Linn Energy - EnerCom Oil & Gas Conference

EnerCom Oil & Gas Conference Denver, CO

Forward-Looking Statements

and Risk Factors

Statements made in these presentation slides and 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, potential for reserves and drilling, completion of current and future

acquisitions, future distributions, future growth, benefits of acquisitions, future

competitive position 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 and Senior Notes, access to capital markets, availability of

sufficient cash flow to pay distributions and execute our business plan, prices and

demand for natural 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, regulation, availability of connections and

equipment 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 2011 Annual Report on Form 10-K and any other

public filings. Linn Energy undertakes no obligation to publicly update any forward-

looking statements, whether as a result of new information or future events. The

market data in this presentation has been prepared as of July 27, 2012, except

otherwise noted.

Corporate

Headquarters

(Houston)

NM

TX

KS IL

LA

MI

ND

OK

CA

WY

4

East Texas

Salt Creek Field

LINN Operations

Recent Acquisitions /

Joint Ventures

Note: Market data as of July 27, 2012 (LINE closing price of $39.15). All operational and reserve data as of

December 31, 2011, pro forma for recently closed 2012 acquisitions and joint venture (“JV”). Estimates of

proved reserves for recently closed 2012 acquisitions and JV were calculated as of the effective date of

the acquisitions using forward strip oil and natural gas prices, which differ from estimates calculated in

accordance with SEC rules and regulations. Estimates of proved reserves for recently closed 2012

acquisitions and JV based solely on data provided by seller. Source: Bloomberg.

(1) Well count does not include ~2,500 royalty interest wells.

(2) Average working interest of ~7%.

8th largest public MLP/LLC and 8th largest

domestic independent oil & natural gas company

IPO in 2006 (NASDAQ: LINE)

Equity market cap

Total net debt

Enterprise value

Large, long-life diversified reserve base

~5.1 Tcfe total proved reserves

64% proved developed

45% oil and NGLs / 55% natural gas

~18 year reserve-life index

>15,500 gross productive oil and natural gas wells(1)

Large inventory of low risk and liquids-rich

development opportunities

Jonah Field – ~650 locations

Granite Wash – ~600 horizontal locations

Wolfberry – ~400 locations

Bakken – ~800 horizontal locations(2)

Cleveland – ~165 horizontal locations

Kansas Hugoton – ~800 locations

Salt Creek Field – CO2 flood

$7.8 billion

$6.7 billion

$14.5 billion

LINN Overview

Hugoton Field

Jonah Field

Growth Through Accretive Acquisitions

Value of Acquisitions Per Year (1)

5

~$10 billion in acquisitions completed since the Company’s inception

Includes 54 separate transactions(1)

(1) Includes 15 acquisitions comprising the Appalachian Basin properties sold in July 2008.

(2) Based on contract price for recently closed acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV.

(2)

$452

$2,627

$601

$1,351

$1,479

$2,800

$52 $78 $202

$654

$3,281

$3,882 $4,000

$5,356

$6,835

$9,635

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012TD

($'s

in

mil

lio

ns)

Cumulative Acquisitions Acquisitions Completed In Year

$118

$1,351 $1,479

$2,800

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

2009 2010 2011 2012TD

($'s

in

mil

lio

ns)

Continued Success in Acquisition Activity

Record amount of

negotiations in 2010

− Screened 189 opportunities

− Bid 41 for ~$10.1 billion

− Closed 13 for ~$1.4 billion

Record amount of

transactions closed in 2011




(1) Based on total consideration.


(3) As of August 3, 2012.

(1) (1) (2)

Total ~$5.7 Billion Since 2009

Historical Acquisitions and Joint Venture

(1)

6

Record amount of

transactional value YTD(3)




MLP and Independent E&P Rankings

Note: Market data as of July 27, 2012 (LINE closing price of $39.15).

Source: Bloomberg.

LINN is quickly becoming one of the largest MLP and independent E&P companies

− 8th largest public MLP/LLC

− 8th largest domestic independent oil & natural gas company

7

Rank Master Limited Partnership Enterprise Value ($MM) Rank Independent E&Ps Enterprise Value ($MM)

1. Enterprise Products Partners $62,104 1. Occidental Petroleum Corp. $67,761

2. Kinder Morgan Energy Partners $41,005 2. Anadarko Petroleum Corp. $48,988

3. Energy Transfer Equity $37,421 3. Apache Corp. $43,080

4. Williams Partners $24,060 4. EOG Resources Inc. $31,948

5. Energy Transfer Partners $20,964 5. Chesapeake Energy Corp. $30,296

6. Plains All American Pipeline $20,952 6. Devon Energy Corporation $27,540

7. ONEOK Partners $15,826 7. Noble Energy Inc. $19,219

8. LINN Energy LLC $14,534 8. LINN Energy LLC $14,534

9. Enbridge Energy Partners $13,680 9. Continental Resources Inc. $13,988

10. El Paso Pipeline Partners $11,869 10. Pioneer Natural Resources Co. $13,826

11. Magellan Midstream Partners $10,829 11. Southwestern Energy Co. $12,989

12. Buckeye Partners $7,320 12. Range Resources Corp. $12,810

13. Markwest Energy Partners $7,294 13. Concho Resources Inc. $11,339

14. Cheniere Energy Partners $6,425 14. EQT Corp. $10,747

15. Nustar Energy LP $6,267 15. Cabot Oil & Gas Corp. $9,749

16. Amerigas Partners $6,155 16. Murphy Oil Corp. $9,712

17. Regency Energy Partners $5,718 17. Cobalt International Energy $9,167

18. Sunoco Logistics Partners $5,544 18. Denbury Resources Inc. $8,831

19. Access Midstream Partners $5,441 19. Plains Exploration & Production $8,794

20. Western Gas Partners $5,385 20. Newfield Exploration Co. $7,156

21. Teekay LNG Partners $4,885 21. QEP Resources Inc. $6,961

22. Targa Resources Partners $4,857 22. Sandridge Energy Inc. $6,949

23. Inergy LP $4,311 23. Whiting Petroleum Corp. $6,389

24. Terra Nitrogen Company LP $4,009 24. MDU Resources Group Inc. $5,585

25. Teekay Offshore Partners $3,935 25. Ultra Petroleum Corp. $5,569

0.400.43

0.52

0.52

0.57

0.57

0.63

0.63

0.63

0.63

0.63

0.63

0.63

0.63

0.63

0.63

0.63

0.66

0.66

0.66

0.69

0.69

0.69

0.73

0.73

$0.40 $0.80

$1.23 $1.75

$2.27 $2.84

$3.41

$4.04

$4.67

$5.30

$5.93

$6.56

$7.19

$7.82

$8.45

$9.08

$9.71

$10.34

$11.00

$11.66

$12.32

$13.01

$13.70

$14.39

$15.12

$15.84

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2

Distribution History


Quarterly Distribution Cumulative Distribution

2006 2007 2008 2009

(1)

2010

Consistently paid the distribution for 26 quarters

81% increase in quarterly distribution since IPO

Generated total return of ~231%

8

2011

(1) The Q1 2006 distribution, adjusted for the partial period from the Company's closing of the IPO on January 19, 2006 through March 31, 2006, equates to $0.32 per unit.

2012

Jonah Field Acquisition Provides Significant Upside Potential

9

Significant operated entry into the Green River Basin

Long-life, low-decline natural gas asset

Significant future drilling inventory

~1.2 Tcfe of identified resource potential from ~650

future drilling locations

Hedged ~100% of net expected oil and natural gas

production through 2017

Immediately accretive to distributable cash flow per unit

Strategic Rationale

Asset Overview

Production of ~145 MMcfe/d

55% operated by production

Low decline rate of ~14%

Proved reserves of approximately 730 Bcfe (56% PDP)

73% natural gas, 23% NGL and 4% oil

~750 gross wells on >12,500 net acres

Park

Teton

Albany

Big Horn

Carbon

Converse

Crook

Fremont

Goshen

Hot Springs Johnson

Laramie

Lincoln

Natrona

Niobrara

Platte

Sheridan

Sublette

Sweetwater Uinta

Washakie Weston

Campbell

Wyoming

Oil Fields

Natural Gas Fields

Salt Creek Jonah

Acquisition Acreage

Field Area

Sublette County

On July 31, 2012, LINN closed a $1.025 billion

acquisition in Wyoming’s Jonah Field from BP.

Anadarko Salt Creek Joint-Venture

10 (1) LINN Energy, LLC estimates.

Park

Teton

Albany

Big Horn

Carbon

Converse

Crook

Fremont

Goshen

Hot Springs Johnson

Laramie

Lincoln

Natrona

Niobrara

Platte

Sheridan

Sublette

Sweetwater Uinta

Washakie Weston

LaBarge

EXXON Shute Creek Plant

EXXON

Field

Campbell

Salt Creek Wyoming

1,000

10,000

100,000

1910 1930 1950 1970 1990 2010

Year

Barr

els

Oil p

er

Day

Primary

Secondary

Tertiary

19.9% 9.9% 24.4%

Oil Fields

Natural

Gas Fields

CO2 Pipelines

Natural Gas

Pipelines

On April 3, 2012, LINN received 23% of Anadarko’s

(“APC”) interest in the Salt Creek field, one of the

largest CO2 EOR projects in North America.

Unique, high growth asset with low decline rate

Expect steady production growth for ~10 years

Expect to greatly benefit from APC’s extensive CO2

experience

Potential to transfer enhanced oil recovery (“EOR”)

technology to LINN’s existing asset base

Immediately accretive to DCF / unit

Strategic Rationale

Asset Overview

Expect to invest ~$600 million over the next 3-6 years

$400 million of APC’s development costs

$200 million net to LINN’s interest

Net production ~1,600 BOPD (first 12 months)(1)

Expect to double net production by 2016

Low decline rate of <7% and reserve life of ~28 years.

Estimated ~1 billion gross barrels of oil remaining in

place

Hugoton Field Acquisition Fits The MLP Model

KS

TX

OK

Finney

Grant

Hamilton

Haskell

Kearny

Morton Seward

Stanton

Stevens

Kansas

Acquisition Acreage

On March 30, 2012, LINN closed a $1.2 billion acquisition in

the liquids-rich Kansas Hugoton Field from BP America.

Jayhawk Gas Plant

11

Liquids-Rich

Liquids-rich production of ~110 MMcfe/d

37% NGLs / 63% natural gas

Excellent MLP Asset

Low decline rate of 7%

Reserve life of ~18 years

Proved reserves of ~730 Bcfe, with 81% PDP

Platform For Growth

~800 future drilling locations on >600,000 contiguous acres

~500 identified recompletion opportunities in the Chase formation

100% ownership of Jayhawk Gas Processing Plant

o Significant excess capacity; currently 41% utilized

Strategic-Fit With LINN’s Business Model

Immediately accretive to DCF / unit

Little requirement for capital investment

Steady stream of predictable cash flow

Granite Wash – Operated Horizontal Drilling Activity (Greater Stiles Ranch)

12

DYCO

FRYE RANCH

STILES RANCH

0 8,260’

Feet

Hemphill County

Wheeler County

7TH STEP – MENDOTA

DYCO

TWIN

CHANNELS

STILES

RANCH

FRYE

RANCH

MAYFIELD

Hemphill County

Wheeler County

Roger Mills

County

Beckham County

BUFFALO

WALLOW

2 STEP

TEXAS

OKLAHOMA

LINN Acreage

Acquisition Acreage

LINN Acreage

~23,000 Gross

~12,000 Net

Drilled Wells

Acquisition

Acreage

~21,000 Net

2012 Proposed

Drilling Activity

Current

Hogshooter

Development

Successfully completed three

Hogshooter oil wells in Q2’12

Average IP rates of ~2,500

Bbls/d of oil

Currently have 8 operated rigs

drilling Hogshooter wells

Plan to drill 20 Hogshooter

wells by year-end

Modeling IP rate of ~1,700

Bbls/d of oil

Extending mapping effort over

LINN’s additional acreage in the

Granite Wash

Hogshooter

IP Rate

Oil

(Bbls/d)

Natural Gas

(MMcf/d)

Well 1 2,454 3.0

Well 2 2,891 4.4

Well 3 2,122 3.4

LINN’s Unique Position In The Granite Wash

Over 600 horizontal

drilling locations

Produce from 8

separate zones

Each zone bears a

unique production

profile

Oil

Liquids-rich gas

Dry gas

Enables LINN to adapt

its drilling program

Focus on highest

returns

Recently shifted entire

drilling program to

focus on oil 13

G

R

A

N

I

T

E

W

A

S

H

W

AS

H

A

TO

K

A

D

E

S

M

O

I

N

E

S

I

A

N

LATERAL BOREHOLES

VIR-GILIAN

Carr

Britt

“A”

“A” thru “C"

“B”

“C”

“D”

“E”

“F”

Lwr “C” thru “E"

9,400’

15,000’

Lansing

Kansas City

(Hogshooter)

Cleveland

Tonkawa

Oil

Natural Gas &

Condensate Rich

Natural Gas &

Condensate Lean

LINN horizontal

tested zone

Granite Wash / Atoka Wash Stratigraphy

200

300

400

500

600

700

800

900

1000

YE09 YE10 YE11 2012E 2013E 2014E 2015E

Pro

du

cti

on

(M

Mcfe

/d)

LINN Base Completed Acquisitions Potential Future Growth Prof ile

LINN Provides Both Organic & Acquisition Growth

LINN is unique in that it provides investors with the potential for significant

organic and acquisition growth

14

Potential

Organic

Growth(2)

LINN

Base Assets

$2.8 billion of

Acquisitions

in 2012(4) ~320 MMcfe/d YE

2010 Exit Rate

~425 MMcfe/d YE 2011

Exit Rate

~$1.5

billion(3) of

acquisitions

impact in addition to

30% organic growth

(1) Projected organic production from future Jonah Field drilling is not included in the company’s Potential Organic Growth profile.

(2) Based on the Company’s estimated 3-year forward-looking budget and assuming the wells produce at rates consistent with historical average for wells in their respective regions.



Permian Basin (Wolfberry)

o 4 year drilling inventory

o ~400 future drilling locations

Horizontal Granite Wash


o ~600 high potential,

low-risk locations (TX)

Jonah Field(1)


o ~650 future drilling locations

Natural Gas Positions

Percent Puts (3) Swaps Puts (2)

Vo

lum

es (

Bb

ls/d

)

Significant Hedge Position

LINN is hedged ~100% on expected natural gas production through 2017; and

~100% on expected oil production through 2016

Puts provide price upside opportunity

Vo

lum

es (

MM

cf/

d)

Oil Positions

Percent Puts (3) Swaps (4) Puts

15

Note: Except as otherwise indicated, illustrations represent full-year natural gas hedge positions through 2017 and oil positions through 2016, as of June 30, 2012.

(1) Represents the average daily hedged volume for the period August-December 2012.

(2) Excludes natural gas puts used to hedge NGL revenues associated with BP Hugoton acquisition.

(3) Calculated as percentage of hedged volume in the form of puts.

(4) Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100 per Bbl for each of the years ending December 31, 2017, and December 31,

2018, and $90 per Bbl for the year ending December 31, 2019, 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.

$5.12 $5.22

$5.25

$5.19 $4.20 $4.26

$5.46 $5.42 $5.00

$5.00 $5.00 $4.88

-

50

100

150

200

250

300

350

400

450

500

550

2012 (1) 2013 2014 2015 2016 2017

$5.12

$5.14 $5.31 $5.27

46%41%

43%

34%

$4.48 $4.48

35% 36%

$96.54

$94.97 $92.92 $96.23 $90.56

$99.19

$97.86 $91.30

$90.00 $90.00

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2012 (1) 2013 2014 2015 2016

$94.81 $90.44

25%23%

21%

21%22%$97.09

$95.57 $92.52

C-Corp. Peers

% Hedged

Note: LINN’s hedge percentages based on internal estimates. Excludes NGL production and natural gas puts used to hedge NGL revenues associated with BP Hugoton acquisition.

(1) Peers include: CLR, FST, XEC, KWK, NFX, PXD, PXP, RRC, SWN and WLL. Source: FactSet research estimates and hedge information based on publicly available sources.

(2) Peers include: BBEP, EVEP, LGCY, LRE, MEMP, MCEP, PSE, QRE, and VNR. Source: Wells Fargo Securities, LLC estimates.

LINN’s cash flow is notably more protected from oil and natural gas price uncertainty than its C-Corp. and Upstream MLP peers

Prolonged periods of weak natural gas prices could put further pressure on E&P C-Corps.

Significant Hedge Position (Equivalent Basis)

% Swaps % Puts

16

Upstream MLP

Peers % Hedged (1) (2)

64% 63%65%

70% 69%

54%

36% 37% 35% 30% 31%

25%

100% 100% 100% 100% 100%

79%

44%

22%4%

1%

77%70%

54%

31%

11%

0%

0%

20%

40%

60%

80%

100%

2012 2013 2014 2015 2016 2017

Exp

ecte

d P

rod

ucti

on

Hed

ged

$0.40 $0.40 $0.43

$0.52 $0.52

$0.57 $0.57

$0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.66 $0.66 $0.66

$0.69 $0.69 $0.69

$0.73 $0.73

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

Natu

ral G

as ($

/MM

Btu

)

Oil

($/B

bl)

Distribution Stability and Growth


2006 2007 2008 2009

(2)

2010

Stability During Credit Crisis

2011

81% increase in quarterly distribution since IPO

Distribution stability maintained throughout the Credit Crisis (i.e. 2008 – 2009)

− 16 out of 74 MLPs (or 23%) were forced to reduce or suspend distributions(1)

WTI Crude Oil Henry Hub Natural Gas Quarterly Distributions

17

Source for commodity prices: Bloomberg.

(1) Source: Wells Fargo Securities, LLC research note entitled “MLP Primer - - Fourth Edition” published on November 19, 2010.

(2) The Q1 2006 distribution, adjusted for the partial period from the Company's closing of the IPO on January 19, 2006 through March 31, 2006, equates to $0.32 per unit.

(3) Based on announced Q2’12 distribution of $0.725 per unit payable August 14, 2012, to unitholders of record at the close of business August 7, 2012.

2012

(3)

(50%)

0%

50%

100%

150%

200%

250%

2006 2007 2008 2009 2010 2011 2012

Line Total Return (TR) Line Price Appreciation Alerian MLP TR Index S&P Mid-Cap E&P TR Index S&P 500 TR Index

Note: Market data as of July 27, 2012 (LINE closing price of $39.15). Source: Bloomberg.

LINN Total Return and Stock Price Appreciation (LINE IPO – Present of ~231%)

LINN Historical Return

~24%

~14%

~86%

~146%

~231%

18

E&P MLP/LLC

6%

All Others94%

Size Advantage in E&P MLP/LLC Market

LINN has a significant size advantage in the

E&P MLP/LLC market

Greater access to capital markets

Ability to complete larger transactions

E&P market presents significantly more

acquisition opportunities than rest of MLP

market

E&P Sector has room to grow; $28 billion

versus $412 billion for all other sectors

LINE vs. Other Upstream MLPs(1) MLP/LLC Total EV: $440 Billion

$28

Billion

$412

Billion

19 (1) Excludes Dorchester Minerals LP and Constellation Energy Partners.

Note: Market data as of July 27, 2012 (LINE closing price of $39.15). Source: Bloomberg.

EV Energy

Vanguard

Legacy

BreitBurn

QR Energy

Pioneer

Atlas Resources

LRR Energy Mid-Con Energy

Memorial Production

Constellation

$14.5 Billion $13.6 Billion

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

$16.0

LINE All Others (11 MLPs)

En

terp

rise V

alu

e (

$B

)

Why Invest in LINN?

− High quality asset base

Multi-year inventory of liquids-rich development opportunities

45% liquids

Long-life reserves (~18 years)

Diversified asset base (6 core areas / >15,500 gross producing wells)

– Extensive hedge positions; reduced commodity risk

− Organic growth (YOY ~20% in 2012E vs. 2011)

− Acquisitions

Excellent acquisition track record (54 transactions for ~$10 billion)

~$1.4 billion(1) completed in 2010



− Strong balance sheet

Recent increase to revolving credit facility commitment provides

additional liquidity and financial flexibility (e.g. >$1B of liquidity)

− Announced LinnCo IPO expected to provide further liquidity

− First in class access to capital; including low cost of

equity capital

− Expect ~1.10x coverage ratio for the remainder of the year

Stable

Distributions

Distributions

Growth Drivers

Financial Strength

Note: All operational and reserve data as of December 31, 2011, pro forma for recent acquisitions and joint venture. Estimates of proved reserves for recent acquisitions and joint venture were calculated as of the

effective date of the acquisitions using forward strip oil and natural gas prices, which differ from estimates calculated in accordance with SEC rules and regulations.


(2) Based on contract price for recently closed acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV. 20

Embrace & Drive Change

Pursue Growth

Take Action

Respect Others

Be Passionate

Connect

LINN Energy’s mission is to acquire,

develop and maximize cash flow

from a growing portfolio of long-life

oil and natural gas assets.

22 Note: All operational and reserve data as of December 31, 2011, pro forma for recently closed 2012 acquisitions and joint venture (“JV”). Estimates of proved reserves for recently closed 2012 acquisitions and JV were calculated as of the effective date

of the acquisitions using forward strip oil and natural gas prices, which differ from estimates calculated in accordance with SEC rules and regulations. Estimates of proved reserves for recently closed 2012 acquisitions and JV based solely on data

provided by seller.

Corporate

Headquarters

(Houston)

NM

TX

KS IL

LA

MI

ND

OK

CA Hugoton Field

East Texas

WY

Oklahoma

Williston / Powder River Basins

• 32 MMBoe proved reserves

• 4% of total reserves

• 92% liquids

California



• 93% liquids

Jonah Field

• 730 Bcfe proved reserves


• 73% natural gas

Permian Basin



• 79% liquids

Michigan / Illinois

• 317 Bcfe proved reserves


• 96% natural gas

LINN Operations

Recent Acquisitions /

Joint Ventures

Salt Creek Field

LINN Overview

TX Panhandle Granite Wash

TX Panhandle Shallow

Jonah Field

Mid-Continent

• 3.1 Tcfe proved reserves


• 59% natural gas

Financial Appendix

24

Proved Reserves

The following table sets forth certain information with respect to LINN’s proved reserves at December 31, 2011 and pro forma

proved reserves calculated on the basis required by SEC rules:

Region

Proved

Reserves At

December 31,

2011 (Bcfe)(1)

Proved

Reserves 2012

Acquisitions

(Bcfe)(1)

Pro Forma

Proved Reserves

(Bcfe)(1)

Pro Forma %

Oil and NGL

Pro Forma %

Proved Developed

Mid-Continent 1,860 24 1,884 41% 53%

Hugoton Basin(2) 380 701 1,081 47% 87%

Green River Basin(3) - 703 703 27% 54%

Permian Basin 527 - 527 79% 56%

Michigan/Illinois 317 - 317 4% 91%

California 193 - 193 93% 93%

Williston/Powder River

Basin(2)

93

96

189

92%

63%

East Texas(4) - 110 110 3% 100%

Total 3,370 1,634 5,004 45% 66%

(1) Except as otherwise noted, proved reserves for oil and natural gas assets were calculated on December 31, 2011, the reserve

report date, and use a price of $4.12/MMBtu for natural gas and $95.84/Bbl for oil, which represent the unweighted average

of the first-day-of-the-month prices for each of the twelve months immediately preceding December 31, 2011.

(2) Pro forma proved reserves for the Hugoton Acquisition (in the Hugoton Basin region) and the Anadarko Joint Venture (in

the Williston/Powder River Basin region) were calculated using a price of $3.73/MMBtu for natural gas and $98.02/Bbl for

oil, which represent the unweighted average of the first-day-of-the-month prices for each of the twelve months ending

March 1, 2012, the most recent twelve-month period prior to the closing of each of those transactions.

(3) Pro forma proved reserves for the Jonah Acquisition (in the Green River Basin region) were calculated using a price of

$3.15/MMBtu for natural gas and $95.63/Bbl for oil, which represents the unweighted average of the first-day-of-the-month

prices for each of the twelve months ending June 1, 2012, the most recent twelve-month period prior to the signing of the

Jonah Acquisition.

(4) Pro forma proved reserves for the East Texas Acquisition were calculated using a price of $3.54/MMBtu for natural gas and

$97.65/Bbl for oil, which represent the unweighted average of the first-day-of-the-month prices for each of the twelve

months ending April 1, 2012, the most recent twelve-month period prior to the closing of the East Texas Acquisition.

The Company defines adjusted EBITDA as net income (loss) 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 long-lived assets;

Write-off of deferred financing fees;

(Gains) losses on sale of assets and other, net;

Provision for legal matters;

Loss on extinguishment of debt;

Unrealized (gains) losses on commodity derivatives;

Unrealized (gains) losses on interest rate derivatives;

Realized (gains) losses on interest rate derivatives;

Realized (gains) losses on canceled derivatives;

Realized gain on recovery of bankruptcy claim;

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 make to its 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 unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, realized gain on recovery of bankruptcy claim, impairment of long-lived assets, loss on extinguishment of debt and (gains) losses on sale of assets, net.

Historical Financial Statements Reconciliation of Non-GAAP Measures

25

The following presents a reconciliation of net loss to adjusted EBITDA:

Historical Financial Statements Adjusted EBITDA

26

The following presents a reconciliation of net income (loss) to adjusted EBITDA:

Three Months Ended

June 30, Six Months Ended

June 30,

2012 2011 2012 2011

(in thousands)

Net income (loss) $ 237,086 $ 237,109 $ 230,884 $ (209,573 )

Plus:

Net operating cash flow from acquisitions and divestitures, effective date through closing date 6,034 29,308 45,127 36,359

Interest expense, cash 86,773 61,591 129,652 125,181

Interest expense, noncash 7,617 770 42,257 644

Depreciation, depletion and amortization 143,506 79,345 260,782 145,711

Impairment of long-lived assets 146,499 — 146,499 —

Write-off of deferred financing fees 6,229 1,189 7,889 1,189

(Gains) losses on sale of assets and other, net (444 ) (93 ) 991 (916 )

Provision for legal matters 160 248 795 740

Loss on extinguishment of debt — 9,810 — 94,372

Unrealized (gains) losses on commodity derivatives (303,630 ) (163,434 ) (250,406 ) 261,851

Realized gain on recovery of bankruptcy claim (18,277 ) — (18,277 ) —

Unit-based compensation expenses 6,663 5,543 14,834 11,181

Exploration costs 407 550 817 995

Income tax expense 512 1,670 9,430 5,868

Adjusted EBITDA $ 319,135 $ 263,606 $ 621,274 $ 473,602

The following presents a reconciliation of net loss to adjusted net income:

Historical Financial Statements Adjusted Net Income

27

Three Months Ended

June 30, Six Months Ended

June 30,

2012 2011 2012 2011

(in thousands, except per unit amounts)

Net income (loss) $ 237,086 $ 237,109 $ 230,884 $ (209,573 )

Plus:

Unrealized (gains) losses on commodity derivatives (303,630 ) (163,434 ) (250,406 ) 261,851

Realized gain on recovery of bankruptcy claim (18,277 ) — (18,277 ) —

Impairment of long-lived assets 146,499 — 146,499 —

Loss on extinguishment of debt — 9,810 — 94,372

(Gains) losses on sale of assets, net (479 ) (128 ) 921 (986 )

Adjusted net income $ 61,199 $ 83,357 $ 109,621 $ 145,664

Net income (loss) per unit – basic $ 1.19 $ 1.34 $ 1.17 $ (1.25 )

Plus, per unit:

Unrealized (gains) losses on commodity derivatives (1.52 ) (0.93 ) (1.26 ) 1.56

Realized gain on recovery of bankruptcy claim (0.09 ) — (0.09 ) —

Impairment of long-lived assets 0.73 — 0.74 —

Loss on extinguishment of debt — 0.06 — 0.56

(Gains) losses on sale of assets, net — — — (0.01 )

Adjusted net income per unit – basic $ 0.31 $ 0.47 $ 0.56 $ 0.86

Reserve Replacement / F&D Calculations Reconciliation of Non-GAAP Measures

Year Ended December 31,

2011 2010

Costs incurred (in thousands):

Costs incurred in oil and natural gas property acquisition, exploration and

development $ 2,158,639 $ 1,602,086

Less:

Asset retirement costs (2,427) (748)

Property acquisition costs (1,516,737) (1,356,430)

Oil and natural gas capital costs expended, excluding acquisitions $ 639,475 $ 244,908

Reserve data (MMcfe):

Purchase of minerals in place 579,003 671,146

Extensions, discoveries and other additions 449,818 234,324

Add:

Revisions of previous estimates (120,892) 76,281

Annual additions 907,929 981,751

Less:

Purchase of minerals in place (579,003) (671,146)

Annual additions, excluding acquisitions 328,926 310,605

Annual production (MMcfe) 134,645 96,827

Reserve replacement metrics:

Reserve replacement cost per Mcfe (1) $ 2.37 $ 1.63

Reserve replacement ratio (2) 674% 1,014%

Finding and development cost from the drillbit per Mcfe (3) $ 1.94 $ 0.79

Drillbit reserve replacement ratio (4) 244% 321%

(1) (Oil and natural gas capital costs expended) divided by (Annual additions)

(2) (Annual additions) divided by (Annual production)

(3) (Oil and natural gas capital costs expended, excluding acquisitions) divided by (Annual additions, excluding acquisitions)

(4) (Annual additions, excluding acquisitions) divided by (Annual production) 28

The U.S. Securities and Exchange Commission (“SEC”) permits oil and gas companies, in their filings with the

SEC, to disclose only resources that qualify as "reserves" as defined by SEC rules. We use terms describing

hydrocarbon quantities in this presentation including “inventory” and “resource potential” that the SEC’s guidelines

prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than

estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are

substantially less certain. Investors are urged to consider closely the reserves disclosures in the Company’s

Annual Report on Form 10-K for the year ended December 31, 2011, 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.

In this communication, the terms other than “proved reserves” refer to the Company's internal estimates of

hydrocarbon volumes that may be potentially discovered through exploratory drilling or recovered with additional

drilling or recovery techniques. Those estimates may be based on economic assumptions with regard to

commodity prices that may differ from the prices required by the SEC to be used in calculating proved

reserves. In addition, these hydrocarbon volumes may not constitute reserves within the meaning of the Society

of Petroleum Engineer's Petroleum Resource Management System or the SEC’s oil and gas disclosure rules.

Unless otherwise stated, hydrocarbon volume estimates have not been risked by Company management. Factors

affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the

availability of capital, drilling and production costs, commodity prices, availability of drilling services and

equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors,

and actual drilling results, including geological and mechanical factors affecting recovery rates. Accordingly,

actual quantities that may be ultimately recovered from the Company's interests may differ substantially from the

Company’s estimates of potential resources. In addition, our estimates of reserves may change significantly as

development of the Company's resource plays and prospects provide additional data.

29

Linn Energy - EnerCom Oil & Gas Conference

Business

salt creek

hedge ngl

bp hugoton

east texas

wells fargo

jv based solely

recently closed

natural gas