michael C. Linn.


(6)	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 years ended December 31, 2004 and 2005.

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.

The Company has executed employment agreements with certain members of management. The agreements provide for annual compensation levels subject to annual increases, incentive compensation, options to purchase units and unrestricted units upon completion of the initial public offering and restricted units upon performance of specified service periods. The following is a summary of options and unit grants made in 2006.

Number of

Exercise

Vesting

Number of

Service

Options

Price

Period

Unrestricted Units

Restricted Units

Period

President & CEO

111,250

21.00

3 years

—

625,781

1 year

CFO

111,250

21.00

3 years

114,455

228,909

2 years

SVP — Operations

75,000

19.74

3 years

—

20,000

3 years


(7)	Business and Credit Concentrations


	*Cash*

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


	*Revenue and Trade Receivables*

The Company has a concentration of customers who are engaged in natural gas and oil production within the Appalachian region. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company performs ongoing credit evaluations of its customers and generally does not require collateral.

F-19

LINN ENERGY, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. For the year ended December 31, 2005, the Company’s three largest customers represented approximately 48%, 14% and 10% of the Company’s sales.

As of December 31, 2004, trade accounts receivable from our four largest customers represented approximately 17%, 17%, 11%, and 29% of the Company’s receivables. Trade accounts receivable for the two largest customers represented approximately 70% and 13% of the Company’s receivables as of December 31, 2005.


(8)	Natural Gas Derivatives

The Company sells natural gas in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in natural gas. The Company enters into derivative instruments such as swap contracts and put options to hedge a portion of its forecasted natural gas sales.

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