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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.
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
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
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 $400 million of Anadarko’s development costs related to the Salt Creek JV.                                  6
 (3)   As of August 3, 2012.
MLP and Independent E&P Rankings
        LINN is quickly becoming one of the largest MLP and independent E&P companies
             − 8th largest public MLP/LLC
             − 8th largest domestic independent oil & natural gas company
     Rank        Master Limited Partnership                             Enterprise Value ($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
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.
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
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.
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
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
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
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.
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
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.
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.
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
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.
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.
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
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.
Financial Appendix
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
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
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
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
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

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Linn Energy - EnerCom Oil & Gas Conference

  • 2. EnerCom Oil & Gas Conference Denver, CO
  • 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