1. JPMorgan High Yield Conference
March 3, 2010
RESILIENT

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 2009 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 February 25, 2010.
2

3. LINN Energy’s mission is to acquire, develop
and maximize cash flow from a growing portfolio of
long-life oil and natural gas assets.

4. LINN Overview
Mid-Continent
 Top 25 largest domestic independent oil & gas  1.5 Tcfe proved reserves
 83% of total reserves
company and largest public E&P MLP/LLC (1)  51% natural gas
 Founded in 2003, IPO in 2006 (Nasdaq: LINE)
 Equity market cap $3.5 billion CA TX Panhandle
Granite Wash KS
Total net debt $1.7 billion Division Oklahoma
Office
Enterprise value $5.2 billion (Brea)
TX Panhandle
Shallow OK
 Large, long-life diversified reserve base
Division
NM Office
(Oklahoma City)
California
 1.8 Tcfe total proved reserves
 189 Bcfe proved reserves Corporate
 72% proved developed  11% of total reserves TX Headquarters
(Houston)
 56% oil and NGL’s / 44% gas  93% liquids
 22 year reserve-life index Permian Basin LINN Operations
 117 Bcfe proved reserves Recent Acquisition Area
 Large inventory of lower risk development  6% of total reserves
 86% liquids
opportunities
2010E Production Reserves by Commodity Reserves by Category
 Over 4,200 engineered drilling locations;
NGL NGL Proved
multiple years at current drilling pace 18% 19% Undeveloped
28%
 PUD 0.5 Tcfe
 High-confidence inventory 1.3 Tcfe Oil Gas Oil Gas
30% 52% 37% 44%
Total low-risk inventory 1.8 Tcfe
 Total resource potential of 4.1-5.1 Tcfe Proved
Developed
72%
220 MMcfe/d (2) 1.8 Tcfe of proved reserves 22 year reserve life index (2)
Note: Market data as of February 25, 2010 (LINE closing price of $26.62). All operational and reserve data as of December 31, 2009. Pro forma for $154.5 million acquisition.
(1) Based on proved reserves.
(2) Based on mid-point of guidance estimates announced on February 25, 2010.
4

5. LINN’s Acquisition Strategy
 Mature U.S. oil and natural gas basins provide significant opportunity for
future growth and consolidation
LINN’s strategy is to :
 Acquire mature oil and natural gas properties with the appropriate attributes
Asset Attributes
• Stable, long-life production
• High percentage of PDP
• Shallow decline
• Long reserve-life index
• Low-risk, low-cost repeatable drilling
 Efficiently operate and develop acquired properties
 Reduce commodity price and interest rate risk through hedging
 Return cash flow through the form of a distribution payment to unitholders
5

6. Attractive Acquisition Margins
 Despite rising acquisition costs, acquisition margins remain strong
$16.00
NYMEX Five Year Forward Strip ($ per Mcfe) (1) $14.44
$14.34
LINN Weighted Average Acquisition Cost ($ per Mcfe) $13.92
$14.00
$12.00
$9.98
$10.00
$7.92
$12.02 $12.33
$8.00 $12.76
$6.42
$6.00 $8.37
$4.65 $4.82 $5.51
$4.32
$4.00
$3.82 $4.14
$2.00 $2.41
$2.10 $1.91 $2.11
$1.61 $1.58
$0.83 $0.68
$0.00
2003 2004 2005 2006 2007 2008 2009 2010
(1) Represents weighted average blended five year forward oil and gas strip prices as of the closing date of acquisitions completed during the year. Source: Bloomberg.
6

7. Year End 2009 Highlights
 Total unitholder return of more than 100 percent
 Record adjusted EBITDA of $566 million
 Record adjusted net income of $1.73 per unit for 2009
 Attractive finding and development cost of $1.59 per Mcfe and
112 percent of production replaced through the drillbit (1)
 Increase in proved reserves of 3 percent to 1,712 Bcfe
 100% hedged on an equivalent basis through 2011, 65% of oil
hedged in 2012 and 2013
(1) Excluding price revisions.
7

8. Granite Wash – Horizontal Activity
(Greater Stiles Ranch)
Hemphill County Industry Horizontal Activity
IP: 11.8 MMcfe/d
Rigs Operating 14
IP: 14.9 MMcfe/d
IP: 17.0 MMcfe/d Wells Drilled 38
IP: 21.0 MMcfe/d
DYCO Waiting on Completion 9
LINN Operated
(spud March 2010) LINN Acreage Gross Net
IP: 22.3 MMcfe/d IP: 21.0 MMcfe/d Greater Stiles Ranch ~23,000 ~12,000
IP: 23.8 MMcfe/d
IP: 12.0 MMcef/d
LINN Activity
FRYE IP: 25.0 MMcfe/d LINN Operated
RANCH Non- Operated
Industry Activity
IP: 18.6 MMcfe/d IP: 20.0 MMcfe/d Currently Drilling
STILES Waiting on Completion
Proposed Location
RANCH
IP: 21.0 MMcfe/d Producing Well
Tom Puryear 5-28H
(Non-operated)
FEET Wheeler County
0 7,822’
Note: Based on public and available industry data.
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9. Granite Wash – Trend Area
 Granite Wash trend also extends into Oklahoma
 LINN’s potential from its Oklahoma acreage is not included in the estimated 100 locations
Buffalo Wallow - 2 Step ELLIS DEWEY
7th Step - Mendota Greater Stiles Ranch
Devon, Forest Colony Granite Wash
Newfield, Questar Chesapeake
ROBERTS
HEMPHILL Penn Virginia
RODGER MILLS
OKLAHOMA BLAINE
CUSTER
GRAY
WHEELER
BECKHAM
TEXAS WASHITA
Mayfield CADDO
` LINN Acreage
Horizontal
LINN Acreage Gross Net OK
Locations
Texas G.W. Area ~68,000 ~48,000 100+
Oklahoma G.W. Area ~100,000 ~25,000 ? TX
Total ~168,000 ~73,000 100+
Note: Acreage totals reflect only what acreage is shown in the gray area on the Granite Wash regional map.
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10. Granite Wash / Atoka Wash Stratigraphy
 Multiple laterals per location significantly increase LINN’s horizontal inventory
PRODUCING
LATERAL BOREHOLES ZONES
12,000’
Carr
G
UPPER R Britt
A
MIDDLE N “A”
I
T “B”
E
“C”
3,000’
W “D” Interval
A
LOWER S “E”
H
“F”
UPPER A “A”
T thru
O W “C"
K A
Lwr “C”
LOWER A S
H thru “E"
15,000’
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11. Financial Overview

12. Financial Strength
 Low risk asset base (1)
 1.8 Tcfe of proved reserves
 22 year reserve life
 72% proved developed
 Financial flexibility
 Credit facility with $1.64 billion borrowing base (August 2012)
 In 2009, 2 public equity offerings and bond offering for gross proceeds of $542 million
 Borrowing capacity, including available cash, of ~$427 million at January 31, 2010
 High levels of hedging
 ~100% of current production hedged through 2011, 65% of oil hedged in 2012 and 2013
 ~100% of Mid-Continent basis hedged through 2011
 ~100% of floating interest rate expense hedged through 2013
(1) Reserve data as of December 31, 2009. Pro forma for $154.5 million acquisition.
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13. Financial Flexibility
 LINN is well positioned for future acquisitions and growth opportunities
Credit Profile – 1/31/10
($ in millions, unless otherwise indicated)
Cash and Cash Equivalents $5
Long-Term Debt
Credit Facility $1,215
9 7/8% Senior Notes due 2018 251
11 3/4% Senior Notes due 2017 238
Total Debt $1,704
Operating Metrics
Adjusted EBITDA (1) ($ millions) $570
Proved Reserves (Bcfe) 1,785
Proved Developed Reserves (Bcfe) 1,282
Credit Metrics
Total Net Debt / Proved Reserves ($/Mcfe) $0.95
Total Net Debt / Proved Developed Reserves ($/Mcfe) $1.33
Total Net Debt / Adjusted EBITDA (1) 3.0x
Adjusted EBITDA / Interest Expense (1) (2) 4.1x
Note: Reserve data as of December 31, 2009. Reserves pro forma for $154.5 million acquisition.
(1) Based on mid-point of guidance estimates announced on February 25, 2010.
(2) Includes the effects of the Company’s interest rate hedges.
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14. Current Hedge Position
 Approximately 100% hedged through 2011 provides cash flow stability
Gas Positions Oil Positions
 Puts provide upside on hedged volumes  Puts and collars provide upside on
hedged volumes
64.0
$8.66 5,000 $99.68 $82.50
56.0 $9.25
48.0 $8.11 4,000
$110.00 $75.00
Volume (MBbls)
$8.84
40.0
Volume (Bcf)
31% 48% 50%
3,000
32.0 39%
$90.00 $90.00
24.0 2,000
$8.90
16.0 $9.50 $100.00 $100.00
$90.00 $90.00
1,000
8.0
0.0 0
2010 2011 2010 2011 2012 2013
Swaps Puts (1) Percent Puts (2) Swaps (3) Collars (4) Puts (2) Percent Puts (2)
(1) Includes puts which settle on the Panhandle Eastern Pipeline Index (PEPL) to hedge basis differential associated with gas production in the Mid-Continent.
(2) Calculated as percentage of hedged volume in the form of puts.
(3) As presented in the table above, the Company has outstanding fixed price oil swaps on 7,250 Bbls per day at a price of $100.00 per Bbl for the years ending December 31, 2012, and
December 31, 2013. The Company has derivative contracts that extend the swaps for each of the years ending December 31, 2014, December 31, 2015, and December 31, 2016, if
the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without
respect to the other years.
(4) Includes collars with floor / ceiling prices of $90.00 / $112.00 and $90.00 / $112.25 on 250 MBbls and 276 MBbls of oil for FY 2010-FY 2011, respectively.
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15. LINN Production Hedged vs. Peers
 Hedged much more than peers while still preserving upside potential
120%
106%
100%
100%
% Production Hedged
39%
80% 43%
60%
58%
40%
30%
20%
0%
FY 2010E FY 2011E
LINE Swaps LINE Collars LINE Puts
Average Production Hedged Q4 09 (1)
Note: 2010E production held flat through 2011E. LINN’s 2010E production based on mid-point of 2010E guidance announced on February 25, 2010. Source: Company filings and
press releases. E&P Peer Group includes: Berry Petroleum, Comstock Resources, Encore Acquisition, Mariner Energy, Petrohawk, Quicksilver Resources, SandRidge Energy,
Swift Energy and Whiting Petroleum.
(1) 2010E peer group production per Wall Street research. Hedge data based on publicly available data.
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16. LINN Historical Return
LINN Total Return and Stock Price Appreciation (LINE IPO – 2/25/10)
120%
100%
89.53%
80%
60%
40%
26.76%
20% 22.48%
0%
-6.30%
-20%
-40%
-60%
1/13/06 7/20/06 1/24/07 7/31/07 2/4/08 8/10/08 2/14/09 8/21/09 2/25/10
LINE Total Return LINE Price Appreciation S&P Mid-Cap E&P Index S&P 500 Index
Note: Market data as of February 25, 2010 (LINE closing price of $26.62). Source: Bloomberg.
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17. E&P Peer Group Yield
 LINN’s bonds still represent good relative value
10.00%
9.00% 8.93%
9.00% 8.80%
8.68% 8.60% 8.58% 8.49%
8.27% 8.21% 8.17%
8.00% 7.88%
7.01% 6.92%
7.00%
6.00%
5.00%
4.00%
3.00%
2.00%
1.00%
0.00%
Atlas Mariner SandRidge 11.75% 9.875% Petrohawk Quicksilver Berry Average Swift Encore Comstock Whiting
(ATN) (ME) (SD) (LINE) (LINE) (HK) (KWK) (BRY) (SFY) (EAC) (CRK) (WLL)
(B3/B+) (B3/B+) (B3/B+) (B3/B-) (B3/B-) (B3/B) (B3/B-) (B3/B) (B3/BB-) (B1/B) (B2/B) (B1/BB)
Note: As of February 26, 2010
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18. LINN Energy’s mission is to acquire, develop
and maximize cash flow from a growing portfolio of
long-life oil and natural gas assets.

19. Appendix

20. Historical Financial Statements
Reconciliation of Non-GAAP Measures
 The Company defines adjusted EBITDA as income (loss) from continuing
operations plus the following adjustments:
 Net operating cash flow from acquisitions and divestitures, effective date through closing date;
 Interest expense;
 Depreciation, depletion and amortization;
 Impairment of goodwill and long-lived assets;
 Write-off of deferred financing fees and other;
 (Gain) loss on sale of assets, net;
 Unrealized (gain) loss on commodity derivatives;
 Unrealized (gain) loss on interest rate derivatives;
 Realized (gain) loss on interest rate derivatives;
 Realized (gain) loss on canceled derivatives;
 Unit-based compensation expenses;
 Exploration costs; and
 Income tax (benefit) expense.
 Adjusted EBITDA is a measure 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. Adjusted EBITDA is also a quantitative measure
used throughout the investment community with respect to publicly-traded partnerships
and limited liability companies.
 Adjusted net income is a performance measure used by Company management to
evaluate its operational performance from oil and natural gas properties, prior to derivative
gains and losses, impairment of goodwill and long-lived assets and (gain) loss on sale of
assets, net.
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21. Historical Financial Statements
Adjusted EBITDA
 The following presents a reconciliation of income (loss) from continuing operations
to adjusted EBITDA:
Three Months Ended Year Ended
December 31, December 31,
2009 2008 2009 2008
(in thousands)
Income (loss) from continuing operations $ (65,965) $ 888,054 $ (295,841) $ 825,657
Plus:
Net operating cash flow from acquisitions and
divestitures, effective date through closing
(1)
date 115 (872) 3,708 3,436
Interest expense, cash 23,195 16,782 74,185 81,704
Interest expense, noncash 3,810 6,536 18,516 12,813
Depreciation, depletion and amortization 49,848 46,834 201,782 194,093
Impairment of goodwill and long -lived assets — 50,505 — 50,505
Write-off of deferred financing fees and other — — 204 6,728
(Gain) loss on sale of assets, net 239 (98,763) (23,051) (98,763)
Unrealized (gain) loss on commodity
derivatives 128,652 (884,865) 591,379 (734,732)
Unrealized (gain) loss on intere st rate
derivatives (10,261) 44,634 (16,588) 50,638
(2)
Realized loss on interest rate derivatives 11,252 4,557 42,881 16,036
Realized (gain) loss on canceled derivatives — — (48,977) 81,358
Unit-based compensation expenses 3,616 3,301 15,089 14,699
Exploration costs 2,544 4,654 7,169 7,603
Income tax (benefit) expense (4,600) 1,665 (4,221) 2,712
Adjusted EBITDA from continuing operations $ 142,445 $ 83,022 $ 566,235 $ 514,487
(1) Includes net operating cash flow from acquisitions and divestitures.
(2) During 2009, the Company revised its definition of adjusted EBITDA to include realized (gains) losses on interest rate derivatives in order to match the related interest expense.
Amounts reported in adjusted EBITDA for all prior periods have been reclassified to conform to current period presentation. This reclassification had no effect on the Company’s
reported net income.
21

22. Historical Financial Statements
Adjusted net income (a non-GAAP financial measure), as defined by the Company, may not be comparable to
similarly titled measures used by other companies. Therefore, adjusted net income should be considered in
Adjusted Net Income
conjunction with net income from continuing operations and other performance measures prepared in accordance
with GAAP. Adjusted net income should not be considered in isolation or as a substitute for GAAP measures, such
as net income or any other GAAP measure of liquidity or financial performance. Adjusted net income is a
performance measure used by management to evaluate the Company’s operational performance from oil and natural
gas properties, prior to derivative gains and loss es, impairment of goodwill and long-lived assets and (gain) loss on
 The following net.
sale of assets, presents a reconciliation of income (loss) from continuing operations
to adjusted net income:
The following presents a reconciliation of income (loss) from continuing operations to adjusted net income:
Three Months Ended December Year Ended
31, December 31,
2009 2008 2009 2008
(in thousands, except per unit amounts)
Income (loss) from continuing operations $ (65,965) $ 888,054 $ (295,841) $ 825,657
Plus:
Unrealized (gain) loss on commodity derivatives 128,652 (884,865) 591,379 (734,732)
Unrealized (gain) loss on interest rate derivatives (10,261) 44,634 (16,588) 50,638
Realized (gain) loss on canceled derivatives — — (48,977) 81,358
Impairment of goodwill and long-lived assets — 50,505 — 50,505
(Gain) loss on sale of assets, net 239 (98,763) (23,051) (98,763)
Adjusted net income from continuing operations $ 52,665 $ (435) $ 206,922 $ 174,663
Income (loss) from continuing operations per
unit – basic $ (0.52) $ 7.72 $ (2.48) $ 7.18
Plus, per unit:
Unrealized (gain) loss on commodity derivatives 1.01 (7.69) 4.95 (6.39)
Unrealized (gain) loss on interest rate derivatives (0.08) 0.39 (0.14) 0.44
Realized (gain) loss on canceled derivatives — — (0.41) 0.71
Impairment of goodwill and long-lived assets — 0.44 — 0.44
(Gain) loss on sale of assets, net — (0.86) (0.19) (0.86)
Adjusted net income from continuing operations per
unit – basic $ 0.41 $ — $ 1.73 $ 1.52
22

23. Reserve Replacement / F&D Calculations
Reconciliation of Non-GAAP Measures
Year Ended December 31,
2009 2008
Costs incurred – continuing operations (in thousands):
Costs incurred in oil and natural gas property acquisition, exploration
and development $ 258,105 $ 900,256
Less:
Asset retirement obligation costs (371) (680)
Property acquisition costs (115,929) (584,630)
Oil and natural gas capital costs expended, excluding acquisitions $ 141,805 $ 314,946
Reserve data – continuing operations (MMcfe):
Purchase of minerals in place 61,684 368,136
Extensions, discoveries and other additions 50,416 228,083
Add:
Revisions of previous estimates – workover activities and other 38,665 (9,571)
Annual additions, excluding price-related revisions 150,765 586,648
Less:
Purchase of minerals in place (61,684) (368,136)
Annual additions, excluding price-related revisions and acquisitions 89,081 218,512
Annual production – continuing operations (MMcfe) 79,580 77,548
Reserve replacement metrics – continuing operations:
(1)
Reserve replacement cost per Mcfe $ 1.71 $ 1.53
(2)
Reserve replacement ratio 189% 756%
(3)
Finding and development cost from the drillbit per Mcfe $ 1.59 $ 1.44
(4)
Drillbit reserve replacement ratio 112% 282%
(1) (Oil and natural gas capital costs expended) divided by (Annual additions, excluding price-related revisions)
(2) (Annual additions, excluding price-related revisions) divided by (Annual production)
(3) (Oil and natural gas capital costs expended, excluding acquisitions) divided by (Annual additions, excluding price-related revisions and acquisitions)
(4) (Annual additions, excluding price-related revisions and acquisitions) divided by (Annual production)
23

24. Cautionary Note to U.S. Investors — The United States Securities and Exchange Commission (―SEC‖) permits oil and gas companies, in their
filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusi ve formation tests to be
economically and legally producible under existing economic and operating conditions. Any reserve estimate s provided in this presentation that
are not specifically designated as being estimates of proved reserves may include not o nly proved reserves, but also other categories of
reserves that the SEC's guidelines strictly prohibit the Company from including in filings with the SEC. Investors are urged to consider closely
the disclosure in the Company’s Annual Report filed on Form 10-K for fiscal year ended December 31, 2009, available from the Company at 600
Travis, Suite 5100, Houston, Texas 77002 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330
or from the SEC's website at www.sec.gov.
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