This document contains forward-looking statements about Linn Energy's business and operations. It warns that actual results could differ materially from expectations due to assumptions, risks, and uncertainties. Some of the risks mentioned include financial performance, access to capital, commodity prices, replacing reserves, and regulations. The document provides an overview of Linn Energy as an oil and gas company with large reserves and development opportunities across many regions. It also discusses the company's history of growth through billions of dollars in acquisitions.
Challenger August Investor Presentation 290811princeslea79
Challenger Energy’s strategy is to identify, acquire and appraise material upstream oil and gas
exploration opportunities
Mercury Stetson Prospect in North Texas, US
Two proven shale formations – Barnett and Woodford
Massive potential gas in place with OGIP estimated at 360 BCF/sq mile
Large prospect area – potentially up to 55,000 acres (86 sq miles)
Prospect is close to existing infrastructure
Contiguous land position of ~ 26,000 acres with a short term target of 35,000 acres.
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Significant acreage – 45,000 acres with options over a further 6,500 acres.
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Karoo Basin in South Africa
Shale gas in Karoo Basin now a major focus for international E&P companies (eg Shell, Cheasapeake, Statoil and Sasol)
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Independent US Energy Information Agency report suggests Risked Recoverable Resource of more than 7 TCF in
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Attractive assets have exciting potential to grow significant shareholder value
Challenger August Investor Presentation 290811princeslea79
Challenger Energy’s strategy is to identify, acquire and appraise material upstream oil and gas
exploration opportunities
Mercury Stetson Prospect in North Texas, US
Two proven shale formations – Barnett and Woodford
Massive potential gas in place with OGIP estimated at 360 BCF/sq mile
Large prospect area – potentially up to 55,000 acres (86 sq miles)
Prospect is close to existing infrastructure
Contiguous land position of ~ 26,000 acres with a short term target of 35,000 acres.
Triple Crown Prospect in Texas, US
Significant acreage – 45,000 acres with options over a further 6,500 acres.
Large gas charged zones, Ellenburger (dolomite) and an unconventional Hybrid play which is geologically analogous to
Montney Hybrid Play in Western Canada with an estimated OGIP of 9 TCF.
Testing to commence shortly on both the Ellenburger and Hyprid Play
Karoo Basin in South Africa
Shale gas in Karoo Basin now a major focus for international E&P companies (eg Shell, Cheasapeake, Statoil and Sasol)
Challenger Energy’s permit of approx. 800,000 acres centred on only well within basin to flow significant gas to surface to
date, awaiting approval.
Independent US Energy Information Agency report suggests Risked Recoverable Resource of more than 7 TCF in
application area.
Attractive assets have exciting potential to grow significant shareholder value
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3. 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.
4. LINN Overview
8th largest public MLP/LLC and 8th largest
domestic independent oil & natural gas company
IPO in 2006 (NASDAQ: LINE)
Equity market cap $7.8 billion
Total net debt $6.7 billion
Salt Creek Field
Enterprise value $14.5 billion ND
Large, long-life diversified reserve base Jonah Field
~5.1 Tcfe total proved reserves MI
WY
64% proved developed
CA Hugoton Field IL
45% oil and NGLs / 55% natural gas KS
~18 year reserve-life index
>15,500 gross productive oil and natural gas wells(1) OK
NM East Texas
Large inventory of low risk and liquids-rich
development opportunities TX
Corporate
LA
Jonah Field – ~650 locations LINN Operations
Headquarters
(Houston)
Recent Acquisitions /
Granite Wash – ~600 horizontal locations Joint Ventures
Wolfberry – ~400 locations
Bakken – ~800 horizontal locations(2) 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
Cleveland – ~165 horizontal locations 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
Kansas Hugoton – ~800 locations acquisitions and JV based solely on data provided by seller. Source: Bloomberg.
(1) Well count does not include ~2,500 royalty interest wells.
Salt Creek Field – CO2 flood (2) Average working interest of ~7%.
4
5. Growth Through Accretive Acquisitions
~$10 billion in acquisitions completed since the Company’s inception
Includes 54 separate transactions(1)
Value of Acquisitions Per Year (1)
$10,000 $9,635
$9,000
$2,800
$8,000
$6,835
$7,000
($'s in millions)
$6,000 $1,479
$5,356
$5,000
$1,351
$3,882 $4,000
$4,000 $3,281 $601
$3,000
$2,000 $2,627
$1,000 $654
$52 $78 $202
$452
$0
(2)
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012TD
Cumulative Acquisitions Acquisitions Completed In Year
(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. 5
6. Continued Success in Acquisition Activity
Record amount of Record amount of Record amount of
negotiations in 2010 transactions closed in 2011 transactional value YTD(3)
− Screened 189 opportunities − Screened 122 opportunities − Screened 143 opportunities
− Bid 41 for ~$10.1 billion − Bid 31 for ~$7.5 billion − Bid 12 for ~$6.2 billion
− Closed 13 for ~$1.4 billion − Closed 12 for ~$1.5 billion − Closed 4 for ~$2.8 billion
Historical Acquisitions and Joint Venture
$3,000
Total ~$5.7 Billion Since 2009
$2,500
($'s in millions)
$2,000
$1,500
$2,800
$1,000
$1,351 $1,479
$500
$118
$0
(1) (1) (1) (2)
2009 2010 2011 2012TD
(1) Based on total consideration.
(2) Based on contract price for recently closed acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV. 6
(3) As of August 3, 2012.
7. MLP and Independent E&P Rankings
LINN is quickly becoming one of the largest MLP and independent E&P companies
− 8th largest public MLP/LLC
− 8th largest domestic independent oil & natural gas company
Rank Master Limited Partnership Enterprise Value ($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
Note: Market data as of July 27, 2012 (LINE closing price of $39.15).
Source: Bloomberg.
7
8. Distribution History
Consistently paid the distribution for 26 quarters
81% increase in quarterly distribution since IPO
Generated total return of ~231%
Distribution History
$15.84
$16.00
$15.12 0.73
$14.39 0.73
$13.70 0.69
$14.00
$13.01 0.69
$12.32 0.69
$12.00 $11.66 0.66
$11.00 0.66
$10.34 0.66
$9.71 0.63
$10.00
$9.08 0.63
$8.45 0.63
$7.82 0.63
$8.00 $7.19 0.63
$6.56 0.63
$5.93 0.63
$6.00 $5.30 0.63
$4.67 0.63
$4.04 0.63
$4.00 $3.41 0.63
$2.84 0.57
$2.27 0.57
$1.75
$2.00 $1.23 0.52
$0.80 0.52
$0.40 0.43
0.40
$- (1)
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
2006 2007 2008 2009 2010 2011 2012
Quarterly Distribution Cumulative Distribution
8
(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.
9. Jonah Field Acquisition Provides
Significant Upside Potential
On July 31, 2012, LINN closed a $1.025 billion Sheridan
acquisition in Wyoming’s Jonah Field from BP. Park
Big Horn Campbell Crook
Strategic Rationale Wyoming Washakie Weston
Teton
Significant operated entry into the Green River Basin Jonah
Hot Springs Johnson Salt Creek
Natrona
Long-life, low-decline natural gas asset
Sublette
Significant future drilling inventory
Lincoln
Niobrara
Fremont Converse
~1.2 Tcfe of identified resource potential from ~650
future drilling locations Platte Goshen
Hedged ~100% of net expected oil and natural gas Carbon
Albany Fields
production through 2017 Oil
Laramie
Natural Gas Fields
Sweetwater
Immediately accretive to distributable cash flow per unit Uinta
Asset Overview
Sublette County
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 Acquisition Acreage
Field Area
9
10. Anadarko Salt Creek Joint-Venture
On April 3, 2012, LINN received 23% of Anadarko’s
(“APC”) interest in the Salt Creek field, one of the
Sheridan
largest CO2 EOR projects in North America. Park
Campbell
Big Horn Crook
Strategic Rationale Wyoming Salt Creek
Washakie Weston
Unique, high growth asset with low decline rate
Teton
Hot Springs Johnson
Expect steady production growth for ~10 years Natrona
Expect to greatly benefit from APC’s extensive CO2
Lincoln
Sublette
Fremont
experience Niobrara
Converse
Potential to transfer enhanced oil recovery (“EOR”) EXXON
technology to LINN’s existing asset base LaBarge Platte Goshen
Field
Oil Fields
Immediately accretive to DCF / unit EXXON Shute
Carbon
Albany Natural
Creek Plant Gas Fields
Laramie
Sweetwater
Asset Overview Uinta
CO2 Pipelines
Natural Gas
Expect to invest ~$600 million over the next 3-6 years Pipelines
100,000
Primary
$400 million of APC’s development costs Secondary
Tertiary
$200 million net to LINN’s interest
Barrels Oil per Day
Net production ~1,600 BOPD (first 12 months)(1) 10,000
Expect to double net production by 2016
Low decline rate of <7% and reserve life of ~28 years. 19.9% 24.4% 9.9%
Estimated ~1 billion gross barrels of oil remaining in 1,000
place 1910 1930 1950 1970 1990 2010
Year
10
(1) LINN Energy, LLC estimates.
11. Hugoton Field Acquisition Fits
The MLP Model
On March 30, 2012, LINN closed a $1.2 billion acquisition in
the liquids-rich Kansas Hugoton Field from BP America.
Finney
Liquids-Rich Hamilton
Liquids-rich production of ~110 MMcfe/d
Kansas Kearny
37% NGLs / 63% natural gas
Excellent MLP Asset
Low decline rate of 7%
Haskell
Reserve life of ~18 years Stanton Grant
Proved reserves of ~730 Bcfe, with 81% PDP
Platform For Growth
~800 future drilling locations on >600,000 Jayhawk Gas Plant
contiguous acres Stevens
Morton Seward
~500 identified recompletion opportunities in the
Chase formation Acquisition Acreage
100% ownership of Jayhawk Gas Processing Plant
o Significant excess capacity; currently 41% KS
utilized
OK
Strategic-Fit With LINN’s Business Model
Immediately accretive to DCF / unit TX
Little requirement for capital investment
Steady stream of predictable cash flow
11
12. Granite Wash – Operated Horizontal
Drilling Activity (Greater Stiles Ranch)
Successfully completed three 7TH STEP – MENDOTA TWIN Roger Mills
Hogshooter oil wells in Q2’12 CHANNELS County
Hemphill County
Average IP rates of ~2,500 BUFFALO
WALLOW
OKLAHOMA
Bbls/d of oil 2 STEP
Hemphill DYCO
County DYCO
Currently have 8 operated rigs Wheeler County FRYE
MAYFIELD
drilling Hogshooter wells RANCH
TEXAS STILES
RANCH
Plan to drill 20 Hogshooter
LINN Acreage
wells by year-end Acquisition Acreage Beckham
County
Modeling IP rate of ~1,700
Wheeler County
Bbls/d of oil
Current
Extending mapping effort over Hogshooter STILES RANCH
LINN’s additional acreage in the Development
Granite Wash
LINN Acreage
Hogshooter Oil Natural Gas ~23,000 Gross
~12,000 Net
IP Rate (Bbls/d) (MMcf/d)
Acquisition
Acreage
Well 1 2,454 3.0 ~21,000 Net
Drilled Wells FRYE
Well 2 2,891 4.4 RANCH
2012 Proposed
Drilling Activity Feet
Well 3 2,122 3.4 0 8,260’
12
13. LINN’s Unique Position In The
Granite Wash
Over 600 horizontal
drilling locations Granite Wash / Atoka Wash Stratigraphy
Produce from 8
LATERAL BOREHOLES 9,400’
separate zones VIR-
Tonkawa
GILIAN
Each zone bears a Lansing
Kansas City
unique production (Hogshooter)
profile Cleveland
Carr
Oil D
G
R Britt
A
Liquids-rich gas
E
S N “A”
I
Dry gas M
O T “B”
I E
Enables LINN to adapt N
E
“C”
S
its drilling program I
W
A
“D”
A
“E”
Focus on highest N S
H “F”
returns Oil
Natural Gas & A “A”
Recently shifted entire Condensate Rich
Natural Gas &
T
O
W
A
thru
“C"
Lwr “C”
drilling program to Condensate Lean
LINN horizontal
K
A
S
H
thru “E"
focus on oil tested zone
15,000’
13
14. LINN Provides Both Organic
& Acquisition Growth
LINN is unique in that it provides investors with the potential for significant
organic and acquisition growth
Horizontal Granite Wash Permian Basin (Wolfberry) Jonah Field(1)
o 10 year drilling inventory o 4 year drilling inventory o 16 year drilling inventory
o ~600 high potential, o ~400 future drilling locations o ~650 future drilling locations
low-risk locations (TX)
1000
900
Potential
Production (MMcfe/d)
800 Organic
Growth(2)
700
600 ~425 MMcfe/d YE 2011 $2.8 billion of
Exit Rate Acquisitions
500 ~320 MMcfe/d YE
in 2012(4)
2010 Exit Rate
400
~$1.5
billion(3) of
LINN
300 acquisitions Base Assets
impact in addition to
30% organic growth
200
YE09 YE10 YE11 2012E 2013E 2014E 2015E
LINN Base Completed Acquisitions Potential Future Growth Prof ile
(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.
(3) Based on total consideration. 14
(4) Based on contract price for recently closed acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV.
15. 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
Natural Gas Positions Oil Positions
550 45,000 $92.52
$4.48 $4.48
$5.12 $95.57 $94.81
500 $90.44
$5.14 40,000 $91.30
$5.31 $97.86 $90.00 $90.00
450 $5.27 $5.00 $4.88 25%
$5.00
Volumes (MMcf/d)
35,000 21%
Volumes (Bbls/d)
$97.09 23% 22%
400 $5.00 34% 35% 36%
$5.46 $5.42 $99.19
350 30,000
41% 21%
43% 46%
300 25,000
$4.20 $4.26 $94.97 $92.92 $96.23 $90.56
250 $5.19
20,000
200 $5.25 $96.54
15,000
$5.12 $5.22
150
10,000
100
50 5,000
- -
2012 (1) 2013 2014 2015 2016 2017 2012 (1) 2013 2014 2015 2016
Swaps Puts (2) Percent Puts (3) Swaps (4) Puts Percent Puts (3)
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.
15
16. Significant Hedge Position (Equivalent Basis)
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.
100% 100% 100% 100% 100%
100%
36% 37% 35% 30% 31% 79%
80%
Expected Production Hedged
70%
77%
70% 25%
69%
60% 64% 65%
63%
54% 54%
40%
44% 31%
20%
22% 11%
4%
1% 0%
0%
2012 2013 2014 2015 2016 2017
C-Corp. Peers Upstream MLP
% Swaps % Puts % Hedged (1) Peers % Hedged (2)
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. 16
(2) Peers include: BBEP, EVEP, LGCY, LRE, MEMP, MCEP, PSE, QRE, and VNR. Source: Wells Fargo Securities, LLC estimates.
17. Distribution Stability and Growth
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)
Distribution History
Stability During Credit Crisis
$180 $0.73 $0.73
$18
$0.69 $0.69 $0.69
$160 $0.66 $0.66 $0.66 $16
$0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63 $0.63
$140 $0.57 $0.57 $14
Natural Gas ($/MMBtu)
$0.52 $0.52
$120 $12
Oil ($/Bbl)
$0.43
$100 $0.40 $0.40 $10
$80 $8
$60 $6
$40 $4
$20 $2
$0 (2) (3)
$0
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
2006 2007 2008 2009 2010 2011 2012
Quarterly Distributions WTI Crude Oil Henry Hub Natural Gas
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. 17
(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.
18. LINN Historical Return
LINN Total Return and Stock Price Appreciation (LINE IPO – Present of ~231%)
250%
~231%
200%
150%
~146%
100%
~86%
50%
~24%
~14%
0%
(50%)
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.
18
19. Size Advantage in E&P MLP/LLC Market
LINN has a significant size advantage in the E&P market presents significantly more
E&P MLP/LLC market acquisition opportunities than rest of MLP
Greater access to capital markets market
Ability to complete larger transactions 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
$16.0
$14.5 Billion $13.6 Billion E&P
$14.0 Constellation MLP/LLC
Memorial Production
Mid-Con Energy
LRR Energy
6%
$12.0 $28
Enterprise Value ($B)
Atlas Resources
Pioneer Billion
$10.0
QR Energy
$8.0 BreitBurn
$6.0 Legacy
$412
$4.0 Vanguard
Billion
$2.0
EV Energy
$0.0
LINE All Others All Others
(11 MLPs) 94%
(1) Excludes Dorchester Minerals LP and Constellation Energy Partners. 19
Note: Market data as of July 27, 2012 (LINE closing price of $39.15). Source: Bloomberg.
20. Why Invest in LINN?
− High quality asset base
Multi-year inventory of liquids-rich development opportunities
Stable 45% liquids
Distributions 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
Distributions Excellent acquisition track record (54 transactions for ~$10 billion)
Growth Drivers ~$1.4 billion(1) completed in 2010
~$1.5 billion(1) completed in 2011
~$2.8 billion(2) completed in 2012
− Strong balance sheet
Recent increase to revolving credit facility commitment provides
additional liquidity and financial flexibility (e.g. >$1B of liquidity)
Financial Strength − 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
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.
(1) Based on total consideration. 20
(2) Based on contract price for recently closed acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV.
21. LINN Energy’ mission is to acquire,
s
develop and maximize cash flow
from a growing portfolio of long-life Embrace & Drive Change
oil and natural gas assets. Pursue Growth
Take Action
Respect Others
Be Passionate
Connect
22. LINN Overview
Salt Creek Field ND
Jonah Field
WY MI
Hugoton Field
CA IL
KS
TX Panhandle Oklahoma
Shallow
TX Panhandle OK
Granite Wash East Texas
NM
TX LINN Operations
Corporate
Headquarters
LA Recent Acquisitions /
(Houston) Joint Ventures
Williston / Powder River Basins Jonah Field California
• 32 MMBoe proved reserves • 730 Bcfe proved reserves • 32 MMBoe proved reserves
• 4% of total reserves • 15% of total reserves • 4% of total reserves
• 92% liquids • 73% natural gas • 93% liquids
Permian Basin Mid-Continent Michigan / Illinois
• 88 MMBoe proved reserves • 3.1 Tcfe proved reserves • 317 Bcfe proved reserves
• 10% of total reserves • 61% of total reserves • 6% of total reserves
• 79% liquids • 59% natural gas • 96% natural gas
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 22
provided by seller.
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:
Proved Proved
Reserves At Reserves 2012 Pro Forma
December 31, Acquisitions Proved Reserves Pro Forma % Pro Forma %
Region 2011 (Bcfe)(1) (Bcfe)(1) (Bcfe)(1) Oil and NGL 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.
24
25. Historical Financial Statements
Reconciliation of Non-GAAP Measures
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.
25
26. Historical Financial Statements
Adjusted EBITDA
The following presents a reconciliation of net loss to adjusted EBITDA:
The following presents a reconciliation of net income (loss) to adjusted EBITDA:
Three Months Ended Six Months Ended
June 30, 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
26
27. Historical Financial Statements
Adjusted Net Income
The following presents a reconciliation of net loss to adjusted net income:
Three Months Ended Six Months Ended
June 30, 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
27
28. 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
29. 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