HAPL 39 th Annual Technical Workshop Presentation

1. HAPL 39th Annual Technical Workshop Presentation April 24, 2008

2. Forward-Looking Statements Statements made by representatives of Linn Energy, LLC during the course of this presentation that are not historical facts are forward-looking statements. These statements are based on certain assumptions and expectations made by the Company which reflect management’s experience, estimates and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to financial performance and results, our indebtedness under our credit facility, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for gas, oil and natural gas liquids, our ability to replace reserves and efficiently develop our current reserves, our ability to make acquisitions on economically acceptable terms, and other important factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. See “Risk Factors” in the Company’s 2007 Annual Report on Form 10-K and any other public filings and press releases. Linn Energy undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. This presentation has been prepared as of April 11, 2008.

3. Senior Management Representative Mark E. Ellis President & Chief Operating Officer

4. What Assets Fit the MLP Model

5. Appalachia Sale Rationale • Capitalizes on Marcellus Shale enthusiasm • Marcellus Shale is a challenging asset for the MLP / LLC structure • Significant capital commitments • Exploration risk • Marcellus Shale development introduces new risks to conventional production and development activities • Additional capacity constraints • Escalating costs (puts pressure on conventional economics) • Conventional Appalachian inventory does not compete well with broader inventory set • Enhances financial strength • Reduces revolver by $550 million • Borrowing capacity increases to approximately $700 million from approximately $300 million • Ability to repay entire $400 million term loan if so desired • In the current market, opportunities exist to rebuy nearly twice as much cash flow from “pure” MLP assets for the same price, for example: • Lamamco – purchase price $552 million; EBITDA $75-$90+ million • Appalachia – sale price $600 million ($550 million net); EBITDA $50-$55 million

6. Appalachia Sale Metrics • Due to Marcellus potential, Linn Energy was able to realize a full value for its Appalachian properties through the sale • Value metrics based on proved reserves of 197 Bcfe (1) and current daily production of approximately 25 MMcfe/d (1) Proved reserves as estimated by a third-party engineering firm at December 31, 2007.

7. Appalachia Sale vs. Lamamco Acquisition • Current acquisition market for “pure” MLP assets allows Linn Energy to generate significant accretion above cash flow lost due to Appalachia sale

8. Inventory Classification Texas Panhandle Granite Wash HIGH Marcellus Shale Texas Panhandle Shallow Woodford Shale Mississippi Shelf Inventory Potential Verden California Mayfield Tuttle Naval Reserve Appalachia Osage Hominy LOW Concept Maturity HIGH

9. Overview of Linn Energy

10. Company Overview • Oil and gas development and acquisition company • Headquartered in Houston and publicly traded on Nasdaq (symbol: LINE) • Top 25 largest independent producer in the United States • Focus on mature producing basins for stable cash flows • Operate in Mid-Continent and California • Target new regions and bolt-on opportunities in existing core areas • Key statistics: • 1.7 Tcfe total proved reserves  Equity market cap $2.7 billion • ~7,200+ oil and gas wells  Total debt 1.5 billion • 4,100+ drilling locations Enterprise value $4.2 billion • 21 year reserve life index Note: Pro forma for pending Appalachia sale. Market data as of April 11, 2008 (LINE closing price of $23.32). Reserve data based on D&M reserve reports as of December 31, 2007 and acquisitions closed as of January 31, 2008.

11. U.S. Operations • Mid-Continent • 57% natural gas • 43% oil and NGLs • 87% of total reserves 4,078 engineered locations • Western • 94% crude oil • 13% of total reserves 91 engineered locations CA KS Division Office (Brea) OK Division Office (Oklahoma City) TX Corporate Headquarters (Houston) Note: Pro forma for pending Appalachia sale. Reserve data based on D&M reserve reports as of December 31, 2007 and acquisitions closed as of January 31, 2008.

12. Proved Reserves Distribution Reserves by Commodity Reserves by Category NGL 15% Proved Undeveloped 28% Oil 35% Gas 50% Proved Developed 72% 1.7 Tcfe of proved reserves 21 year reserve life index Note: Pro forma for pending Appalachia sale. Reserve data based on D&M reserve reports as of December 31, 2007 and acquisitions closed as of January 31, 2008.

13. Proven Acquisition Track Record Aggregate # of Gross Contract Price Year Acquisitions Wells Region ($ millions) (1) (2) 2003 4 498 Appalachia $ 52.0 2004 2 698 Appalachia 25.9 2005 3 718 Appalachia 124.5 2006 5 1,430 Mid-Continent, Appalachia and Western 451.7 2007 8 4,505 Mid-Continent, Appalachia and Western 2,678.9 2008 2 2,450 Mid-Continent and Appalachia 566.9 24 10,299 $ 3,899.9 Historical acquisition cost = $2.07 per Mcfe 2007 acquisition cost = $2.41 per Mcfe 2008 acquisition cost = $1.72 per Mcfe Note: Table includes all significant completed acquisitions. Per unit acquisition costs based on purchase of working interests only. Reserve data based on internal company estimates. (1) Gross wells do not include approximately 1,800 wells associated with royalty interest acquisitions. (2) Contract acquisition price is subject to post-closing adjustments.

14. A History of Performance and Growth Proved Reserve Volume (Bcfe) Reserves Per Unit (Mcfe) 51% CAGR 109% CAGR Average Daily Production (MMcfe/d) Total Net Acreage Undeveloped Developed 87% CAGR 151% CAGR (1) Pro forma for pending Appalachia sale. Reserve data based on D&M reserve reports as of December 31, 2007 and acquisitions closed as of January 31, 2008. (2) Pro forma for pending Appalachia sale. Based on mid-point of guidance estimates announced on February 28, 2008 and includes Appalachian production for only the first quarter of 2008 to match the Company’s recognition of Adjusted EBITDA for the fiscal year. (3) Pro forma for pending Appalachia sale. Reflects year-end 2007 acreage and includes acquisitions completed as of January 31, 2008.

15. A History of Performance and Growth Cumulative Acquisitions ($ millions) Adjusted EBITDA (1) ($ millions) Total $3.9 billion 161% CAGR Equity Raised ($ millions) Annualized Distribution per Unit Total $2.7 billion 58% Increase (1) Adjusted EBITDA is a Non-GAAP financial measure reconciled to its most directly comparable GAAP measure on page 51 of this presentation. (2) Mid-point of guidance estimates announced on February 28, 2008, adjusted for pending Appalachia sale.

16. 2008E Capital Program 2008E Capital Budget – $255 Million 2008E Estimated Wells – 294 Texas Panhandle Granite Wash $113 MM Texas Panhandle Granite Wash 57 Wells Texas Panhandle Shallow $49 MM Texas Panhandle Shallow 97 Wells 45% 19% 19% 33% 7% Appalachia $18 MM 1% California $3 MM 34% 14% Oklahoma & Other 99 Wells Appalachia 41 Wells 28% Oklahoma & Other $72 MM Note: Estimated capital budget adjusted for Appalachia sale.

17. Company Inventory 1,355 1.8 Tcfe Total Inventory • Opportunity sources • Development • Exploitation • Acquisition (asset & land) • Inventory quality • Location-specific • Risk-adjusted • Land-controlled Areas Resource Category 0.3 Tcfe 19% 0.7 Tcfe 35% 1.3 Tcfe 72% 0.5 Tcfe 28% 0.7 Tcfe 37% 903 0.1 Tcfe 9% 1,820 91 Engineered Locations 2008E Drilling Activity Engineered Locations Years of Inventory 4,169 253 16 years Note: Pro forma for pending Appalachia sale.

18. Low Risk Inventory For The Future Includes 4,169 drilling locations and 2.8-3.8 Tcfe of capital inventory Unrisked Resource Potential (Tcfe) Verden Woodford Shale Down spacing opportunities Mississippi Shelf TX Panhandle – Granite Wash TX Panhandle – Shallow Prospective 1-2 Tcfe Resource Potential (Bcfe) Engineered Locations Total Wells High Confidence Inventory 1.3 Tcfe TX Panhandle – Granite Wash 777 600 Oklahoma 1,083 440 TX Panhandle – Shallow 967 170 California 79 40 2,906 PUD Engineered Locations Reserves (Bcfe) Total Wells Oklahoma 737 209 TX Panhandle – Shallow 388 174 TX Panhandle – Granite Wash 126 77 California 12 32 PUD Development Upside 0.5 Tcfe 1,263 Proved Developed 1.2 Tcfe PDP / PDNP

19. Mid-Continent RegionOverview • Largest area of operations • 87% of total proved reserves • A top producer in the Mid-Continent • 57% natural gas, 43% oil and NGLs • 300+ employees • ~6,600+ oil and gas wells (70% operated) • Currently running 13 rigs • Acreage position • ~845,000 net acres • ~660,000 net developed acres • ~185,000 net undeveloped acres • Growth opportunities • Significant organic growth potential • Opportunities for bolt-on acquisitions Kansas Naval Reserve Unit Mississippi Shelf Panhandle – Granite Wash Oklahoma Osage Hominy Texas Panhandle – Shallow Mayfield Tuttle Carter Verden Existing LINE Fields Sho-Vel-Tum Note: Reserve data based on D&M reserve reports as of December 31, 2007 and acquisitions closed as of January 31, 2008.

20. Mid-Continent:Texas Panhandle Granite WashOverview HEMPHILL COUNTY ROBERTS COUNTY Lard Ranch • Production in eastern portion of Texas Panhandle • 4th most active operator behind Cimarex, Samson and Chesapeake • 40 active industry rigs in the play • Average depth 13,000 feet • Multiple stacked reservoirs • Repeatable drilling program • Currently running 5 operated rigs • Long life, low risk reserves • 83% gas, 17% oil and NGLs • 54% proved developed • ~330 wells • Significant organic growth potential • ~900 drilling locations • 16 years of drilling inventory • Acreage position • ~60,000 net acres • ~35,000 net developed acres • ~25,000 net undeveloped acres Twin Channel Mendota Ranch Buffalo Wallow 7th Step Frye Ranch LINE Producing Acreage Dyco LINE Non-Producing Acreage LINE Farm-Out Acreage WHEELER COUNTY Operated Rigs Non-Operated Rigs Stiles Ranch Note: Reserve data based on D&M reserve reports as of December 31, 2007.

21. Mid-Continent: Texas Panhandle ShallowOverview Hansford County • Shallow production in Panhandle Field of North Texas • 3rd largest operator behind Pioneer and ConocoPhillips • Ownership and control of ~900 miles of gathering pipelines • Average depth 3,200 feet • Long life, low risk reserves • Predictable, shallow decline rates • 37% gas, 63% oil and NGLs (53% proved developed) • Reserve life index of 30 years • Currently running 4 rigs • Significant organic growth potential • ~1,300+ drilling and behind pipe opportunities • 14 years of inventory • 1,200+ producing wells • Acreage position • ~112,000 net acres • ~112,000 net developed acres • Opportunities for bolt-on acquisitions • ~200 operators in area Sherman County Hutchinson County Moore County River Canadian Meredith Lake Carson County Potter County LINE Acreage Gas Prone Note: Reserve data based on D&M reserve reports as of December 31, 2007. Operator information based on Texas Railroad Commission data for May 2007. Oil Prone

22. Western Region (California)Overview • Brea-Olinda Field of Los Angeles Basin • Discovered in 1880 • Top 20 oil producer in California • Cumulative production of over 400 MMBoe • Long life, low risk reserves • 94% oil (over 85% proved developed) • Reserve life index of ~40 years • Low decline rates of less than 2% per year • ~600 oil & gas wells • Gas converted to electricity to power field, reducing operating expenses • Current field activity • Well reactivation program • 3 new wells • Acreage position • ~4,000 net acres • ~4,000 net developed acres Brea-Olinda Field Brea-Olinda Field Stearns 310 Tested 35 Bopd Tonner Stearns 101 Tested 65 Bopd Brea Canyon Area Tonner Area LINE Acreage Tonner Stearns 102 Tested 40 Bopd Oil Wells Currently Completed Locations Note: Reserve data based on D&M reserve reports as of December 31, 2007.

23. Financial Overview

24. Long-Term Natural Gas Hedges Upside Potential 2008 2008 2009 2009 2010 2010 2011 2011 2012 2012 • Natural gas fully hedged for 2008E • Puts provide upside on 15%-34% of hedged volume through 2012 $15.00 $15.00 Upside Potential Upside Potential Upside Potential Upside Potential $10.00 Floor Price $8.45 Hedged Price per MMBtu $8.48 $8.32 $8.14 $8.08 $7.99 $7.85 $7.73 $7.71 $7.65 $5.00 34% 18% 20% 15% 29% 82% 71% 66% 85% 80% $0.00 Fixed Price Swaps Puts (1) Percent of Hedged Volumes Hedged Volume (MMMBtu) Note: Shown prior to hedge cancellation in connection with pending Appalachia sale. (1) Includes puts which settle on Panhandle Eastern Pipeline Index to hedge basis differential associated with natural gas production in the Mid-Continent.

25. Long-Term Oil Hedges $114.25 $112.35 $112.25 $112.00 $100.00 Upside Potential Upside Potential Upside Potential Upside Potential Upside Potential $90.00 $90.00 $90.00 $90.00 Floor Price $80.00 5,000 4,000 3,000 2,000 1,000 0 $81.49 $79.65 $78.28 $78.07 Hedged Price (Bbl) $77.65 $77.73 $72.90 $72.13 $72.22 $70.56 $69.11 Percent of Hedged Volumes $60.00 41% 71% 44% 41% 17% 12% 48% 6% 50% 5% 54% 46% 59% 6% Hedged Volume (MBbls) $40.00 $20.00 2008 2009 2010 2011 2012 2013 Fixed Price Swaps Puts Collars • Oil and NGLs approximately 90% hedged for 2008E • Puts provide upside on 17%-50% of hedged volumes • Puts are used to hedge NGL production $120.00 2008 2009 2010 2011 2012 2013

26. Net Asset Value Summary PV-10 Analysis (1) Market Comparisons ($ in millions, except per unit data) Low High Proved value per Mcfe $2.00/Mcfe $3.00/Mcfe Proved reserves $3,400 $5,100 1.7 Tcfe Unproved value per Mcfe $1.00/Mcfe $1.25/Mcfe Low-risk unproved upside $1,300 $1,625 1.3 Tcfe Total Asset Value $4,700 $6,725 Less: Long-term debt $1,518 $1,518 Equity value $3,182 $5,207 Fully diluted units outstanding 115 115 NAV per Unit $27.67 $45.28 $3,900 $950 $4,850 $1,518 $3,332 115 $28.97 Note: Pro forma for pending Appalachia sale. (1) Economic analysis performed assuming pricing of $8.00/MMBtu and $80.00/Bbl flat.

27. Advantages of LINE’s LLC Structure • No incentive distribution rights to general partner • Investors share equally in all cash flows • Acquisitions are more accretive long-term without IDRs • Higher tax shield • Linn Energy’s tax shield was over 100% in 2006 and 2007 • 80% average for MLP group in 2006 • Fair governance – all unitholders vote • No general partner to control all votes • Management strongly aligned with unitholders

28. Goal = Maintain and Grow Distributions Accretive acquisitions Inventory of repeatable drilling opportunities Basin diversification Maintain and grow distributions Oil and gas diversification Active hedging

29. Key Investment Considerations • Strong acquisition track record • Completed approximately $3.9 billion of acquisitions • Increased cash distributions 58% since January 2006 IPO • Experienced management team • Senior management has an average of 20+ years of industry experience • Considerable experience running large cap oil and gas operations • Large inventory of organic growth projects • 4,100+ drilling locations create potential for significant organic growth • Significant development projects underway • Aggressive hedging program protects cash flow to pay distributions • Production over 95% hedged for 2008E • Substantial volumes hedged at attractive prices for five years • Attractive, tax-advantaged yield • Yield of over 11% ($2.52 / $23.32) • Distributions were 100% tax shielded for 2006 and 2007 Note: Market data as of April 11, 2008 (LINE closing price of $23.32).

31. Appendix

32. Reconciliation of Non-GAAP Measures • The Company defines Adjusted EBITDA as net income (loss) plus: • Net operating cash flow from acquisitions, effective date through closing date; • Interest expense, net of amounts capitalized; • Depreciation, depletion and amortization; • Write-off of deferred financing fees and other; • (Gain) loss on sale of assets; • Accretion of asset retirement obligation; • Unrealized (gain) loss on derivatives; • Unit-based compensation and unit warrant expense; • Data license expenses; • IPO cash bonuses; and • Income tax (benefit) provision. • Adjusted EBITDA is a significant performance metric used by Company management to indicate (prior to the establishment of any reserves by its Board of Directors) the cash distributions the Company expects to pay unitholders. Specifically, this financial measure indicates to investors whether or not the Company is generating cash flow at a level that can sustain or support an increase in its quarterly distribution rates. Adjusted EBITDA is also a quantitative metric used throughout the investment community with respect to publicly-traded partnerships and limited liability companies. • The Company defines Adjusted Net Income (Loss) as net income (loss) plus: • Unrealized (gain) loss on derivatives

33. Adjusted EBITDA • The following presents a reconciliation of consolidated net income (loss) to Adjusted EBITDA:

34. Adjusted Net Income • The following presents a reconciliation of consolidated net income (loss) to Adjusted Net Income (Loss):