linn energy overview
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TRANSCRIPT
LinnCo Overview
Forward-Looking Statements and Risk Factors Statements made in these presentation slides and by representatives of LINN Energy, LLC and LinnCo, LLC (collectively the “Company”) 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, indebtedness under LINN Energy’s 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, LINN Energy’s ability to replace reserves and efficiently develop LINN Energy’s current reserves, LINN Energy’s 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 LINN Energy’s 2011 Annual Report on Form 10-K and any other public filings. We undertake 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 September 28, 2012, except otherwise noted.
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.
LinnCo – Strategic Rationale
Issues Form 1099-DIV rather than a Schedule K-1
Should appeal greatly to investors who do not want the tax reporting
burdens associated with owning a partnership security
Significantly expands LINN’s investor base
Institutions
Tax-exempt organizations
Incremental retail investors (including IRA accounts)
4
Corporate Headquarters
(Houston)
NM
TX
KS IL
LA
MI
ND
OK
CA
WY
5
East Texas
Salt Creek Field
LINN Operations 2012 Acquisitions / Joint Venture
Note: Market data as of September 28, 2012 (LINE closing price of $41.24). All operational and reserve data as of December 31, 2011, pro forma for closed 2012 acquisitions and joint venture (“JV”). Estimates of proved reserves for 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 closed 2012 acquisitions and JV based solely on data provided by seller. Source: Bloomberg.
(1) Pro forma for ~$1,250 million LNCO IPO (assumes proceeds used to repay debt) and Jonah Field acquisition.
(2) Well count does not include ~2,500 royalty interest wells. (3) Average working interest of ~7%.
8th largest public MLP/LLC and 12th largest domestic independent oil & natural gas company
IPO in 2006 with enterprise value of ~$713 million
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
~21 year reserve-life index
>15,000 gross productive oil and natural gas wells(2)
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(3)
Cleveland – ~165 horizontal locations
Kansas Hugoton – ~800 locations
Salt Creek Field – CO2 flood
$9.5 billion
$5.5 billion
$15.0 billion(1)
LINN Overview
Hugoton Field
Jonah Field
LINN’s Unique Business Strategy
Consolidate Mature Assets
Mitigate Commodity
Risk
Operational Efficiency
Organic Growth
Opportunities
LINN’s goal is to consolidate mature oil and natural gas assets across the U.S.
Since 2003, we have made 54 acquisitions for ~$10 billion(1)
We efficiently operate and enhance our existing properties
o Include workovers, recompletions and other production enhancement activities
>15,000 producing wells in 6 core operating areas
LINN provides investors with significant organic growth
o ~30% growth from 2010 vs. 2011
o ~20% growth from 2011 vs. 2012E
Typically look to hedge ~100% of oil and natural gas production for 4 – 6 years in order to “lock-in” commodity prices and capture significant margins
Unique hedging structure utilizing ~30% puts allows for significant upside potential
6
Low Cost of Capital
LINN has a unique cost of capital advantage
o This allows us to consolidate low-risk assets and still generate significant returns
o Our structure gives us one of the lowest costs of equity capital in the E&P industry
“LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.”
Note: Pro forma for closed 2012 acquisitions and joint venture. (1) Includes 15 acquisitions comprising the Appalachian Basin properties sold in July 2008.
Rank Master Limited Partnership Enterprise Value ($MM) Rank Independent E&Ps Enterprise Value ($MM)
1. Enterprise Products Partners $63,392 1. ConocoPhillips $91,8842. Kinder Morgan Energy Partners $41,982 2. Occidental Petroleum Corp. $72,9143. Energy Transfer Equity $38,716 3. Anadarko Petroleum Corp. $48,0184. Williams Partners $26,901 4. Apache Corp. $44,9325. Plains All American Pipeline $21,746 5. EOG Resources Inc. $34,9886. Energy Transfer Partners $20,598 6. Chesapeake Energy Corp. $31,2847. ONEOK Partners $16,537 7. Devon Energy Corporation $28,0308. LINN Energy LLC(1) $14,976 8. Marathon Oil Corporation $25,6589. Enbridge Energy Partners $14,600 9. Noble Energy Inc. $19,858
10. El Paso Pipeline Partners $12,565 10. Continental Resources Inc. $16,15511. Magellan Midstream Partners $11,806 11. Pioneer Natural Resources Co. $15,99512. Boardwalk Pipeline Partners $9,576 12. LINN Energy LLC(1) $14,97613. Markwest Energy Partners $8,293 13. Range Resources Corp. $13,97614. Buckeye Partners $6,745 14. Southwestern Energy Co. $13,77115. Nustar Energy LP $6,534 15. Concho Resources Inc. $12,43816. Amerigas Partners $6,382 16. EQT Corp. $11,04817. Sunoco Logistics Partners $6,304 17. Cabot Oil & Gas Corp. $10,35218. Access Midstream Partners $6,137 18. Murphy Oil Corp. $10,07919. Cheniere Energy Partners $6,099 19. Denbury Resources Inc. $9,27220. Regency Energy Partners $5,848 20. Plains Exploration & Production $8,32321. Western Gas Partners $5,778 21. Cobalt International Energy $8,27722. Targa Resources Partners $5,444 22. Sandridge Energy Inc. $8,14023. Teekay LNG Partners $4,981 23. QEP Resources Inc. $7,39824. Inergy LP $4,318 24. Newfield Exploration Co. $7,16725. Teekay Offshore Partners $4,075 25. Whiting Petroleum Corp. $6,995
MLP and Independent E&P Rankings
Note: Market data as of September 28, 2012 (LINE closing price of $41.24). Source: Bloomberg. (1) Pro forma for ~$1,250 million LNCO IPO and Jonah Field acquisition.
LINN is one of the largest MLP and independent E&P companies 8th largest public MLP/LLC
12th largest domestic independent oil & natural gas company
7
Growth Through Accretive Acquisitions
Value of Acquisitions Per Year (1)
8
~$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 closed 2012 acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV.
(2)
$452
$2,627
$601
$1,367
$1,513
$2,800
$52 $78 $202$654
$3,281$3,882 $4,000
$5,367
$6,880
$9,680
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
$10,000
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 YTD
($'s
in m
illio
ns)
Cumulative Acquisitions Acquisitions Completed In Year
Jonah Field Acquisition From BP
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 DCF / unit(1)
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.
(1) Distributable cash flow per unit.
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 2010Year
Barr
els
Oil
per D
ay
PrimarySecondaryTertiary
19.9% 9.9% 24.4%
Oil Fields Natural Gas Fields
CO2 Pipelines
Natural Gas Pipelines
On April 3, 2012, LINN acquired 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 From BP
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.
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 net
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)
Well Status Operated Non-Operated
Producing 111 32
Drilling 8 2
Waiting on Completion 10 2
Completing 1 1
Total 130 37
Note: Well counts as of July 8, 2012. 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
Over 600 horizontal locations
Expect to drill or participate in 81 horizontal wells in 2012
Successfully completed 12 Hogshooter oil wells YTD
Average IP rates of ~2,110 Bbls/d of oil
8 rig drilling program currently focused primarily on Hogshooter
Plan to drill an additional 11 Hogshooter wells by year-end
LINN’s Unique Position In The Granite Wash
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
GRANITE
WASH
WASH
ATOKA
DES
MOINESIAN
LATERAL BOREHOLESVIR-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
1,000
YE09 YE10 YE11 2012E 2013E 2014E 2015E
Prod
uctio
n (M
Mcf
e/d)
LINN Base Closed 2012 Acquisitions Potential Organic Growth
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) LINN Energy, LLC estimate. (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. (4) Based on contract price for closed 2012 acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV.
2012E Exit Rate of >800 MMcfe/d(1)
LinnCo Structure and Financial Highlights
LinnCo Structure
16
Existing LINE Unitholders
LINN Energy, LLC
LLC Units
LinnCo Shareholders
LinnCo
Common Shares
Current distribution of $2.90 / unit(1)
Schedule K-1 (partnership)
LINE LNCO
Estimated dividend of $2.84 / share(2)
Form 1099 (C-Corp.)
LLC Units
Investors now have the ability to own LINN Energy two ways: LINE (Partnership for tax purposes / K-1) LNCO (C-Corp. for tax purposes / 1099)
$2.90 Distribution
$2.90 Distribution
$2.84 Dividend
(1) Represents annualized distribution based on Q2’12 distribution of $0.725 per unit paid August 14, 2012. (2) Represents annualized dividend based on current projections for the period ending December 31, 2013.
LinnCo Structure – Advantages
17
Shareholders receive Form 1099 rather than
a Schedule K-1
No state income tax filing requirements
Generally, no UBTI(1) implications
Reduces Tax Reporting Burdens
Tax-shield at LINN Energy, LLC
o 100%+ from 2010 – 2011 (actual)
o 100%+ from 2012 – 2013 (estimated)(2)
Estimated tax at LNCO
o ~1.5¢ / quarter from Q4’12 through Q4’13(2)
Efficient Tax Structure
(1) Unrelated business taxable income. (2) Based on current projections.
LinnCo Structure – Overview
18
LinnCo Overview Provides a simple and fair structure
o 1 LinnCo share = 1 vote of LINN unit o Similar economic interest o LinnCo Board and officers mirror LINN
Sole purpose of LinnCo is to own LINN units o Cannot own oil and natural gas assets or incur debt
LinnCo will distribute LINN distributions it receives to LinnCo shareholders in the form of a dividend, net of reserves for corporate income tax
Transaction Overview Net proceeds will be used to purchase an equal number of LINN units
o LINN will use net proceeds to repay debt outstanding under its revolving credit facility
Post IPO, LinnCo shareholders will own ~13% of LINN(1)
(1) Based on ~$1,250 million offering and LNCO price of $41.24 (LINN’s closing price as of September 28, 2012).
7.0%
0.4%
1.6%2.1%
3.1% 3.3%
3.9% 4.0%
5.8%
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
LINE E&P 10-Yr. Treasury
S&P 500 TRGP FTSE NAREIT
Index
KMI S&P 500 Utilities Index
Alerian MLP Index
Cur
rent
Yie
ldAttractive Valuation
LINN represents an attractive value relative to other yield segments
19
(1)
Note: Market data as of September 28, 2012 (LINE closing price of $41.24). Source: Bloomberg. (1) E&P yield represents average for domestic, independent oil and natural gas companies traded on the NYSE and NASDAQ Global Select Market (excluding MLPs and Royalty Trusts).
Current Yields
Financial Highlights Recently increased 2012 guidance(1)
Increased Q3 guidance: o Production +2%
o EBITDA +4%
o Distribution coverage ratio +12% to 1.25x
Estimates positively impacted by NGL prices and recent organic drilling results
Distribution growth of ~15% since 2010; 81% increase since IPO Excellent acquisition track record (~$5.7 billion since 2010)
~$1.4 billion(2) in 2010
~$1.5 billion(2) in 2011
~$2.8 billion(3) in 2012
Significant organic growth ~30% growth from 2010 vs. 2011
~20% growth from 2011 vs. 2012E
LinnCo IPO has the potential to be a game-changer in terms of access to equity capital Pro forma balance sheet positioned for future growth
Industry leading hedge position Hedged ~100% of expected natural gas production through 2017 at attractive prices
Hedged ~100% of expected oil production through 2016 at attractive prices (1) Estimates based on third quarter and full-year 2012 guidance updated on September 27, 2012. (2) Based on total consideration. (3) Based on contract price for closed 2012 acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV.
20
$1,367 $1,513
$2,800
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
2010 2011 2012 YTD
($'s
in m
illio
ns)
LINN Has Created an Acquisition Machine
Screened 189 opportunities
Bid 41 for ~$10.1 billion
Closed 13 for ~$1.4 billion(1)
Screened 122 opportunities
Bid 31 for ~$7.5 billion
Closed 12 for ~$1.5 billion(1)
(1) Based on total consideration. (2) Based on contract price for closed 2012 acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV. (3) As of September 21, 2012.
(1) (2)
Total ~$5.7 Billion Since 2010
Historical Acquisitions and Joint Venture
(1)
21
Screened 186 opportunities
Bid 12 for ~$6.2 billion
Closed 4 for ~$2.8 billion(2)
2010 2011 2012 YTD(3)
Note: Data reflects continuing operations only. The results of the Company’s Appalachian Basin and Mid Atlantic operations are classified as discontinued. (1) As of December 31, 2011, pro forma (“PF”) for closed 2012 acquisitions and joint venture. (2) Production estimate based on the mid-point of full-year 2012 guidance updated on September 27, 2012. (3) Adjusted EBITDA based on full-year 2012 guidance updated on September 27, 2012. (4) Annualized distribution based on Q2’12 distribution of $0.725 per unit paid August 14, 2012.
Adjusted EBITDA ($ in millions)
Strong Performance and Growth
$514 $566
$732
$998
$1,365
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2008 2009 2010 2011 2012E
Reserves (Bcfe)
255
1,419 1,660 1,712
2,597
3,370
5,067
0
1,000
2,000
3,000
4,000
5,000
6,000
2006 2007 2008 2009 2010 2011 2012PF
Production (MMcfe/d)
8
87
212 218 265
369
673
0
100
200
300
400
500
600
700
800
2006 2007 2008 2009 2010 2011 2012E
Annualized Distributions ($ per unit)
$1.60
$2.28
$2.52 $2.52 $2.52
$2.76 $2.90
$1.00
$1.50
$2.00
$2.50
$3.00
Q2 '06 Q2 '07 Q2 '08 Q2 '09 Q2 '10 Q2 '11 Q2 '12
(3)
(2) (1)
22
(4)
Natural Gas Positions
Percent Puts (3) Swaps Puts (2)
Volu
mes
(Bbl
s/d)
23
LINN is hedged ~100% on expected natural gas production through 2017; and ~100% on expected oil production through 2016
Puts provide price upside opportunity
Volu
mes
(MM
cf/d
)
Oil Positions
Percent Puts (3) Swaps (4) Puts
Note: Except as otherwise indicated, illustrations represent full-year natural gas hedge positions through 2017 and oil positions through 2016, as of August 1, 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
Significant Hedge Position
64% 63% 65%70% 69%
54%
36%37% 35% 30% 31%
25%
100% 100% 100% 100% 100%
79%
66%
47%
20%
4% 1% 1%
88%
71%
49%
29%
16%9%
0%
20%
40%
60%
80%
100%
2012 2013 2014 2015 2016 2017
Expe
cted
Pro
duct
ion
Hedg
ed
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. Source: Production estimates based on Bloomberg consensus, and hedge information based on publicly available sources. (1) Represents simple average and peer group includes: CLR, FST, XEC, KWK, NFX, PXD, PXP, RRC, SWN and WLL. (2) Represents simple average and peer group includes: BBEP, EVEP, LGCY, LRE, MEMP, MCEP, PSE, QRE and VNR.
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 commodity prices could put further pressure on E&P C-Corps.
Significant Hedge Position (Equivalent Basis)
% Swaps % Puts
24
Upstream MLP Peers % Hedged (1) (2)
$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
$180
Natural Gas ($/M
MBtu)
Oil
($/B
bl)
Distribution Stability and Growth
25
Distribution History
2006 2007 2008 2009
(2)
2010
Stability During Credit Crisis
2011
LINN has performed well through all kinds of commodity price cycles 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 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.
2012
0.400.43
0.520.52
0.570.57
0.630.63
0.630.63
0.630.63
0.630.63
0.630.63
0.630.66
0.660.66
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
Distribution History
26
Quarterly Distribution Cumulative Distribution
2006 2007 2008 2009
(1)
2010
Consistently paid the distribution for 26 quarters 81% increase in quarterly distribution since IPO
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
Note: Market data as of September 28, 2012 (LINE closing price of $41.24). Source: Bloomberg.
LINN Total Return and Stock Price Appreciation (LINE IPO – Present of ~255%)
LINN Historical Return
27
~29% ~18%
~96%
~156%
~255%
(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
EV Energy
Vanguard
BreitBurn
Legacy
QR Energy
Atlas Resources
Pioneer LRR Energy
Mid-Con Energy Memorial Production $15.0 Billion $15.7 Billion
$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
$14.0
$16.0
LINE All Others (10 MLPs)
Ente
rpris
e Va
lue
($B
)
E&P MLP/LLC
6%
All Others94%
28
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; $31 billion versus $447 billion for all other sectors
LINE vs. Other Upstream MLPs(1) MLP/LLC Total EV: $478 Billion(3)
$31 Billion
$447 Billion
Note: Market data as of September 28, 2012 (LINE closing price of $41.24). Source: Bloomberg. (1) Excludes Constellation Energy Partners and Dorchester Minerals LP. (2) Pro forma for ~$1,250 million LNCO IPO and Jonah Field acquisition. (3) Includes all U.S. energy MLPs recognized by the National Association of Publically Traded Partnerships (NAPTP).
(2)
29
Why Invest in LINN?
High quality asset base o Multi-year inventory of high-return development opportunities o Long-life reserves (~21 years) o Diversified asset base (6 core areas / >15,000 gross producing wells)
Extensive hedge positions; reduced commodity risk
Organic growth (YOY ~20% in 2012E vs. 2011) Acquisitions
o Excellent acquisition track record (54 transactions for ~$10 billion) o ~$1.4 billion(1) completed in 2010 o ~$1.5 billion(1) completed in 2011 o ~$2.8 billion(2) completed in 2012
LinnCo IPO has the potential to be a game-changer in terms of access to equity capital
First in class track record in capital markets o Total capital raised since IPO:
Stable Distributions
Distributions Growth Drivers
Financial Strength
Note: All operational and reserve data as of December 31, 2011, pro forma for closed 2012 acquisitions and joint venture. Estimates of proved reserves for closed 2012 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. (2) Based on contract price for closed 2012 acquisitions and $400 million of Anadarko’s development costs related to the Salt Creek JV. (3) Pro forma for ~$1,250 million LNCO IPO.
$6.4 billion of equity(3)
$5.4 billion of bonds
$11.8 billion total
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.
31 Note: All operational and reserve data as of December 31, 2011, pro forma for closed 2012 acquisitions and joint venture (“JV”). Estimates of proved reserves for 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 closed 2012 acquisitions and JV based solely on data provided by seller. (1) Includes Mid-Continent, Hugoton Basin and East Texas.
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
• 32 MMBoe proved reserves • 4% of total reserves • 93% liquids
Jonah Field
• 730 Bcfe proved reserves • 15% of total reserves • 73% natural gas
Permian Basin
• 88 MMBoe proved reserves • 10% of total reserves • 79% liquids
Michigan / Illinois
• 317 Bcfe proved reserves • 6% of total reserves • 96% natural gas
LINN Operations 2012 Acquisitions / Joint Venture
Salt Creek Field
LINN Overview
TX Panhandle Granite Wash
TX Panhandle Shallow
Jonah Field
Mid-Continent(1)
• 3.1 Tcfe proved reserves • 61% of total reserves • 59% natural gas
LinnCo – Overview of Tax Considerations
32
LinnCo subject to corporate-level taxation on income allocation from LINN (35%)
LinnCo expected to receive tax shield in excess of 100%
However, LinnCo expected to pay taxes due to alternative minimum tax (AMT)
Income tax liability estimated to be between 2% – 5% of LINN’s cash distribution to LinnCo for the next 3 years (2012 – 2015)
Taxation at LinnCo
Shareholder Level
Taxation at LinnCo Level
Distributions from LinnCo to its shareholders treated as dividends to the extent that LinnCo has earnings and profits
o Taxed at dividend tax rate (currently 15%)
Distributions in excess of earnings and profits, treated as return of capital and reduce the basis in LinnCo shares
o Percentage of distributions treated as return of capital expected to be between 40% – 100% through 2015
Calculation of earnings and profits different from income allocation (on traditional MLP unit)
o Generally higher than income allocation as items such as accelerated depreciation and current deduction of IDC’s not allowed
LINN Units vs. LinnCo Shares
Business & Assets
Taxation Schedule
Voting
Board of Directors
LINN is in the business of acquiring and developing oil and natural gas assets
Unitholders have the right to vote with respect to:
o LINN’s Board of Directors
o Certain amendments to its limited liability company agreement
o Potential merger of LINN or the sale of all or substantially all of its assets
o Potential dissolution and / or winding-up of LINN
LINN Board of Directors provides oversight to LINN’s management and has the power to appoint LINN’s officers
Unitholders receive a Schedule K-1
33
LINN LinnCo
LinnCo’s sole purpose is to own LINN units
Will not own any other assets besides LINN units and reserves for income taxes payable by LinnCo
No leverage allowed
LinnCo will submit to a vote of its shareholders any matter submitted by LINN to a vote of its unitholders (including election of LINN’s Board of Directors)
LinnCo will vote the LINN units which it holds in the same manner as the owners of LinnCo shares vote
LINN, as the holder of LinnCo’s sole voting share, will have the sole right to elect the members of LinnCo’s Board of Directors
Shareholders receive a Form 1099-DIV
LINN Structure & Benefits
34
Characteristic LINN Energy(LINE)
TypicalMLP
LinnCo, LLC(LNCO)
TypicalC-Corp.
Non-Taxable Entity
Payout Distribution Distribution Dividend Dividend
Tax Reporting Schedule K-1 Schedule K-1 Form 1099 Form 1099
General Partner
Incentive DistributionRights (IDRs)
(Up to 50%)
Voting Rights
Ensuring Liquids Delivery In The Granite Wash
35
Gathering system provides accessibility to numerous processing facilities Multiple interconnects ensures take-away capacity
Exposure to multiple processing plants leads to superior pricing
Extending 43 miles in 2012
Frontier & DCP
Markwest
Enbridge
DYCO
FRYE RANCH
STILES RANCH Wheeler County
Hemphill County
Markwest Enbridge
Eagle Rock
Eagle Rock Woodall Plant
Frontier
Enbridge Allison Plant
BUFFALO WALLOW
TWO STEP
Enbridge
Enbridge Ajax Plant
Eagle Rock Wheeler Plant Markwest
PVR
Enogex
Crestwood
Eagle Rock
Enbridge
Enbridge
Completed Pipeline
LINN Acreage
Expanding GW Capacity
2012 Pipeline
2012 Compressor Stations
0 1 mile
Enogex Fort Elliott Plant
Interconnect
TX
TX
NMEddyLea
Hockley
Dawson
AndrewsHoward
EctorWinkler
Upton
SchieicherPecos
CraneWard
Crockett
Midland
Martin
Garza
Shackleford
Stonewall
Irion
Permian Basin
36
Strategic entry in 2009
Long-life, low-risk reserves 88 MMBoe proved reserves
79% liquids (~56% proved developed)
Reserve life ~18 years
Growth opportunities
~400 proved low-risk infill-drilling and optimization opportunities in the Wolfberry
Potential for additional bolt-on acquisitions
Recent activity and average results IP rates: ~120 Boe/d
EURs: ~125 MBoe
Rate of returns: ~40%+
Note: All operational and reserve data as of December 31, 2011.
02468
10121416
MB
bls/
d
Permian Production Growth
MONTHS
LINN Fields
Wolfberry Trend
TX
NM
Drilling in the Wolfberry
37
Leonard Shelf Carbonates
Wolfcamp Shelf Carbonates
Spraberry Turbidites (primary target)
Wolfcamp (primary target)
Eastern Shelf
10,500’
8,500’
Central Basin Platform A B
S p r a b e r r y
W o l f c a m p
WESTERN WELL EASTERN WELL
P E R M I A N
P E N N M S
Spraberry
Wolfcamp
Cisco Canyon Strawn
Mississippian
Vertical well development
Multi-stage fracture stimulation
Emerging horizontal well development
Targeting deeper zones
Infill potential
Note: All operational and reserve data as of December 31, 2011.
Strategic entry into premier oil basin in 2011 Non-operated position with high quality
operators
Offers high rates of return
Significant growth potential
Additional consolidation opportunities
Current position ~14 MMBoe proved reserves
~17,000 net acres
91% liquids
48% proved developed
~7% average working interest
Growth opportunities ~800 future drilling opportunities
Current activity and average results IP rates: ~1,000 Boe/d
EURs: ~500 MBoe
Rate of returns: ~50%
Williston Basin – Bakken Play
Note: All operational and reserve data as of December 31, 2011.
FEET
0 18,970’
Williams
Mountrail
McKenzie
Dunn
North Dakota
LINN Acreage
Capital Activity
Westberg Area
Sanish Bay Area
38
California Overview
39
34 35 36 31
T2S R10W T2S R9W
T3S R9W T3S R10W
32
03 02 01 06 05
10 11 12 07 08
Brea Canyon Area
Tonner Area
LINN Acreage
Oil Wells
Brea-Olinda Field
Brea-Olinda field of the Los Angeles Basin
Discovered in 1880
Cumulative production of over 400 MMBoe
Long-life, low-risk reserves 4% of total proved reserves 93% oil (93% proved developed) Reserve life of ~38 years Low decline rates of ~3% per year ~320 productive oil wells
o 100% operated
Gas converted to electricity to power field, reducing operating expenses
Acreage position ~4,000 net acres ~4,000 net developed acres
Los Angeles
10
Brea-Olinda Field
Michigan Overview
40
Long-life, low-decline natural gas asset 317 Bcfe of proved reserves
91% proved developed
6% decline rate
~24 year reserve life
6% of total reserves
Located in the Antrim Shale in Michigan ~220,000 net acres
~200,000 net developed acres
Produces at shallow depths of 600-2,200 feet
Potential development drilling, workover, and recompletion opportunities could provide further upside
>26,000 net acres prospective for the Utica-Collingwood Shale
Alcona
Alpena Antrim
Arenac
Barry
Bay
Clare
Crawford Grand Traverse
Isabella
Jackson
Lake
Manistee
Mecosta Newaygo
Oceana
Ogemaw
Osceola
Oscoda
Otsego
Tuscola
Wexford
Traverse City
Lewiston
Mont- morency
Michigan
Overton Field Acquisition
41
Strategic entry into East Texas natural gas field
Long-life, low-decline natural gas asset
100% held by production
Concentrated acreage position
Multiple identified upside recompletion and infill-drilling opportunities
Immediately accretive to DCF / unit
Strategic Rationale
Asset Overview
~24 MMcfe/d of production
~97% natural gas
Low decline rate of <10% and reserve life of ~15 years
Highly developed proved reserves of ~136 Bcfe
100% PDP
~430 wells on ~19,800 contiguous net acres
Located in Smith & Cherokee Counties, Texas
0 4,000’ 8,000’
FEET
Smith County
Cherokee County
Acquisition Acreage
TX Cherokee
Smith
On May 1, 2012, LINN closed a $175 million acquisition in the prolific Overton Field in
East Texas from Southwestern Energy.
Financial Appendix
43
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) - 806 806 27% 53% 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 1,737 5,107 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 $3.02/MMBtu for natural gas and $94.81/Bbl for oil, which represents the unweighted average of the first-day-of-the-month prices for each of the twelve months ending July 1, 2012, the most recent twelve-month period prior to the closing of the Green River 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
44
The following presents a reconciliation of net loss to adjusted EBITDA:
Historical Financial Statements Adjusted EBITDA
45
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
46
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) 47
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 LINN Energy’s Annual Report on Form 10-K for the year ended December 31, 2011, available from LINN Energy 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.
48