marathon howard weil 2011 energy conference

8/7/2019 Marathon Howard Weil 2011 Energy Conference

http://slidepdf.com/reader/full/marathon-howard-weil-2011-energy-conference 1/95

Howard Weil Energy ConferenceHoward Weil Energy Conference

March 28, 2011

Clarence P. Cazalot, Jr.President and CEO



ForwardForward--Looking StatementLooking Statement

Except for historical information, this presentation contains forward-looking information including, but not limited to, the timing and levels

of the Company's worldwide liquid hydrocarbon and natural gas production, synthetic crude production, Droshky, Ozona, Gunflint, Angola

and other existing and potential development projects, anticipated future exploratory and development drilling activity in Poland and other

countries, potential developments in Indonesia, the possibility of a new significant resource base in Kurdistan, expansion plans for oil sands

’

m n ng, e e ro eavy pgra e pro ec , p ans o move orwar w sp nn ng o ara on orpora on s owns ream us ness

into a separate publically traded company and the capital spending forecast. These statements are subject to risks and uncertainties thatcould 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, 2010, and subsequent 8-K, 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 forward-looking statements.

See definitions of terms used throughout this presentation in the Appendix.

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 only proved, probable, or possible 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. Marathon Oil Corporation uses certain terms in this presentation to refer to reserves other

than proved, probable, or possible reserves, which the SEC’s guidelines strictly prohibit us from including in filings with SEC. These terms include resource base, net resource potential, net unrisked resource potential, gross unrisked potential and other similar terms, which are not yet classified as proved, probable, or possible

reserves. U.S. investors are urged to consider closely the disclosures in Marathon's periodic filings with the SEC, available from us at 5555 San Felipe, Houston, Texas'

an e ompany s we s e a www.mara on.com . ou can a so o a n s n orma on rom e y ca ng - - - .

2



Writing the Next Chapter for The Ohio Oil CompanyWriting the Next Chapter for The Ohio Oil Company

Well positioned versus peers

Strong balance sheets

Experienced and focused management teams

Enhanced flexibility to pursue tailored strategies

Expanded growth opportunities

Superior transparency – improved investor focus

3



Proved ReservesProved ReservesEOY 2010

4,000

3,000

,

1 500

2,000

,

MMBOE

500

1,000

0

OXY APA DVN APC CHK MRO HES EOG ECA TLM NBL MURMRO

13:1 6:1Source: Company annual reportsBOE volume based on 6:1 and 13:1 gas/oil ratioMRO & MUR include Oil Sands Mining Operations

4



Proved ReservesProved Reserves - - % Liquids% LiquidsEOY 2010

100%

80%

40%% Liquids

20%

0%

OXY MRO HES MUR APC APA DVN TLM NBL EOG CHK ECA

Source: Company annual reportsBOE volume based on 6:1 gas/oil ratioMRO & MUR include Oil Sands Mining Operations

5



Upstream Adjusted Income, $/BOEUpstream Adjusted Income, $/BOEYr. 2010

18

20

1416

E

8

10

com

e,$/B

4

6I

0

OXY MRO HES APA CHK MUR DVN NBL APC ECA TLM EOG

Source: Company annual reportsBOE volume based on 6:1 oil/gas ratioMRO upstream includes after tax income of E&P, OSM & Integrated Gas. MUR includes OSM. MRO, MUR & HES exclude R&M

6



Upstream PortfolioUpstream Portfolio

CanadaOil Sands MiningIn-situ

UKBraeFoinaven Norway

AlvheimViljeVolund

United StatesBakken Poland

Kurdistan4 Blocks

Indonesia

Anadarko WoodfordDJ BasinEagle FordRocky Mountain Oil

AlaskaPermian Basin

2.3 MM Acres

Gulf of MexicoDroshkyPetronius

yaFareghDahra JofraNC-98North Gialo

West Africa

Piceance

Base Assets

Ewing BankNeptuneOzonaGunflintShenandoahStones

EGAngola

Impact Exploration

7



Base AssetsBase Assets

Characterized by safe and reliable operations

Stable base roduction 2010 - 2015 avera es ~380 MBOED

Averages 66% liquidsCAPEX ~$1.5B per year

Constantly seek to reduce costs and optimize portfolio

Generate substantial free cash flow

Equatorial Guinea Oil Sands MiningUS Conventional Gulf of MexicoNorth Sea Libya

9



MROMRO –– Marathon Oil CorporationMarathon Oil Corporation

Key Strategies

Maximize value from existing base assets

Establish profitable-sustainable growth in reserves and production

10



Growth Assets and OpportunitiesGrowth Assets and Opportunities

Shift from few large projects to lower risk and scalable resource plays

Select dee water ro ects on oin

Technical excellence and project execution are key success factors

Focused on li uids

Retain upside for mid to long term natural gas

-

Disciplined CAPEX spend $1.5B-$2.5B per year

11



Growth AssetsGrowth Assets

Net ProductionProduction grows greater than 25% CAGR

Production mix avera es 72% li uids

CAPEX spend ~$1.5-$2.5B per year

Y10 Y11 Y12 Y13 Y14 Y15

Liquids Gas

Growth assets include Angola, select Gulf of Mexico, Bakken, Anadarko Woodford, DJ Basin (Niobrara), Eagle Ford, Piceance, and Haynesville/Bossier

12



Focus on North American Liquids GrowthFocus on North American Liquids Growth

2007$1,400MM*

2011$1,900MM*CAPEX Focus

Natural GasLHC

40%

60%

8%

92%

24% Increase in liquids production

200763,000 BPD

201178,000 BPD

*Excludes impact exploration CAPEX

13



U.S. LiquidsU.S. Liquids--Rich Shale PlaysRich Shale Plays

Based on Net Acreage, 000s Acres

3,000

2,000

2,500

1,500

000s acre

500

1,000

0

A B C D E F MRO G H I J K

Comparator group includes; APA, APC, CHK, DVN, ECA, EOG, HES, MUR, NBL, OXY, and TLM

Plays included: Bakken, DJ Basin (Niobrara), Anadarko Woodford, Eagle Ford, Granite Wash, Wolfberry, and Barnett

Source: The most recent available public sources including investor presentations, analyst reports, SEC filings, and earnings call transcripts as of year end 2010

14



Growth AssetsGrowth Assets

Liquids Rich Resource Plays

Resource Play Total• ~791,000 net acresIn-situ

~ • , ne we s• Significant down-spacing upside

• Acreage acquisition ongoing

,• Birchwood (13,000 net acres)

• Appraisal program early 2011

Bakken Shale• ~391,000 net acres• ~450 net wells


• Well Cost**: ~$6.0-$7.0MM• 30-Day IP: ~250-600 BOED• ~280 -500 MBOE/well

Woodford Well Metrics *

Anadarko Woodford Shale• ~94,000 net acres

~

DJ Basin (Niobrara)• ~177,000 net acres• ~600 net wells• Acreage acquisition ongoing

• Well Cost**: ~$7.5MM• 30-Day IP: ~600-900 BOED• ~750-1,000 MBOE/well

• Acreage acquisition ongoingDJ Basin Well Metrics *• Well Cost**: ~$4.0MM• 30-Day IP: ~200-300 BOED• ~250-300 MBOE/well

Eagle Ford Shale• ~79,000 net acres

~

Eagle Ford Well Metrics *• Well Cost**: ~$5.5MM• 30-Day IP: ~350-400 BOED• ~250-400 MBOE/well

*Industry basin average resource per well **Well cost includes facilities costs


15



This page intentionally left blankThis page intentionally left blank

16



Bakken ShaleBakken Shale

Diomedes

Cazador

Elk Creek HelenAeneas

Myrmidon

Menelaus

Fort

Paris Hector BertholdReservation

17



BakkenBakken ShaleShale

Bakken Shale Summary

Net acres 391,000

Projected Well Stats

EUR 280-500 MBOE

Average MRO-op WI 81%

Average OBO WI 17%

Potential locations 450

30-Day IP 250-600 BOED

Well & facility costs $6-$7 MM

Operating cost (FLC) $5-$6/BOE

Resource potential190MMBOE

Average well spacing 420 – 640 acres

Total discount to WTI $6-$8 / BBL

Net development costs $15-$20/BOE

22

MRO Bakken Average Annual Net Production(MBOED)

6 10

2008 2009 2010 2013E

Exited 2010 with ~15,000 BOED Net Production

18



Anadarko Woodford Shale WindowAnadarko Woodford Shale Window

Expanding Legacy Position in Liquids

19



Anadarko Woodford ShaleAnadarko Woodford Shale

Expanding Legacy Position in Liquids

Anadarko Woodford Shale Summary

Net acres 94,000


EUR 750-1,000 MBOE


Average OBO WI 15%


Well & facility costs $7.5 MM


Resource potential 300 MMBOE

Spud-to-spud 45 Days

Operating costs (FLC) $2-$3/BOE

Net development costs 10- 15/BOE

Increased program activity-

50-60 net wells per year by 2013Industry returns among highest of domestic resource playsExited 2010 at ~1,500 BOEDEstimate peak rate > 30,000 BOED by 2015

20



Eagle Ford ShaleEagle Ford ShaleNew Liquids Play Entry

21



Eagle Ford ShaleEagle Ford ShaleNew Liquids Play Entry

Eagle Ford Shale Summary

Net acres 79,000


EUR 250-400 MBOE


Average OBO WI N/A


Well & facility costs $5.5 MM


Resource potential 110 MMBOE

Average well spacing 160 acres

Spud-to-spud 35 Days

Operating costs (FLC) $5-$6/BOE

Net development costs $18-$25/BOE

Option to acquire ~75,000 net acresHigh interest – 94% WI

Consolidated positionDrill and complete 4 wells in 2011 to evaluate acreage potential– Risk reduced with option to purchase remaining acreage

Estimated peak rate > 15,000 BOED

22



DJ Basin (Niobrara)DJ Basin (Niobrara)New Frontier Growth Play

DJ BASINDenver, CO

23



Retained Natural Gas UpsideRetained Natural Gas Upside

Natural Gas Resources• Acreage primarily held by production

Powder River Basin• ~40 MMBOE net resource potential

Piceance Basin• ~160 MMBOE net resource potential

Oklahoma Conventional• ~260 MMBOE net resource otential

Haynesville/Bossier Shale• ~250 MMBOE net resource potential

East Texas Conventional• ~135 MMBOE net resource potential

Net resource potential represents P90 (high side) case

Additional Significant Long-term Upside from EG LNG 25



MROMRO –– Marathon Oil CorporationMarathon Oil CorporationKey Strategies


Establish profitable-sustainable growth in reserves and productionCreate si nificant value throu h im act ex loration

26



Gulf of MexicoGulf of Mexico

~21 Prospects with net unrisked resource44% Miocene56% Paleogene

Plan to operate 65%

Shelf

InnsbruckMC 993, 85% WI GunflintMC 948 12.5% WI

Deepwater

Exploration Leases

P A L E O G E N E

Producing Leases2011 Possible Exploration

Well2011 Possible Appraisal

Neptune30% WI

r ng

28



Kurdistan Region of IraqKurdistan Region of Iraq

29




New Impact Entry

Announced October 20, 2010

Position in four exploration blocks

High potential, world class, under-explored onshore oil play

ne o t e ast ons ore reg ons w t a s gn cant resource potent a per prospect

Potential to establish oil production in short to mid-term

30




3 BBOE Gross Unrisked PotentialStacked pay

4-way surface anticlines

Production sharing contracts2 wells in testing phase

– 1 in Sarsang– 1 in Atrush

Harir and Safen– 2011 seismic acquisition– 2012 initiate drilling

Block MRO WI Gross Acres

Harir 100 174,200Safen 100 104,800

Sarsan 25 303 000

Atrush 20 66,500 Atrush #1

31



PolandPoland

Shale gas potentialLower Paleozoic shales

100 – 600’ thick

8,000 – 13,000’ drill depth

Total 2.3 million net acres

2D Seismic & 1 well

exploration phase

5+ year concessions

: cqu re se sm c anDrill 1-2 wells in Q4

2012: Drill 7-8 wells

32



MROMRO –– Marathon Oil CorporationMarathon Oil CorporationKey Strategies


Establish profitable-sustainable growth in reserves and productionCreate si nificant value throu h im act ex loration

Maintain strong balance sheet and capital discipline

Pa com etitive dividend

33



What Distinguishes MRO?What Distinguishes MRO?

Large and stable base assets provide significant earnings and free cash flow

Leveraged to liquids with retained natural gas upsideDisci lined and sustainable reserve/ roduction rowth 3-5% CAGR

Very strong financial position

S endin linked to cash flow eneration

Top quartile financial and shareholder returns

Focused Focused on Total Shareholder Returnson Total Shareholder Returns

34



ForwardForward--Looking StatementLooking Statement

The following portion of the presentation contains forward-looking statements with respect to theplans to move forward with spinning off Marathon Oil Corporation's downstream business into aseparate publicly traded company thus creating two independent companies. Some factors that couldpotentially affect these forward-looking statements include board approval, receipt of a favorable

private letter ruling from the IRS and a registration statement declared effective by the SEC. Otherforward-looking statements include the Detroit Refinery Heavy Upgrade Project, which could beaffected by transportation logistics, availability of materials and labor, unforeseen hazards such asweather conditions, delays in obtaining or imposed by necessary government and third-partyapprovals, and other risks customarily associated with construction projects. 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, 2010,and subsequent Forms 8-K, cautionary language identifying other important factors, though notnecessarily all such factors, that could cause future outcomes to differ materially from those set forthin the forward-looking statements.

36



MPCMPC -- Marathon Petroleum CorporationMarathon Petroleum CorporationPositioned to be the premier US Independent Refiner

Strong across the full downstream value chain

37



Marathon Petroleum Corporation (MPC)Marathon Petroleum Corporation (MPC)Focused and Integrated Asset Base – Flexibility to Achieve Peer-Leading Results

Refineries

PipelinesTerminals

Coastal water terminals Inland water terminals

Speedway Brand MarketingPipelines TerminalsRefineries

Coastal waterterminals

Inland waterterminals Marketing Area

38



MPC Relative Refining PositionMPC Relative Refining PositionU.S. Crude Refining Capacity (1) # of U.S. Refineries (1)(MB/D) (#)

2,0001,962 1,951

1,4011,142 1,114

2,000

, 13

11

7 76 6 6 6

5

10

823 755 675 665

0

1,000

oco

lero

xon

BP

PC

PC

vron

hell

itgo

oco

soro

3 3

0

5

oco

lero

xon

oro P

CPC B

Phell

ron

itgo

oco

279252 233

300

Co V E

Che

Su Te

13.5 12.915.0

Co V

a Ex TeS

Che C

Su

Average Crude Capacity ofU.S. Refineries (1)

Nelson Complexity Index (1)(NCI)(MB/D)

190 188 186 178154

137

95100

200

.11.7 11.7 11.2 10.8 10.5 10.5

9.5

8.010.0

0

Exxon

Citgo

BP

Sunoco

MPC

Chevron

MPC

Valero

Conoco

Shell

Tesoro

5.0

Chevron

Exxon

Shell

BP

Citgo

Valero

Conoco

MPC

MPC

Tesoro

Sunoco

(1) O&GJ U.S. Refining Survey, data as of 1/1/2011. Owned interest of joint ventures are included in companystatistics: Conoco includes 50% WRB, Exxon includes 50% Chalmette, BP includes 50% BP-Husky Toledo, Shellincludes 50% Deer Park and Motiva. Sunoco data does not include the Eagle Point refinery which was shut down in2009. Valero data does not include the Paulsboro refinery which was sold to PBF in December 2010.

Majors and IntegratedsMPC

Independent Refiners

MPC w/Garyville @ 464 MBPD

39



MPC's Extensive Retail NetworkMPC's Extensive Retail NetworkIndustry-Leading Retail Operation

Speedway4th lar est U.S. owned o erated87 c-store chain

Over 1,350 stores~2.0 million customers/dayLocated in 7 states470

30663

77589

27

130

60887650

601

457136109

Brand

Independent entrepreneurs~5,100 branded locationsLocated in 18 states289137

100

1

Store counts as of 12/31/10

40



Marathon Petroleum CorporationMarathon Petroleum CorporationPositioned to be the premier US Independent Refiner


Well positioned geographically/operational flexibility and logistics

42



Midwest/PADD II Net Short Supply PositionMidwest/PADD II Net Short Supply PositionEnhances Margin Opportunities

The incremental barrel in PADD II isshipped from PADD III, so product

rices in PADD II should retain a

2015

premium to the USGC/PADD III

Refinery utilization rates in PADD IIhave traditionall been hi her than in other PADDs

Product stocks have stayed0.9 MMB/D or 18% of demand

to the other PADDs

TEPPCO Pipeline has raised tariffs49%

53%47%

40%

60%

ercentage o apac ty y

PADD II refiners are alsoadvantaged by having better access

8%

21%

4%

18%

0%

20%

PADD I PADD II PADD III PADD IV PADD V

In ustry D str ut on MPC w DHOUP & w o SPP

MPC has the highest Midwest exposure of all the major refining competitors

Source: DOE, data as of 1/1/2011Source: Marathon Economics

43

MPC W ll P i i d C Oil S d E iMPC W ll P i i d C Oil S d E i



MPC Well Positioned to Capture Oil Sands EconomicsMPC Well Positioned to Capture Oil Sands EconomicsAdvantaged Location Should Lead to Higher Relative Profitability

Hardisty

~ $7.35/BBLHardisty to USGC

~ $5.50/BBLHardisty to

Detroit

ChicagoDetroit Value vs. USGC Refineries for

WoodRiver

Patoka

~ $1.70/BBL

Canadian Heavy Processing

Laid-in Crude Cost

$/BBL

1.85

Port ArthurHouston

Houston to C icago

Higher Product Value 1.90*Total Advantage 3.75

* Includes $0.20 time value of money to ship a lightproduct barrel from Houston to Chicago

44

M h P l C iM h P l C i






Major refining investments nearly complete

45

G ill O ti Effi i iG ill O ti Effi i i



Garyville Operating EfficienciesGaryville Operating Efficiencies

Base Garyvi e re inery, 2008 So omon surveyBest U.S. cash cost operating expenseSecond-best U.S. Energy Intensity Index

Garyville Major Expansion Project (GME) expected to improve overallfixed cash cost by 20% per barrel at the Garyville refinery

46

Detroit Hea Oil Upgrade ProjectDetroit Hea Oil Upgrade Project



Detroit Heavy Oil Upgrade ProjectDetroit Heavy Oil Upgrade Project

Positioned to capitalize on Canadian oilsands production

Increases heavy oil capacity an additional80,000 B D, including “difficult to process”Canadian crudes

Crude capacity increases ~15,000 B/D

28,000 B/D delayed coker and 36,000 B/Ddistillate hydrotreater (DHT)

DHT will provide feedan cetane ex ty

Commenced constructionJune 2008, completion

$2.2 B* project; $1.27 B*capitalized as of

,

*Excludes capitalized interest

47



Marathon Petroleum CorporationMarathon Petroleum Corporation







Consistently a top performer on an operating income per barrel basis

49

IndustryIndustry Leading ProfitabilityLeading Profitability



IndustryIndustry--Leading ProfitabilityLeading Profitability(Pre-tax Adjusted Domestic Operating Income per Barrel of Crude Oil Throughput)

15

10

L

MPC

Group Range

0

5$/B

-51998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Preliminary

Companies Ranked* 12 11 11 9 10 9 8 9 98 10 8

MPC’s Rank 3 3 2 1 2 7 2 5 313 1

8

3

*Current companies ranked: BP, COP, CVX, MPC, SUN, TSO, VLO, XOM

Source: Company Reports

50

Diversified Income StreamDiversified Income Stream



Diversified Income StreamDiversified Income StreamPipeline and Retail Contributed 46% and 42% of Segment Income in 2009 and 9/30/2010 YTD

2009 Segment Income from Operations 9/30/2010 YTD Segment Income from Operations

PipelineTransportation

$172MM21%

PipelineTransportation

$131MM15%

Refining &Marketing

$452MM

Refining &Marketing

$497MMSpeedway54%

Speedway$212MM

25%

58%$228MM27%

Source: MPC Form 10 filed with SEC on January 25, 2011

51

Marathon Petroleum CorporationMarathon Petroleum Corporation







Consistently a top performer on an operating income per barrel basis

Characterized by safe and reliable operations

52





Well positioned versus peers

Strong balance sheets

Experienced and focused management teams

Enhanced flexibility to pursue tailored strategies

Expanded growth opportunities

Superior transparency – improved investor focus

53





54



AppendixAppendix

55



DefinitionsDefinitions



Term DefinitionCAGR Compound average growth rate, which is the annual growth rate calculated based

on each year's previous number anchored to a base starting point

, ,costs that are expensed as incurred rather than capitalized such as geological and

geophysical costs and certain staff costs, and other miscellaneous investmentexpenditures

Cash Adjusted Debt Calculated as follows: (Total Debt) – (Cash and cash equivalents) – (Trusteed cash)

CO2 Carbon dioxide

Conv Conventional

COP ConocoPhillips

CSG Coal seam gas

CVX Chevron Corporation

DD&A Depreciation, depletion and amortization

DHOUP Detroit Heavy Oil Upgrade Project

Dividend Yield Calculated as follows: (4 x Most Recent Quarterly Dividend Rate) ÷ (Current StockPrice

57




Term DefinitionE Estimated

E-10 A fuel mixture of 10% ethanol and 90% gasoline

E&P Exp oration & Pro uction, one o MRO s our usiness segments

EG Equatorial Guinea

EG LNG Equatorial Guinea Liquified Natural Gas production facility

EHCI E ectrica , Hy rau ic, C emica Injection

EIA Energy Information Administration

EOR Enhanced oil recovery

s ma e ma e ecovera e

FCC Fluid Catalytic Cracker

FLC Field Level Controllable Cost

oa ng pro uc on, s orage an o oa ng vesse

G&A General and administrative expense

GME Garyville Major Expansion project

HES Hess Corporation

58




Term DefinitionHH Henry Hub natural gas spot price

IEA International Energy Agency

IG Integrated Gas, one of MRO’s four business segments

In-situ Oil sands too deep for mining that require in-place treatment to achieve production

IP Initial production rate

LLS Light Louisiana Sweet crude oil

LNG Liquefied natural gas

LTPD Long tons per day

M Thousand

MBD Thousand barrels per day

MBOD Thousand barrels of oil per day

MBOED Thousand barrels of oil equivalent per day

59




Term DefinitionMCF Thousand cubic feet per day

MM Million

MMBOE Mi ion arre s o oi equiva ent

MMBTU Million British thermal units

MMCFED Million cubic feet equivalent per day

MRI Magnetic Resonance Imaging

MRO Marathon Oil Corporation

MSAT Mobile Source Air Toxics

e e o o aCapital Ratio

a cu a e as o ows: as us e e ÷ o a oc o ers qu y + asAdjusted Debt)

NOL Net operating loss

OBO Operated By Others

Oil Sands Mining orOSM

The business segment through which MRO’s oil sands mining results are reported;MRO holds a 20% outside-operated interest in the Athabasca Oil Sands Project, anoil sands mining joint venture located in Alberta, Canada

OPIS Oil Price Information Service

60




Term DefinitionOXY Occidental Petroleum Corporation

PADD Petroleum Administration for Defense Districts

Production Production available for sale

Proved Reserves Proved oil, natural gas and bitumen reserves determined under SEC requirements

PP&E Property, Plant & Equipment

PSVM Plutao, Saturno, Venus, Marte development area

PTD Projected Target Depth

R/P Reserve/Production

RDS Royal Dutch Shell plc

Recordable Incident The number of cases of in ur or illness er 200 000 work hours e uivalent to the Rate

hours worked by 100 full-time workers in a year)

REP Repsol YPF, S.A.

Reserves Proved, Probable and Possible oil and gas volumes as defined by the SEC

Resources Total Resource represents a high side, or P90 estimate of remaining expectedrecovery

61




Term DefinitionRFS Renewable fuels standard, which was amended by the Energy Independence and

Security Act of 2007 to require 36B gallons of renewable fuels by 2022

RIN Renewable identification number

RM&T Refining, Marketing & Transportation, one of MRO’s four business segments

ROCE Return on Capital EmployedROZ Residual oil zone

RVP Reid vapor pressure

SEC Securities and Exchange Commission

SCT Special Corporation Tax

SG&A Selling, General & Administrative

SPT Special Petroleum Tax

SSA Speedway SuperAmerica LLC

unoco, nc.

TAN Total acid number

TD Total depth

Total Debt Calculated as follows: (Long-term Debt + Short-term Debt)

62



Net Sales VolumesNet Sales Volumes



Yr. 2010

300

200

250

150MMBOE

50

100

0OXY APA APC DVN HES MRO TLM ECA CHK EOG MUR NBLMRO

13:1 6:1Source: Company annual reportsBOE volume based on 6:1 and 13:1 gas/oil ratioMRO & MUR include Oil Sands Mining Operations

64

Base AssetsBase Assetsl lb ld d d



Equatorial Guinea Alba Field & LPG – Long-Lived Production & Resource Base

Alba Field, 63% WI & Operator

590 MMBOE net resource– 395 MMBOE net proved reserves

Adding offshore compression. Start-up in 2015

Exploration potential

a an , pera or

2010 Production

37 MBD net liquids, 405 MMCFD net natural gasReliability > 92%; without planned TAR >96%

120 Projected EG Production

40

60

80

duction (MBOED)

Natural Gas

-

20

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Net Pro

Liquids

65

Base AssetsBase AssetsE i l G i LNG & M h l W ld Cl S l L Li d I S



Equatorial Guinea LNG & Methanol – World Class Scale, Long-Lived Income Stream

Monetize previously stranded gas

.

60% ownership

First sales Q2 2007, 17-year contract, FOB Bioko Island

Reliability > 97% in 2010, without planned TAR ~99%

At $6 HH net back $3.45/MMBTU

- Net cash flow to Marathon ~$265MM/year- Net profit to Marathon ~$200MM/year

>1 MMTPA Methanol Plant

45% Ownership

One of the worlds lowest cost producers

Competitively positioned to supply key markets

66

Base AssetsBase AssetsN O t f i g E t ti ith Additi l S t llit P t ti l



Norway – Outperforming Expectations with Additional Satellite Potential

Alvheim & Volund 65% WI & Operator / Vilje 47% WIFull field developed at cost of $13.25/boe~ ,through year-end 2010

Further Phase II infill drilling taking place through 2012Additional prospectivity

Mari øne A iscovery, 65% WI, ~20 MMBOE gross resourcepotential

– Evaluation underway, first production expected 2014

Recent Viper & Caterpillar discoveries

e ou e ng eva ua e

100,000

Alvheim FPSOViper

Marihone

Vilje South

20,000

40,00060,000

,

Axis Title Volund

Vilje

Alvheim Ph2a,b&c

0Alvheim Ph1

Sanctioned (w/normalized start date)

67

Base AssetsBase AssetsUK Area



UK Area

Brae Complex – Extending Asset Life3 Marathon-operated platforms

120

140

Brae Controllable Costs

Reliability > 92% in 2010, withoutplanned TAR >93%Reduced controllable costs, top quartile

80

100

illion

performance in 2009 McKinsey &Company benchmarkingFurther development drilling planned in

2011 & 2012

40

60$ m

Pursuing additional 3rd party volumes

Foinaven – Steady Source of Production & Income

0

2008 2009 2010

~30% Average WI2010 production 11 MBOED net, > 10MBOEPD projected through 2015Upgrading FPSO extends life to 2021

68

Base AssetsBase AssetsLegacy North American Oil



Legacy North American Oil

Long-lived, low decline onshore assetsRockies Oil

– ~ • Wyoming’s top oil producer

– Operated activity in 13 fields– High WI: ~98%

–

Permian Basin OBO position– 2010 Exit rate: ~7 MBOED net– 12 fields

• ree most s gn cant– Seminole: WI ~14%– Vacuum: WI ~26%– Wasson: WI ~12%

–

50

75 Net Production

ED

Gulf of Mexico2010 Exit rate: ~47 MBOED net

0

25

MB

2010 2011E 2012E 2013E 2014E

LHC Natural Gas

69

Base AssetsBase AssetsLegacy North American Gas



Legacy North American Gas

Alaska2010 Exit rate: ~119 MMCFD

– Disconnected from Lower 48 market

• 2010 realized price $5.37/mcf – Gas storage capabilities optimize

Rockies Gas (CO/WY)2010 Exit rate: ~79 MMCFD

Mid-Continent (OK/TX/LA)

50

75 Legacy North American GasNet Production

2010 Exit rate: ~92 MMCFD

25MBOED

2010 2011E 2012E 2013E 2014E

LHC Natural Gas

70

Base AssetsBase AssetsAthabasca Oil Sands Project



Athabasca Oil Sands Project

20% WI, 2 billion barrels of Bitumenresource (pre-royalty)Muskeg River mine production

Pierre

River

capac y neExpansion 1 ~20 MBD net

Mine began ramping up production Q3 2010Upgrader complete and commissioning in 2011

Muskeg RiverJackpine

Jackpine 2

85 MBD gross de-bottleneckingopportunities

700

800

D)

Fort McKay

400

500

600

duction (MB

Potential Micro-Expansions

PotentialMajor Expansions

Fort McMurray

Mining Assets

0

100

200

Gross Pr

Expansion 1

Muskeg River Mine

& Debottlenecking

2050

Production before royalty; growth beyond Expansion 1 is illustrative of timing and volumes

71

Growth AssetsGrowth AssetsDriving Production Growth in 2011 & Beyond



Driving Production Growth in 2011 & Beyond

Project MROW.I. MRO Operated First Production Peak Net Rate

(MBOED)

US Resource Pla s

Bakken ~80% 2006 22

Anadarko Woodford ~60% 2008 >30Ea le Ford ~94% 2011 >15

DJ Basin 75% 2011 TBD

Gulf of Mexico

Gunflint 12.5% 2015 6

Canadian In-situ

Birchwood – Phase I 100% 2016 15

AngolaBlock 31 PSVM 10% 2012 14

Block 32 CSE 10% 2016 18

72

Growth AssetsGrowth AssetsBakken hale



Production GrowthCurrently running 7 rigs

20

– – 1 dedicated to completions

Targeting 18 re-fracs in 2011Peak production 22 MBOED D

5

10

in 2013– Downspacing upside

Exited 2010 ~ 15 MBOEDMBOE

0

2007 2008 2009 2010 2011E 2012E 2013E

– ~ perate we s– ~100 Outside operated

73




Focused on ultimate recovery, not initial ratesConservative initial production practice focused on delivering higher recovery

80

100

120

E

MRO

Industry

40

60MB

Dunn County per well average

0

20

0 12 24 36

cumu at ve pro uct on

Time, Months

74

Da s from S ud




Da s from S ud

0

2,000

4,000

0 10 20 30 40 50 60

2006

Drilling performanceimprovement

6,000

8,000

10,00012,000D

epth, ft

2007

2008

20092010

evolution

Geology drives completionstechnique,

16,000

18,000

20,000

MRO Best– Initial open-hole fracs in shortlaterals

– Now drilling longer laterals• Surface access constraints• Technology advancements

Not all Bakken completions are created equal– MRO currently determining optimum completion type and number of stages to achieve

im roved well economics• Applying this knowledge to obtain most cost-effective completions by area

75

Growth AssetsGrowth AssetsAnadarko Woodford Shale



2011 ProgramCurrently running 3 company operated rigs, going to 8 by year-end 2011

500

20 - 25 Company-operated drill wells

25 - 50 Outside-operated drill wells

350

400

450

200

250

300

Capex, $MM

50

100

150

0

2009 2010 2011E 2012E 2013E 2014E 2015E

76

Growth AssetsGrowth AssetsMarcellus Shale Gas



Joint Venture$45 million in drilling carry

– Earns 50% of ~60,000 acres

$10 million option– Earns 50% of remaining ~22,000 acres

Option to acquire 100% o MRO sremaining net acreage

77

Growth AssetsGrowth AssetsHaynesville/Bossier Shale Gas



20,000 Net acres, 70% operated

Mostly held by production

10 Miles

150-250 MMBOE net resourcepotential Shelby Co.

LOUISIANATEXAS

Shelby Co.

2010: Drilled 2 wells, 1 waiting oncompletion, WI 100%

2010 Exit rate 8 MMCFD

2011: Drill 3 wells1 company operated

MRO WellsRecent IPs > 15 MMCFD

78

Growth AssetsGrowth AssetsAngola



Block 31, 10% WIPSVM Development

MRO acreage

Oil discovery

– Conversion FPSO, 150 MBOED– Project sanctioned 2008– Development drilling underway– -

BLOCK 3110% WI

PSVM

DevelopmentAreaVenus

Marte

Saturno

Leda

,expected May 2011

– First production Q2 2012

Evaluating further potential

Potential Mid

DevelopmentArea

Ceres

Hebe

Titania

Plutao

Miranda

Cordelia

Portia

developments

Block 32, 10% WI

Potential SE

DevelopmentAreaBLOCK 32

10% WI

Juno

UranoAstraea

Palas

Man ericao

CominhosColorau

AlhoDione

Oberon

Cola

Tebe

Development scenarios being evaluatedPotential

EasternDevelopmentArea

Gengibre

Mostarda

Canela

Gindungo

SalsaLouro

40 KM

79

Growth AssetsGrowth AssetsCanadian In-situ



In-situ OwnershipOperated

– Birchwood 100%– Namur ~60%

Outside-operated– Ells River 20%

Net resource

Namur60% WI

PierreRiver

– >1 BBBL net bitumen

2011 Birchwood Appraisal~ Well program

Ells River20% WI Muskeg River

– 2011 Capex: ~$86MMDrill, Evaluate, Plug

– Contracted four rigs– Cores planned for all wells

Birchwood

Fort McKay

– pen o e ogs pressure tests– Cap rock integrity tests

Project sanction: 2014First production: 2016

100% WI

or c urray

In-situ Assets

80

Poland Compared to US Shale Gas PlaysPoland Compared to US Shale Gas Plays



Shale Gas Plays Haynesville AnadarkoWoodford

Poland(Pre-Drill)

Total Organic Carbon(%)

0.5 – 8.0 1- 14 0.5 – 7.0

Depth(000 feet)

10 – 14 9 - 15 8 - 13

Net Thickness (feet) 150- 300 100 – 300 100 – 600

OGIP(BCF/ sq mile)

160 - 320 100 - 150 65 - 400

81

Impact ExplorationImpact ExplorationIndonesia

I N D O N E S I A



Pasangkayu Block70% WI & operatorAc uired 3D seismic 2008

Kutei Basin~15 BBOE

PasangkayuBlock

4 Commitment wells– 1 Well in 2010– 1 Well in 2011

~potential

Bone Bay Block

55% WI & operator

S U L A W E S I

2009 / 2010 Acquired 2D seismicDrill 2012

Kumawa BlockBone Bay

Block

umawaBlock

55% WI & operator2010 Acquired 2D seismicDrill 2012

MRO Acreage

~3.3 million gross acres across 3 blocks

82



Project Completed in Late 2009 Enhances FlexibilityProject Completed in Late 2009 Enhances FlexibilityGaryville Major Expansion (GME) Enhances Opportunities for Cash Flow and Profit*



4,000GME Contribution

Downstream Segment Income31%

2,000

3,000

$MM

Pre-Tax DownstreamSegment Income + DD&A

28%

51%

0

1,000

32%

Mars 2-1-1 Crack Spread $16.20 $19.65 $8.83 $10.96

2003-2007**Average

2008** 2009** 2010**

Incremental average annual after-tax project contribution

Cash flow (2010+) $575 MM $825 MM $300 MM $375 MM

Profit (2010+) $425 MM $675 MM $150 MM $200 MM

*Includes minority interest.**For illustrative purposes only. A simple, annual average of forecast results is added to actuals for all periods. Forecast based upon2003-2007, 2008 and 2009 average pricing for inputs and outputs as well as expected production rates and associated manufacturing costs.

84

Impressive Safety and Environmental RecordImpressive Safety and Environmental Record



OSHA Recordable Incident Rate(Employee and Contractor History)

1.370.97 0.90 0.73 0.80 0.611.00

2.00Days Away Rate

(Employee and Contractor History)

0.50

1.00

. .

0.00

2003 2004 2005 2006 2007 2008 2009 2010Est.

0.12 0.09 0.09 0.13 0.10 0.08 0.12

0.00

2004 2005 2006 2007 2008 2009 2010Est.

6,8198,000

Designated Environmental Incidents

167200

Pipeline Barrels Released

Environmental

(BBLS)

610 60 64 24 4 14 1210

2,0004,000

,

2003 2004 2005 2006 2007 2008 2009 8/20/2010

610

500

1,00086 83 74 76 7334

0

100

24 4 140

2003 2004 2005 2006 2007 2008 2009 2010

Est.

Since 2003, MPC has transported over 2 MMB/D

Goal – Top quartile performer in all Safety and Environmental Metrics

85

Speedway vs. Public CSpeedway vs. Public C- -StoresStores



167.3180

Light Product Sales

163.3180

Merchandise Sales

100.0 105.5 115.7120

140

160

nth 114.6

132.8

120

140

160

nth

71.2

60

80

G

al/Store/M 80.4 84.8

60

80

M/Store/Mo

0

20M

0

20 24.9% 42.0% 32.9% 34.7% 36.6%

(Margin % inside bars)

Top-Tier Industry Performer Source: Based on 2009 Company Public Reports

86

Crude Oil Differentials are Projected to ImproveCrude Oil Differentials are Projected to ImproveImproving Economy Should Result in Improved Differentials



$0.00

-$10.00

-$5.00

-$15.00$/BBL

-$20.00

- 25.002006 2007 2008 2009 2010 2011E 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Maya-LLS Mars-LLS MPC Sweet/Sour Differential

$1 BBL/ Δ in MPC Sweet/Sour Di erential ≈ $150 MM A ter Tax Pro it Forecast Sources: Maya – LLS and Mars – LLS, Purvin & Gertz; MPC Sweet/Sour Differential estimated based on above Purvin & Gertz forecast

MPC Sweet/Sour Differential = [(15% Arab Light) + (20% Kuwait) + (10% Maya) + (10% Western Canadian Select) + (45% Mars)]- Louisiana Light Sweet

87

AtAt--Risk RefineriesRisk Refineries –– CapacityCapacityUS Refineries at Risk (PADDs I-III)



2013 Capacity(MBD)

PADD I PADD IIIPADD II

1,884 3,928 9,180

Total I-III

14,992

Total I-V

18,812

PotentialClosures Count

Potential Closures

2 6 7

335 572 664

15

1 571 1 571

15

Capacity AfterClosures (MBD) 1,549 3,356 8,516 13,421 17,241

Sources: Media reports, Credit Suisse, OPIS, Purvin & Gertz, MRO estimates

88

RFS II & U.S. Gasoline DemandRFS II & U.S. Gasoline Demand

RFS II C ll l i Eth l



10

Actual & MROForecast of U.S.

RFS II Cellulosic Ethanol:Technically, economically &Blend Wall challenged

8

9

MB/D

Gasoline Demand

E-10 Blend Wall

7

M

62006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Hydrocarbon Gasoline Component RFS Ethanol Within E-10 LimitActual Ethanol in Surplus of RFS RFS Ethanol Over E-10 Blend WallQuestionable RFS Volume

Ca italizin on Historical Ethanol Position

Sources: DOE/EIA; Marathon EconomicsEarly Blending Investment Paying Dividends

89

Anticipated Benefits of SpinAnticipated Benefits of Spin- -offoff

h d fl b l l d h ll h



Enhanced flexibility to pursue tailored strategies - each company will have agreater ability to make business and operational decisions in the best interests of its business and to allocate ca ital and cor orate resources with a focus onachieving its own strategic priorities

Expanded growth opportunities – a more focused business strategy will result in anex anded ortfolio of attractive rowth o ortunities for each com an

Superior transparency – improved investor focus – as independent energycompanies, analysis and investment decisions will be more transparent, allow formore specific comparisons against peers, competitors, benchmarks andperformance metrics and thus facilitate evaluation assessments which will likelymake the two companies appeal to different sets of shareholders seeking to investin specific segments of the oil and gas industry

Strengthened ability to attract and retain talent - more focused business models

will enhance each company’s ability to attract and retain individuals with theappropriate skill sets as well as to better align compensation and incentives with

90

Corporate Governance and Dividend PolicyCorporate Governance and Dividend Policy



Each company will be led by the experienced directors and management thathave led Marathon

MPC

Thomas J. Usher – Non-Executive Chairman–.

MROClarence P. Cazalot – Chairman, President and CEO

Dividend PolicyMaintain annual $1.00 per share dividend

– ~.– $0.80 annual per share MPC (~355 million shares)

91

Financial ObjectivesFinancial Objectives

T i d i



Two strong, investment grade companies

Each will have sufficient li uidit and financial flexibilit to ursue theirstrategic objectives

Spin-off intended to be tax-free to the corporation and domestic shareholdersIRS Ruling pending for confirmation of tax-free status

92

Financing Structure at Separation DateFinancing Structure at Separation Date

MPC (D t )



MPC (Downstream)$2 billion new 4 year revolving credit facility

– JP Morgan and Morgan Stanley led

Issued $3 billion in new long term debt (Guaranteed by MRO until spin)– $750 MM 5-year notes, 3.5%– - , .– $1.25B 30-year notes, 6.5%

$750 million minimum balance sheet cash

MRO (Upstream)Retain existing $3B revolving credit facility

Retain existing public debt– Long-term debt reduced by ~$2.5 billion

93

MROMRO -- Debt Maturity ProfileDebt Maturity ProfileDecember 31, 2010

1 800 C d $2 5B h d ff h d b



1,600

1,800 Commenced ~$2.5B cash tender offer to purchase debt

1 000

1,200

1,400

M)

Up to $500MM of 2017, 2018 or 2019

600

800($000

-

200

400

'10 '11 '12 '13 '14 '15 '16 '17 '18 '19 '20 '21 '22 '23 '24 '25 '26 '27 '28 '29 '30 '31 '32 '33 '34 '35 '36 '37

Public Debt IRBs & Other USS Serviced Debt

2011 maturities reflect retirement of industrial revenue bonds by US Steel in accordance with the Financial Matters Agreement

94

Tax ConsiderationsTax Considerations

Deferred Tax Liabilities



Deferred Tax LiabilitiesCanadian election to pay tax in US dollars eliminates currencyremeasurement uctuat ons re ate to t ose tax a ances

Norway NOL balances expired

Country Statutory Tax Rate

Norway 28% Income Tax ; 50% SPT

Canada 26.5% Income Tax

Libya 93% Income Tax

EG 25% Income Tax

Angola 50% Income Tax

UK 30% Income Tax; 20% SCT

95

marathon howard weil 2011 energy conference

Documents