Merrill Lynch. Global Energy Conference. November 8, David E. Roberts, Jr. Senior Vice President, Business Development

Transcription

1 Merrill Lynch Global Energy Conference November 8, 2007 David E. Roberts, Jr. Senior Vice President, Business Development

2 Forward Looking Statement Except for historical information, this presentation contains forward-looking information with respect to the timing and levels of the company's worldwide liquid hydrocarbon and natural gas production, the Alvheim/Vilje, Volund and other potential developments, exploration and drilling plans, an LNG production facility in Equatorial Guinea and possible expansion thereof, projected LNG sales, expansion plans for Libya, growth in refining capacity, the Garyville refinery expansion project, heavy oil refining upgrading projects, ethanol plant construction, other expansion projects, the Company's gas-to-fuels technology, and the common stock repurchase program. These statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied from such information. In accordance with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its Annual Report on Form 10-K for the year ended December 31, 2006, and subsequent 10-Q and 8-K filings, cautionary language identifying important factors, though not necessarily all such factors, that could cause future outcomes to differ materially from those set forth in the forwardlooking statements. 1 Cautionary Note to U.S. Investors The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose e only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. SEC regulations s classify "mined bitumen" as mining- related and not part of conventional oil and natural gas reserves. s. Marathon Oil Corporation uses certain terms in this presentation, such as total and net resources, that t the SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. Investors are urged to consider closely the disclosures in Marathon's periodic filings with the SEC, available from us at San Felipe, Houston, Texas and the Company's Web site at You can also obtain this information from the SEC by calling SEC SEC-0330.

3 Marathon: Well-Positioned For Success Defined production growth 6-9% through 2010 Building growth beyond 2010 World-class West Africa LNG asset Potential regional gas hub Best-in-class downstream Significant growth opportunities Canadian Oil Sands adds integration value Differentiating technology/major Project skills Financial strength through the cycles 2 Top Quartile TSR Performance

4 Total Shareholder Return September 2004 to September % % Total Shareholder Return 250% 200% 150% 100% 50% 0% VLO MRO OXY HES SUN COP XOM CVX REP TOT RDS/A APC BP Marathon s average closing stock price for September 2004 was $19.37 and the average closing stock price for September 2007 was $ TSR = Share price appreciation + dividends paid

5 Marathon s Business Segments Upstream Downstream Integrated Gas Oil Sands Mining 4

6 Upstream Focus Areas 5 Production Exploration/exploitation

7 Total Resources Growth from Total Resources (Billion BOE) Unproved Proved 0.7 YE Production Dispositions Resource Adds 3.9 YE 2006 Total Oil and Gas Resources = Proved + 70% of probable + 30% of possible Resource growth drives future reserves and production 6

8 Upstream Production Outlook (mboe/d) Net Production (mboe/d) % CAGR Libya re-entry EG-Train 1 Alvheim/Norway Vilje/Norway Neptune/GOM Resource Plays High Side Low Side Corrib/Ireland Volund/Norway Libya Growth Resource Plays Resource Plays E 2008E 2009E 2010E High Low 365 ~ Production growth driven by defined projects 7 CAGR production growth rate referenced to 2006 production Volumes from continuing operations. Does not assume any contribution from future exploration successes or from recently-acquired Canadian oil sands assets.

9 Building Further Growth Beyond 2010 Gulf of Mexico Angola U.S. Resource Plays Libya Norway Indonesia Integrated opportunities Canadian Oil Sands West Africa Gas 8

10 Key Upstream Messages Defined 6-9% production CAGR Dependable base Commissioning new development projects U.S. resource plays will provide new stable production Inventory of development opportunities beyond 2010 Well-defined, profitable and sustainable growth 9

11 Marathon s Integrated Gas Strategy Maximizing Value Through Value Chain Skills Upstream Liquefaction Shipping Re-Gas Historic Returns 15-20% or above 8-12% if tolling 8-10% 8-10% 10-20% otherwise Utility businesses Highest participation in greatest value aspects 10 Source: Wood MacKenzie

12 EG LNG Train 1 Long-Term Cash Flow & Earnings Contributor 3.7 MMTPA LNG facility Marathon 60% WI 17-Year BG agreement 3.4 mmtpa (~487 mmbtu/d) First sales May 2007 FOB Bioko Island, indexed to Henry Hub At $6.00 Henry Hub net back $3.45 per MMBTU Net cash flow to MRO ~ $200 million/year Net income to MRO ~ $180 million/year Major project on-budget and six months early 11

13 EG LNG Train 1 Stable, long-life source of cash & earnings 4 Million Tonnes Per Annum BG Contract 3 TCF certified reserves Train 1 Capacity World-Class Project with Significant Upside 12

14 EG LNG Train 2 The Next Stage to Growth Potential Regional Gas Hub Space for multiple LNG Trains Multiple gas resources Nigeria and Cameroon Discovered EG gas resources Continued EG exploration Government HOA s signed EG - Nigeria EG - Cameroon Bonny 0 K 5 M 0 OML 11 N i g e r i a OML 13 OPL 290 OML 69 Alba Field PSC and Satellite Discoveries Punta Europa Source: IHS, Wood MacKenzie and Marathon internal estimates 13

15 Gas-To-Fuels TM Marathon Proprietary Technology Base patents awarded in 2007 Direct (catalytic) conversion of natural gas to end-use fuels 110+ octane gasoline; diesel ~ 30% cost advantage to current GTL processes (no syngas step) The GTF Advantage Cheaper to build / operate Higher carbon-conversion efficiencies Wider range in resource size applicability (500 BCF+) Demonstrated operations 2 years of lab and pilot tests 10 b/d demo plant under construction Plan forward Demo plant operations / commerciality decision in 2008 Currently seeking resource partners Potential game changing technology 14

16 Key Integrated Gas Messages Ability to execute major IG projects Improves returns through the value chain Investing in potential game-changing technology 15

17 Downstream Operations Refinery Pipeline Terminal Coastal Terminal Inland Terminal St. Paul Park Robinson Detroit Canton Catlettsburg Texas City Garyville LOOP 16 A comprehensive, integrated focus

18 Marathon vs. Competitors Adjusted Downstream Operating Income Before Taxes Per Barrel of Crude Oil Throughput MRO Competitor Average # Rank Among Competitors 2 $/BBL Competitors ranked Source: Company Reports Competitors: BP, COP, CVX, MRO, SUN, TSO, VLO, XOM

19 Garyville Major Expansion - 180,000 B/D Projected $3.2 Billion project 4Q 2009 start-up Leverages MRO s most efficient and profitable downstream asset Ability to process wide crude slate Average annual after tax: Cash Flow ~ $350MM Net Income ~ $225 MM Based on average prices / margins WTI - $31 / BBL WTI Crack - $4.70 / BBL 18

20 E10 Infrastructure Investment April 30, 2007 E10 Ethanol Infrastructure Program June 1, 2008 E10 Ethanol Infrastructure Program Terminals Greenville Ethanol Plant 74% 890mm GPY Poised to enter Southeast 100% 1.2 billion GPY 19

21 Key Downstream Messages Comprehensive integrated value chain Expanding strategic midstream assets Enhancing industry-leading asset in Garyville Pursuing selective biofuel opportunities 20

22 Strategically Located RM&T Business Key Advantage in Canadian Oil Sands Mining Upstream Refining Transportation Marketing Driving upstream entry with downstream solution 21

23 Western Oil Sands Acquisition Strategic Highlights Links world-class Athabasca Oil Sands Project with Marathon s Best-in-Class refining assets Maintains complete ownership and control through the value chain Secures long-life OECD crude for refinery upgrades 2.6 billion net barrels of resource 22

24 Total Resources * Growth from Total Resources (Billion BOE) YE Production Dispositions Resource Adds Canadian Oil Sands Acquisition * Total Resource * Resource growth drives future reserves and production 23 Total Oil and Gas Resources = Proved + 70% of probable + 30% of possible * Includes mining bitumen

25 Net Production Profile Bitumen Exp 4 & Exp 2 & 3 Mbpd 40 Exp 1 20 Muskeg River Mine

26 Major Pipeline Projects To Deliver Canadian Crude Oil Detroit Key Marathon Refineries Major Expansion 25

27 Detroit Heavy Oil Upgrade/Expansion Project Projected $1.9 billion investment Expand capacity to 115,000 b/d Increases COS slate by 80,000 b/d New units include: 28 MBD Coker 35 MMSCFD Hydrogen plant 33 MBD Distillate Hydrotreater Two 140 LTPD sulfur plants 12 MBD Coker naphtha hydrotreater Expands 29 miles of pipeline Expected completion late

28 Midwest Refining vs. Alberta Upgrader Base Assumptions WTI = $60/Bbl Premium Synthetic = WTI = $60/Bbl Diluent = 110% of WTI = $66/Bbl Light/Heavy differential = (0.3 x WTI) + $1 = $19/Bbl Bitumen blend (Dilbit) = WTI light/heavy differential = $41/Bbl Bitumen = [Dilbit (0.3 x Diluent)] / 0.7 = $30.29/Bbl Chicago crack spread = $10/Bbl Alberta hydrogen upgrader = $53k - $63k per daily bbl Detroit heavy oil upgrade + 15% expansion = $22k per daily bbl * * To be comparable to the Alberta hydrogen upgrader the Detroit capital is shown as that applicable to the refinery facility only and excludes pipeline investment 27

29 Oil Sands Illustrative Value Chain $80 $70 $70.00 Product Price (US$/bbl) $60 $50 $40 $30 $30.29 $10.71 Blending Cost $41.00 $19.00 Heavy Diff $60.00 $60.00 $0.00 $10.00 SCO Discount Crack Spread $20 Bitumen Bitumen Blend (Dilbit) Premium Synthetic WTI Refined Products Downstream integration allows capture of entire value chain 28

30 Midwest Solution vs. Alberta Solution Margin per bbl of Bitumen Midwest Refining Solution Alberta Hydrogen Addition Upgrader Value of Products $94.60 Value of Products $63.44 Delivered Feedstocks Delivered Feedstocks Bitumen $30.29 Bitumen $30.29 Diluent $28.29 Transportation & Operating Costs $14.28 Blend/Op/Trans Costs $13.61 Operating Margin/bbl $21.74 Operating Margin/bbl $19.54 Capital Charge * Capital Charge * Base Refinery & Coker Capital $18.00 Hydrogen Addition Upgrader $19.25 Margin per bbl Bitumen $3.74 Margin per bbl Bitumen $0.29 Total cost advantage of Midwest Solution ~ $3.50 per barrel 29 * Capital charge includes allowance for 10% project return

31 Key Oil Sands Mining Messages Strategically positioned downstream for added value Pursuing step-change in heavy oil upgrading Long-life stable production Resource upside 30

32 Marathon Delivering Shareholder Value Focused on delivering top quartile TSR Integrated solutions broaden opportunity set Financial strength to fund program in volatile price environment Defined growth across all segments 31

33 Defined Growth Across All Segments Strong upstream volume growth and margins World-class LNG facility with significant growth potential Best-in-class downstream with solid growth opportunities Upstream Production 6-9% CAGR LNG Sales >400% Refinery Capacity 18% MBOE/D MMTPA MB/D 32 Marathon: well positioned for a strong future

34 Appendix

35 Improved Net Income per BOE Ranking Peer Group Marathon Income ($/BOE) MRO Rank 8/12 6/12 7/12 5/11 4/9* 34 Source: Marathon internal report based on company 10-K s and earnings releases, excludes certain UK mark-to-market gas sales contract activities *Peer group includes: BP, COP, OXY, HES, CVX, RDS, MRO, MUR, XOM

36 Exploration Results, (Excludes Exploitation) # of Discoveries Resources Added Finding Cost Success Rate mmboe $ / boe ~60% ~650 mmboe* ~$1.90 / boe* >60% * Including exploitation, resource adds of ~765 mmboe at a finding cost of ~$2.15/boe Production from Exploration discoveries >120 mboe/d in

37 Reserve Replacement and F&D Costs Outstanding Reserve Replacement Reserve Additions (MMBOE) Reserve Replacement (%) F&D Cost ($/BOE) Reserves 12/31/01 of 1.05 Billion BOE Reserves 12/31/06 of 1.26 Billion BOE 36 Reserve replacement ratio: Net Reserve Additions / Net Production, including discontinued operations. Reserve additions exclude dispositions. F&D Cost includes Asset Retirement Obligation costs.

38 Building Further Growth Beyond 2010 Gulf of Mexico 37

39 Droshky Development 100% WI Bullwinkle mmboe resource Degree API oil Feasibility engineering underway Potential 4 to 6 development wells Development options: Subsea completion, tie-back through Troika facility (MRO 50%) Evaluating other tie-back options First production Aspen Troika Droshky GC 244 ~2,900 WD 38

40 Stones Appraisal Program Walker Ridge Area 30% WI 2005 Lower Tertiary discovery 10 Block exploration unit Appraisal to spud late 2007 Very large structural closure 2008 Potential next steps Well test and/or Drill southwest prospect Edge of Salt Appraisal Location ~ 9000 W.D. Additional Exploration Well Exploration Unit Discovery Well #1 LKO Spill Point 39

41 Building Further Growth Beyond 2010 Gulf of Mexico Angola 40

42 Angola Moving Discoveries to Production 25 Discoveries announced 4 Potential development hubs Progressing developments Block 31NE Block 31 SE Block 31 Mid Block 32 Eastern Significant production potential Potential NE Development Area Terra BLOCK 31 10% WI Titania Miranda Cordelia Potential Mid Development Area Urano Potential SE Development Area BLOCK 32 30% WI Marte Plutao Potential Eastern Development Area Venus Saturno Ceres Hebe Juno Palas Colorau Manjericao Caril Astraea Canela Gengibre Mostarda Louro Salsa MRO Acreage Oil Discovery Cominhos Gindungo 41

43 Building Further Growth Beyond 2010 Gulf of Mexico Angola U.S. Resource Plays 42

44 U.S. Resource Plays Bakken, Piceance and Barnett Exposure to ~250 mmboe net resources Net production ~50 mboe/d by 2012 Leverages Marathon core technical competencies Drilling and completions Reservoir characterization Project execution 43

45 U.S. Bakken Shale Unconventional Resource Development Saskatchewan, Canada MONTANA NORTH DAKOTA Odysseus Cassandra Williston Yellowstone Myrmidon MRO Acreage Areas of Evaluation Cazador ~200,000 Net acres Major acreage holder 300 Potential well locations > 100 mmboe net resource Acreage assessment strategy nearing completion Paris Blacktail Ajax Hector Marfa Over 65% of the acreage highly prospective Average well performance IP ~ 300 boe/d Dickinson EUR ~ 380 mboe 44

46 U.S. Bakken Shale Gaining Performance Efficiencies 0 5,000 10,000 Feet 15,000 Industry Average MRO Industry Leading Performance State of the Art automated rigs reducing well cost, cycle times and injuries 25% cost reduction 24 Day reduction in cycle times Safer, more energy efficient performance 20, Days 45 Delivering top tier drilling performance

47 U.S. Bakken Shale Increasing Effective Well Length Ensuring optimum well placement Seismic and geologic models Well Location Horizontal Drilling Single 9000 lateral wells Stimulation techniques Marathon propellant technology Simultaneous fracture stimulation Tiltmeter technology Zone of maximum stimulation during Simultaneous-Fracturing 46 Improved well performance through technology

48 U.S. Piceance Basin Basin Centered Gas Development ~9,000 Acre leasehold ~900 bcf net resource ~100 total wells First well spud July 2007 First production late 2007 Estimated peak net production mmcf/d MRO Acreage Existing Production 47

49 U.S. Piceance Basin Critical Competencies Highly efficient drilling rigs Four new-built rigs by May 2008 Up to 22 wells from one pad Reduced environmental footprint Infrastructure projects & supply chain Water supply & distribution On-site personnel camps Service alliances to minimize costs Year-round operations Gas well unloading 48

50 U.S. Barnett Shale Unconventional Resource Evaluation 80,000 net acres >230 square miles of 3D seismic Drilled 8 wells Tier 2 Tier 1 Core Area Gas content & shale thickness within economic window Completion issue: water in underlying Ellenberger Proprietary seismic processing Karst identification Fault identification Stimulation optimization MRO Excape technology MRO Acreage Existing Production 49

51 Building Further Growth Beyond 2010 Gulf of Mexico Angola U.S. Resource Plays Libya 50

52 Libya 16.33% WI Producing ~345 mboe/d gross Significant development and exploration potential Production optimization Major project developments Faregh Phase II North Gialo NC-98 Dahra Jofra Exploration plan Near-term: Step-outs Mid-term: Fully evaluate Waha acreage Potential mboe/d gross in ~10 yrs Margin terms ~6.5% of net revenue 51

53 Libya Waha Concessions - Gross Production Projection mboe/d Growth Producing Existing Base Projected Growth 52 Growth projects to nearly double production in 10 years

54 Libya Development Projects Faregh Phase II Expansion / N Gialo Field Development Faregh Field Expansion Gas condensate field 1963 Deferred due to lack of gas market 50+ wells drilled to-date Current production 70 mmscf/d and 12 mblhc/d Phase II will increase field gas production by 250 mmscf/d Project currently being implemented Phase II first production scheduled for North Gialo Development Oil reservoir wells drilled to-date Ongoing field studies FEED to be awarded in first production targeted

55 Libya Development Projects NC 98 Development / Dahra Jofra Redevelopment NC 98 Development Gas condensate reservoir appraisal wells to-date Integrated field studies ongoing FEED to be awarded in first production targeted 54 Dahra Jofra Redevelopment Oil reservoir with gas cap 1959 Peaked at 200+ mbo/d in 1964 Field shut-in due to pressure depletion in 1970 Current production 6 mbo/d Cumulative production 600 million STBO Estimated OOIP 5 billion STBO Secondary recovery pilot being evaluated 3-D seismic currently being acquired

56 Building Further Growth Beyond 2010 Gulf of Mexico Angola U.S. Resource Plays Libya Norway 55

57 Norway Alvheim/Vilje Development Alvheim ~65% WI / Vilje 47% WI Subsea infrastructure in place Initial development wells drilled Three wells completed Marathon Lease Gas Field Oil Field FPSO construction complete Currently commissioning vessel FPSO running on ship s power First production expected 1Q 2008 Peak net production ~ 75,000 boe/d in 2008 Brae Gudrun Alvheim Vilje Volund 56

58 Alvheim Area Future Development and Drilling Plans U.K. Norway Peik Boa Kameleon Heimdal Deep Alvheim Kneler South Kneler Volund Alvheim South Gekko Ibsen Vale Vilje Byggve Skirne Byggve South East Heimdal Volund - 65% WI ~6 Mile tie-back to Alvheim Received PDO approval Secured rig - Spud 2008 Initial production 2009 Other inventory includes 5-6 Low-risk prospects 1-3 Higher risk prospects Start drilling in 2008 Marihoene A & B Development or Producing Low Risk Prospect/Discovery Higher Risk Prospects Pipelines 57

59 Building Further Growth Beyond 2010 Gulf of Mexico Angola U.S. Resource Plays Libya Norway Indonesia 58

60 Indonesia Pasangkayu Block 70% WI and operator 1.2 Million acres Signed PSC 3Q Shoot 3D seismic 2008/2009 Drilling Kalimantan Kutei Basin ~ 15 billion boe Marathon Lease Gas Field Oil Field Multiple prospects 200-1,000 mmboe Looking to grow leasehold Area Shown Pasangkayu Block Sulawesi km Indonesia 59 New exploration play to extend a prolific trend

61 Major Downstream Projects Garyville Refinery Crude Unit Expansion Catlettsburg Refinery Repositioning Project Detroit Refinery Expansion Completed 2002 Completed 2004 Completed 2005 Delivering value through project execution 60

62 Marathon Midstream Assets Pipelines Utilized Inland Water Terminal Terminals Utilized Coastal Water Terminal 87 owned and operated terminals, 29 leased light product and asphalt terminals 15 inland waterway tow boats and 184 barges Owns, operates, leases or has interest in 9,900 miles of pipeline 61

63 Marketing Continues to Excel 2006 Gasoline & diesel sales volume up 5.8% Same store: Gasoline & diesel sales volume up 2.1% Merchandise sales up 7.8% Continued growth in diesel volumes and restaurant/merchandise sales 62

64 WTO Acquisition US$6.9 billion* CN$3.8 billion cash (US$3.9 billion) 34.3 million shares Marathon common stock (US$1.9 billion) Debt assumption, ~US$1.1 billion 2.6 Billion Bbls net resource Base - Expansion 5, 1.5 billion Bbls w/ 436 million Bbls Net Proved Mining Bitumen Additional Expansions; 500 million Bbls In-situ leases; 600 million Bbls Resource upside from AMI acreage With acquisition R/P ratio goes from ~9 years to ~12 Proved reserves grow from 1.3 billion to 1.7 billion boe (incl. mining bitumen) Total resource base grows from 3.9 billion boe to 6.5 billion boe * Based on the October 18 midday exchange rate and the average closing Marathon share price for the five-day period around the initial announcement of the Western transaction. 63

65 Athabasca Oil Sands Project (AOSP) Location and Phased Expansions Pierre River Expansions # 6, 7 64 Pierre River Expansions # 4, 5 Current Muskeg River Mine OPS Jackpine Expansions # 2, 3 (Application submitted) Jackpine Expansion # 1 (Approved Mine)

66 Midwest Refining Solution Margin per bbl Bitumen 1.0 bbl Bitumen $30.29 Value of Products Diluent $28.29 Dilbit 70/ bbl Refinery 94.5% Yield Transportation + Opex = $10/bbl Feedstock 1.43 x $70 x 94.5% $ bbl Total cost $ $ $10 (1.43) = $72.86 Operating Margin/Bbl $

67 Alberta Hydrogen Addition Upgrader Margin per bbl Bitumen 1.0 bbl Bitumen $30.29 Alberta Hydrogen Addition Upgrader 103% Yield 1.21 bbls Premium Albian SCO LHM VGO Heavy Albian SCO 1.24 bbls Other Feed/ Blendstocks 0.21 bbl Value of Products $63.44 Other Feed/Blendstocks + Transportation + Overhead + Opex = $13.61/bbl bitumen Total cost $ $13.61 = $43.90 Operating Margin/Bbl $

68 Maximizing Shareholder Value Funding value-accretive growth Maintaining financial flexibility 67

69 Net Debt To Total Capital Net Debt to Total Capital % June Note: All Dates at December 31 unless otherwise noted

70 Maximizing Shareholder Value Funding value-accretive growth Maintaining financial flexibility Paying competitive dividend Raised quarterly dividend 109 percent since July

71 Dividends A History of Growth 0.25 Quarterly Dividend $/share June 2007 Note: All Dates at December 31 unless otherwise noted 70

72 Maximizing Shareholder Value Funded value-accretive growth Maintained financial flexibility Pay competitive dividend Raised quarterly dividend 129 percent Implemented 2 for 1 stock split Return excess cash to shareholders 71

73 Share Repurchases 6,000 5,000 Millions S 4,000 3,000 2,000 1,000 0 Q Q Q Q Q Q Q Authorized Repurchased 72

74 2007 Estimated Annual Sensitivities Upstream +$1/bbl WTI +$0.10/mcf HH $ Million AFIT EPS Effect $ per share Refining, Marketing and Transportation +$0.01/Gallon Refined Product Wholesale Margin +$1/bbl Sweet/Sour Differential +$0.01/Gallon SSA Light Product Margin +$0.50/mcf HH (16) (0.03) 73 Based on estimated ~ 680 million average annual shares outstanding

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