EnerCom Oil & Gas Conference          Denver, CO
Forward-Looking Statementsand Risk FactorsStatements made in these presentation slides and by representatives of LinnEnerg...
LINN Overview 8th largest public MLP/LLC and 8th largest  domestic independent oil & natural gas company     IPO in 2006...
Growth Through Accretive Acquisitions  ~$10 billion in acquisitions completed since the Company’s inception            I...
Continued Success in Acquisition Activity Record amount of                                                   Record amou...
MLP and Independent E&P Rankings        LINN is quickly becoming one of the largest MLP and independent E&P companies    ...
Distribution History   Consistently paid the distribution for 26 quarters   81% increase in quarterly distribution since...
Jonah Field Acquisition ProvidesSignificant Upside Potential On July 31, 2012, LINN closed a $1.025 billion               ...
Anadarko Salt Creek Joint-VentureOn April 3, 2012, LINN received 23% of Anadarko’s(“APC”) interest in the Salt Creek field...
Hugoton Field Acquisition Fits The MLP ModelOn March 30, 2012, LINN closed a $1.2 billion acquisition in the liquids-rich ...
Granite Wash – Operated HorizontalDrilling Activity (Greater Stiles Ranch) Successfully completed three                  ...
LINN’s Unique Position In TheGranite Wash Over 600 horizontal  drilling locations                Granite Wash / Atoka Was...
LINN Provides Both Organic    & Acquisition Growth LINN is unique in that it provides investors with the potential for si...
Significant Hedge Position    LINN is hedged ~100% on expected natural gas production through 2017; and                  ...
Significant Hedge Position (Equivalent Basis)     LINN’s cash flow is notably more protected from oil and natural gas pri...
Distribution Stability and Growth         81% increase in quarterly distribution since IPO         Distribution stabilit...
LINN Historical Return         LINN Total Return and Stock Price Appreciation (LINE IPO – Present of ~231%) 250%          ...
Size Advantage in E&P MLP/LLC Market LINN has a significant size advantage in the                                        ...
Why Invest in LINN?                                                               − High quality asset base               ...
LINN Energy’ mission is to acquire,              sdevelop and maximize cash flowfrom a growing portfolio of long-life   Em...
LINN Overview                                                                        Salt Creek Field                     ...
Financial Appendix
Proved Reserves   The following table sets forth certain information with respect to LINN’s proved reserves at December 31...
Historical Financial StatementsReconciliation of Non-GAAP Measures The Company defines adjusted EBITDA as net income (los...
Historical Financial Statements Adjusted EBITDA The following presents a reconciliation of net loss to adjusted EBITDA:  ...
Historical Financial StatementsAdjusted Net Income The following presents a reconciliation of net loss to adjusted net in...
Reserve Replacement / F&D CalculationsReconciliation of Non-GAAP Measures                                                 ...
The U.S. Securities and Exchange Commission (“SEC”) permits oil and gas companies, in their filings with theSEC, to disclo...
Linn Energy - EnerCom Oil & Gas Conference
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Linn Energy - EnerCom Oil & Gas Conference

  1. 1. EnerCom Oil & Gas Conference Denver, CO
  2. 2. Forward-Looking Statementsand Risk FactorsStatements made in these presentation slides and by representatives of LinnEnergy, LLC during the course of this presentation that are not historical facts areforward-looking statements. These statements are based on certain assumptionsand expectations made by the Company which reflect management’s experience,estimates and perception of historical trends, current conditions, anticipated futuredevelopments, potential for reserves and drilling, completion of current and futureacquisitions, future distributions, future growth, benefits of acquisitions, futurecompetitive position and other factors believed to be appropriate. Such statementsare subject to a number of assumptions, risks and uncertainties, many of which arebeyond the control of the Company, which may cause actual results to differmaterially from those implied or anticipated in the forward-looking statements.These include risks relating to financial performance and results, our indebtednessunder our credit facility and Senior Notes, access to capital markets, availability ofsufficient cash flow to pay distributions and execute our business plan, prices anddemand for natural gas, oil and natural gas liquids, our ability to replace reservesand efficiently develop our current reserves, our ability to make acquisitions oneconomically acceptable terms, regulation, availability of connections andequipment and other important factors that could cause actual results to differmaterially 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 otherpublic filings. Linn Energy undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. Themarket data in this presentation has been prepared as of July 27, 2012, exceptotherwise noted.
  3. 3. 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
  4. 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
  5. 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 $400 million of Anadarko’s development costs related to the Salt Creek JV. 6 (3) As of August 3, 2012.
  6. 6. MLP and Independent E&P Rankings LINN is quickly becoming one of the largest MLP and independent E&P companies − 8th largest public MLP/LLC − 8th largest domestic independent oil & natural gas company Rank Master Limited Partnership Enterprise Value ($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. $5,569Note: Market data as of July 27, 2012 (LINE closing price of $39.15).Source: Bloomberg. 7
  7. 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 Companys closing of the IPO on January 19, 2006 through March 31, 2006, equates to $0.32 per unit.
  8. 8. Jonah Field Acquisition ProvidesSignificant Upside Potential On July 31, 2012, LINN closed a $1.025 billion Sheridanacquisition 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
  9. 9. Anadarko Salt Creek Joint-VentureOn 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.
  10. 10. Hugoton Field Acquisition Fits The MLP ModelOn 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
  11. 11. Granite Wash – Operated HorizontalDrilling 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
  12. 12. LINN’s Unique Position In TheGranite 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
  13. 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 PotentialProduction (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.
  14. 14. 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% $5.00Volumes (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
  15. 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.
  16. 16. 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 $12Oil ($/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 Companys 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.
  17. 17. 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 IndexNote: Market data as of July 27, 2012 (LINE closing price of $39.15). Source: Bloomberg. 18
  18. 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.
  19. 19. Why Invest in LINN? − High quality asset base  Multi-year inventory of liquids-rich development opportunitiesStable  45% liquidsDistributions  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 yearNote: 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.
  20. 20. LINN Energy’ mission is to acquire, sdevelop and maximize cash flowfrom a growing portfolio of long-life Embrace & Drive Changeoil and natural gas assets. Pursue Growth Take Action Respect Others Be Passionate Connect
  21. 21. 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 gasNote: 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.
  22. 22. Financial Appendix
  23. 23. 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
  24. 24. Historical Financial StatementsReconciliation 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
  25. 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
  26. 26. Historical Financial StatementsAdjusted 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
  27. 27. Reserve Replacement / F&D CalculationsReconciliation 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
  28. 28. The U.S. Securities and Exchange Commission (“SEC”) permits oil and gas companies, in their filings with theSEC, to disclose only resources that qualify as "reserves" as defined by SEC rules. We use terms describinghydrocarbon quantities in this presentation including “inventory” and “resource potential” that the SEC’s guidelinesprohibit us from including in filings with the SEC. These estimates are by their nature more speculative thanestimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly aresubstantially less certain. Investors are urged to consider closely the reserves disclosures in the Company’sAnnual 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 bycalling 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 Companys internal estimates ofhydrocarbon volumes that may be potentially discovered through exploratory drilling or recovered with additionaldrilling or recovery techniques. Those estimates may be based on economic assumptions with regard tocommodity prices that may differ from the prices required by the SEC to be used in calculating provedreserves. In addition, these hydrocarbon volumes may not constitute reserves within the meaning of the Societyof Petroleum Engineers 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. Factorsaffecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by theavailability of capital, drilling and production costs, commodity prices, availability of drilling services andequipment, 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 Companys interests may differ substantially from theCompany’s estimates of potential resources. In addition, our estimates of reserves may change significantly asdevelopment of the Companys resource plays and prospects provide additional data. 29

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