RESILIENT

JPMorgan High Yield Conference

March 3, 2010

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.

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

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.

KS

Corporate

Headquarters

(Houston)

Division Office(Brea)

CA

TX

Division Office

(Oklahoma City)California

189 Bcfe proved reserves

11% of total reserves

93% liquids

OK

TX PanhandleGranite Wash

TX PanhandleShallow

Mid-Continent

1.5 Tcfe proved reserves

83% of total reserves

51% natural gas

NM

LINN Operations

Recent Acquisition Area

Oklahoma

Permian Basin

117 Bcfe proved reserves

6% of total reserves

86% liquids

Oil

30%

2010E Production

NGL

18%

Gas

52%

Reserves by Category

22 year reserve life index (2)

Reserves by Commodity

NGL

19%

1.8 Tcfe of proved reserves

Oil

37%

220 MMcfe/d (2)

Proved

Developed72%

Proved

Undeveloped28%

Gas

44%

Top 25 largest domestic independent oil & gas

company and largest public E&P MLP/LLC (1)

Founded in 2003, IPO in 2006 (Nasdaq: LINE)

Equity market cap $3.5 billion

Total net debt $1.7 billion

Enterprise value $5.2 billion

Large, long-life diversified reserve base

1.8 Tcfe total proved reserves

72% proved developed

56% oil and NGL’s / 44% gas

22 year reserve-life index

Large inventory of lower risk development

opportunities

Over 4,200 engineered drilling locations;

multiple years at current drilling pace

PUD 0.5 Tcfe

High-confidence inventory 1.3 Tcfe

Total low-risk inventory 1.8 Tcfe

Total resource potential of 4.1-5.1 Tcfe

5

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

LINN’s Acquisition Strategy

6

Attractive Acquisition Margins

(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.

Despite rising acquisition costs, acquisition margins remain strong

$4.65 $4.82

$6.42

$9.98

$7.92

$14.34 $13.92

$14.44

$0.83 $0.68

$2.10 $1.61

$2.41 $1.58 $1.91 $2.11

$4.32

$8.37 $5.51

$12.76 $12.02

$12.33

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

2003 2004 2005 2006 2007 2008 2009 2010

NYMEX Five Year Forward Strip ($ per Mcfe) (1)

LINN Weighted Average Acquisition Cost ($ per Mcfe)

$3.82 $4.14

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.

8

0 7,822’

FEET

DYCO

STILES RANCH

FRYE

RANCH

Wheeler County

IP: 21.0 MMcfe/d

IP: 14.9 MMcfe/d

IP: 25.0 MMcfe/d

Hemphill County

IP: 22.3 MMcfe/d

IP: 23.8 MMcfe/d

IP: 11.8 MMcfe/d

Proposed Location

Currently Drilling

Waiting on Completion

Producing Well

LINN Operated

Non- Operated

Industry Activity

LINN Activity

Granite Wash – Horizontal Activity

IP: 21.0 MMcfe/d

LINN Operated

(spud March 2010)

Tom Puryear 5-28H

(Non-operated)

IP: 17.0 MMcfe/d

IP: 12.0 MMcef/d

IP: 21.0 MMcfe/d

LINN Acreage Gross Net

Greater Stiles Ranch ~23,000 ~12,000

Industry Horizontal Activity

Rigs Operating 14

Wells Drilled 38

Waiting on Completion 9

Note: Based on public and available industry data.

IP: 18.6 MMcfe/d IP: 20.0 MMcfe/d

(Greater Stiles Ranch)

9

Granite Wash – Trend Area

LINN Acreage Gross Net Horizontal

Locations

Texas G.W. Area ~68,000 ~48,000 100+

Oklahoma G.W. Area ~100,000 ~25,000 ?

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.

Buffalo Wallow - 2 Step

7th Step - Mendota

Colony Granite WashChesapeake

Penn Virginia

Mayfield

ROBERTSHEMPHILL

GRAY

WHEELER

RODGER MILLS

BECKHAM

ELLIS

WASHITA

CUSTER

CADDO

BLAINE

DEWEY

` LINN Acreage

TEXAS

OKLAHOMA

Greater Stiles RanchDevon, Forest

Newfield, Questar

TX

OK

Granite Wash trend also extends into Oklahoma

LINN’s potential from its Oklahoma acreage is not included in the estimated 100 locations

10

Granite Wash / Atoka Wash Stratigraphy

Multiple laterals per location significantly increase LINN’s horizontal inventory

Carr

Britt

“A”

“A”

thru “C"

PRODUCING

ZONES

“B”

“C”

“D”

“E”

“F”

G

R

A

N

I

T

E

W

A

S

H

WAS

H

A

TOK

A

LATERAL BOREHOLES

MIDDLE

LOWER

UPPER

LOWER

UPPER

Lwr “C”

thru “E"

12,000’

15,000’

3,000’

Interval

Financial Overview

12

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

Financial Strength

(1) Reserve data as of December 31, 2009. Pro forma for $154.5 million acquisition.

13

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.

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

Credit Facility

9 7/8% Senior Notes due 2018

Total Debt

Operating Metrics

Adjusted EBITDA (1) ($ millions)

Proved Reserves (Bcfe)

Proved Developed Reserves (Bcfe)

Credit Metrics

Total Net Debt / Proved Reserves ($/Mcfe)

Total Net Debt / Proved Developed Reserves ($/Mcfe)

Total Net Debt / Adjusted EBITDA (1)

Adjusted EBITDA / Interest Expense (1) (2)

Long-Term Debt

11 3/4% Senior Notes due 2017

$5

251

$1,704

$0.95

$1.33

3.0x

4.1x

$1,215

238

1,785

$570

1,282

14

$90.00 $90.00 $100.00 $100.00

$90.00 $90.00

$110.00 $75.00

0

1,000

2,000

3,000

4,000

5,000

2010 2011 2012 2013

Vo

lum

e (

MB

bls

)

50%48%

$99.68 $82.50

Puts provide upside on hedged volumes Puts and collars provide upside on

hedged volumes

Gas Positions Oil Positions

Current Hedge Position

$9.50

$8.90

$8.84

$8.11

0.0

8.0

16.0

24.0

32.0

40.0

48.0

56.0

64.0

2010 2011

Vo

lum

e (

Bc

f)

Swaps Puts (1)

31%

39%

$8.66

$9.25

Percent Puts (2)

Approximately 100% hedged through 2011 provides cash flow stability

(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.

Percent Puts (2)Swaps (3) Collars (4) Puts (2)

15

100%106%

43%

39%

30%

58%

0%

20%

40%

60%

80%

100%

120%

FY 2010E FY 2011E

LINE Swaps

% P

rod

uc

tio

n H

ed

ge

d

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.

LINE PutsLINE Collars

LINN Production Hedged vs. Peers

Hedged much more than peers while still preserving upside potential

Average Production Hedged Q4 09 (1)

16

-60%

-40%

-20%

0%

20%

40%

60%

80%

100%

120%

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

LINN Historical Return

Note: Market data as of February 25, 2010 (LINE closing price of $26.62). Source: Bloomberg.

LINN Total Return and Stock Price Appreciation (LINE IPO – 2/25/10)

26.76%

-6.30%

89.53%

22.48%

17

E&P Peer Group Yield

Note: As of February 26, 2010

LINN’s bonds still represent good relative value

6.92%7.01%

7.88%8.17%8.21%8.27%

8.49%8.58%8.60%8.68%8.80%

8.93%9.00%

0.00%

1.00%

2.00%

3.00%

4.00%

5.00%

6.00%

7.00%

8.00%

9.00%

10.00%

Quicksilver

(KWK)

(B3/B-)

Swift

(SFY)

(B3/BB-)

Encore

(EAC)

(B1/B)

Berry

(BRY)

(B3/B)

SandRidge

(SD)

(B3/B+)

Atlas

(ATN)

(B3/B+)

Whiting

(WLL)

(B1/BB)

9.875%

(LINE)

(B3/B-)

Petrohawk

(HK)

(B3/B)

Comstock

(CRK)

(B2/B)

Mariner

(ME)

(B3/B+)

11.75%

(LINE)

(B3/B-)

Average

LINN Energy’s mission is to acquire, develop

and maximize cash flow from a growing portfolio of

long-life oil and natural gas assets.

Appendix

20

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.

Historical Financial StatementsReconciliation of Non-GAAP Measures

21

The following presents a reconciliation of income (loss) from continuing operations

to adjusted EBITDA:

Historical Financial StatementsAdjusted EBITDA

Three Months EndedDecember 31,

Year EndedDecember 31,

2009 2008 2009 2008

(in thousands)

Income (loss) from continuing operations $ (65,965) $ 888,054 $ (295,841) $ 825,657Plus:

Net operating cash flow from acquisitions and divestitures, effective date through closing date

(1)115 (872) 3,708 3,436

Interest expense, cash 23,195 16,782 74,185 81,704Interest expense, noncash 3,810 6,536 18,516 12,813Depreciation, depletion and amortization 49,848 46,834 201,782 194,093Impairment of goodwill and long -lived assets — 50,505 — 50,505Write-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 interest rate

derivatives (10,261) 44,634 (16,588) 50,638Realized loss on interest rate derivatives

(2)11,252 4,557 42,881 16,036

Realized (gain) loss on canceled derivatives — — (48,977) 81,358Unit-based compensation expenses 3,616 3,301 15,089 14,699Exploration costs 2,544 4,654 7,169 7,603Income tax (benefit) expense (4,600) 1,665 (4,221) 2,712

Adjusted EBITDA from continuing operations $ 142,445 $ 83,022 $ 566,235 $ 514,487

Includes net operating cash flow from acquisitions and divestitures.

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.

(1)

(2)

22

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 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 losses, impairment of goodwill and long-lived assets and (gain) loss on sale of assets, net.

The following presents a reconciliation of income (loss) from continuing operations to adjusted net income:

Three Months Ended December 31,

Year Ended 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

The following presents a reconciliation of income (loss) from continuing operations

to adjusted net income:

Historical Financial StatementsAdjusted Net Income

23

Reserve Replacement / F&D CalculationsReconciliation 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:

Reserve replacement cost per Mcfe (1)

$ 1.71 $ 1.53 Reserve replacement ratio

(2) 189% 756%

Finding and development cost from the drillbit per Mcfe (3)

$ 1.59 $ 1.44 Drillbit reserve replacement ratio

(4) 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)

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.