Investor Relations - Total S.A. · SAUDI ARAMCO TOTAL D REFINING & PETROCHEMICAL COMPANY SATORP F I...

FIELD TRIPSaudi Arabia & The Republic of CongoInvestor Relations

Saudi Arabia & The Republic of Congo 1

Table of contents

Refinery PresentationFawwaz Nawwab, Wednesday 13th

Refining & ChemicalsPatrick Pouyanné, Wednesday 13th

Total in CongoJacques Marraud des Grottes, Babak Bagherzadeh, Thursday 14th

Mature FieldsDieudonné Ganga, Laurent Barthélémy, Thursday 14th

Moho North ProjectYves Duteil, Jean-Yves Poulet, Thursday 14th

02

29

40

51

58

Saudi Arabia

FIELD TRIP

Saudi Arabia

SAUDI ARAMCO TOTAL REFINING & PETROCHEMICAL

COMPANY SATORP

FIELD TRIP

Refinery presentation

SATORP

Fawwaz NawwabPresident and CEO of SATORP

Saudi Arabia 2

SAUDI ARAMCO TOTAL REFINING & PETROCHEMICAL

COMPANY SATORP

Fawwaz NawwabPresident and CEO of SATORP

2 Nations

YanbuSasref

Riyadh

Jeddah

RabighYasref

Samref

RT

Jaizan

SATORP

Yanbu

King Fahad Industrial Port

Jubail ‐1

SATORP Refinery

Jubail ‐2

Key Milestones2006 2007 2008 2009 2010 2011 2012 2013

MOU Between Saudi Aramco ‐

Total May

MOU Between Saudi Arabia &

France Jan

SATORP JV Founded June

EPCC Contracts Award July

Securing the $8.5 billion loan Oct

Oil ‐InMay

Refinery in Operation Dec

Project Overview

Project Progress

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Jul‐0

9Au

g‐09

Sep‐09

Oct‐09

Nov‐09

Dec‐09

Jan‐10

Feb‐10

Mar‐10

Apr‐10

May‐10

Jun‐10

Jul‐1

0Au

g‐10

Sep‐10

Oct‐10

Nov‐10

Dec‐10

Jan‐11

Feb‐11

Mar‐11

Apr‐11

May‐11

Jun‐11

Jul‐1

1Au

g‐11

Sep‐11

Oct‐11

Nov‐11

Dec‐11

Jan‐12

Feb‐12

Mar‐12

Apr‐12

May‐12

Jun‐12

Jul‐1

2Au

g‐12

Sep‐12

Oct‐12

Nov‐12

Dec‐12

Jan‐13

Feb‐13

Mar‐13

Apr‐13

May‐13

Jun‐13

Jul‐1

3Au

g‐13

Sep‐13

Oct‐13

Nov‐13

Dec‐13

0,0

0,5

1,0

1,5

2,0

2,5

3,0

3,5

4,0

4,5

Planned Actual

Execution Strategy

JapanKorea

Singapore

Saudi Arabia

SpainItaly

EPCC’s worldwide

Package 1 - Distillation & Hydro Treatment (Tecnicas Reunidas)

Package 1Package 1

Package 2A

Package2A

Package 2BPackage 3

Package 5A

Package 5A

Package 5A

Package5A

Package 5A

Package 5B

Package 5C

Package 6

Package 6

Package 7Package 2A - Conversion (Technip)

Package 2B - Sulphur, Amine, SWT Acid Gas Treatment (DAELIM)

Package 3 - Aromatics Unit (Samsung)

Package 4 - Coker Unit (Chiyoda/Samsung)

Package 5A - IC Flare, Process Control & Electrical System (Technip)

Package 5B - Plant Utilities (SK Engineering)

Package 5C - Auxiliary Utilities (Al-Kathlan)

Package 6 - ISBL Tank Farm (Rotary Engineering)

Package 7 - Permanent Infrastructure (Al-Osais)

Package 4

Package 5A

Pack

age

8

Package 5C

Project Construction Man-hours to Date: 360,160,437

Project Peak Man-Power:46,000

LTI’s : 7TRIR : 0.0367

Overall Average PQI 89.4

SafetySafety QualityQuality

Safety and Quality

Full alignment and commitment of Shareholders

Alignment between PMT & Operation

Safety & Quality - successfully applied the SAUDI ARAMCO & TOTAL Management System

Corporate Set up and Readiness managed as a Project (CEP), PMT Project (PEP). CEP and PEP under SATORP CEO Responsibility.

Excellent Feed Document

Key Success Factors

2009

April 2010

June 2011

Sep 2012

2013

Refinery

Configuration

Very sophisticated and Complex Refinery with high level of Automation.

Refined High Value Product Complying with most Stringent International Specification

400 MBD of Arabian Heavy

Full Conversion; Integrated with Petrochemical

EDCI = 5550 kbd. Solomon Benchmark Ranking #7 in complexity index among more than 300 Refineries worldwide

Pumps 1,260 Vessels 866 Analyzers 600 Columns 121 Compressors 80 Reactors 68 Boiler & Furnaces 43 Loops 120,000

Equipments of a Complex & Sophisticated Refinery

Refinery Scheme

400 MBD

ArabianHeavy

Benz ène

HDSBP

HDSHP Diesel

Jet

Distillation

ssvide

Essences

Propyl ène

LAGO

HAGO

Coke

Paraxylene

Soufre Sulfur

All units

Heavy naphtha

CCR

LPG

DHC

MHC FCC

Benz ène

Alky

GO ex Coker

Benzene

HDSBP

HDSHP

Diesel

Jet

Distillation

ssvide

VDU(2)

Gasoline

Propylene

Kerosene

Coke

Paraxylene

SulfurSulfur

Recovery (3)Acid gas

HydrogenSteamSteamReformer (2)

Gas or LPG or Naphta

CDU (2)

Light naphthaCCR

LPG

DHC

MHC FCC

Benzene

Alky

VR

NHT (2)

PXPX

CokerCoker

Refinery Start‐up Status

STARTUP STATUS MIDDLE NOVEMBER

U 571

MCB

UTILITIES

FLARE SEAL

DRUMS

U 151

FLARE KO

DRUMS

SLOP TANKST0001 A/B

HP HDS FEED

T1006A

CDU011

NHDT U111

U

150

LP HDS U101

SRU 223

HP HDS U091

Chemical Warehouse

Warehouse

CDU 012U 152

Fire Water

FIRE

STATION

LAB

NHDT

U112

U 161 U213

U 155

LP HDS U102

HP HDS U092

CCR Compressor

SS16

SS1

Cooling Water Train 1

CRUDE TANK T1001 A/B/C

MHCU051

U203

U201

U200 and U 220

Cooling Water Train 2

IN OPERATION

COKER and MEROX LPG

U021U071

HANDOVER

Waste WaterTreatment Unitin operation

SRU 221

Catalyst Section

SOUR STAB NAPHTAT1012

LP HDS KERO FEEDT1004

PDEB TANKS T0007T0008

GASOLINE COMPOSANT

TANKS T2001

T2002A/BT2008T2012

GASOLINE

BLENDER

REGULAR GASOLINE TANKS T4001 A/B/C/D

RBOB GASOLINE TANKS T4002 A/B/C/D

SRU 222U202

U211

U212

U210

FCCU061 UGP

U171

ALKYand SARU081U181

PXU301

DHCU041

Biofilter A

DIESEL TANKS T4004 A/B/C/D/E/F

DIESEL COMPOSANT TANKS

T2005A/BT2006A/BT20013A/B

DIESEL

BLENDER

FUEL OILTANKS

T4011A/B

FUEL OIL COOLER

DHC/MHC FEEDT1007 A/B

LP HDS FEED T1005

DCU COKER FEEDT1009A/B

FCC FEEDT1008

HEAVY AROMATICS

T2003

HEAVY REFORMATT1010 A/B

LIGHT REFORMAT

T1011

PARAXYLENET4007 A/B/C

BENZENET4006A/B/C

SWEET HEAVY NAPHTAT1003A/B

BEUU141

SULFUR TANKS T0001 A/B and Truck

Laoding

LPG BULLETST2009 A/B (C4)

T2014 A/B/C (C3 )T 4008A/B/C (Prop)

ADMINISTRATIVE BUILDING

MIE BUILDING

JET A1TANKS

T4003A/B/C

SRU 222

FEED STAB SECTION

U031

IN STARTUP

24 3rd Quarter Company Performance

Project Finance

SATORP Financing Metrics

• $8.5 billion external project financing

• 40 banks involved

• 7 Export Credit Agencies involved

− France

− Germany

− Japan (2)

− Korea (2)

− Spain

• 3 Islamic instruments ($2.43bn)

− Wakala, Procurement, Sukuk

Thank You

Merci شكرآ

REFINING & CHEMICALS

FIELD TRIP

Refining & Chemicals

Patrick PouyannéPresident Refining & ChemicalsMember of the Executive Committee

Saudi Arabia 29

REFINING & CHEMICALS

Patrick PouyannéPresident Refining & ChemicalsMember of the Executive Committee

Saudi Arabia 30

0

500

1000

1500

2000

2500

3000

Refining & Chemicals at Total

13 refineries• 2.0 Mb/d capacity end-2012 vs 2.6 Mb/d end-2006

41 petrochemicals plants• 20 Mt/y of production capacity (45% outside Europe)

3 Specialty Chemicals subsidiaries• Hutchinson, Bostik, Atotech• 7 B$ sales and 1 B$ EBITDA per year

21 B$ capital employed (18% of Group)

Adj. net operating income

Cash flow from operations

Implementing a dynamic strategy

ResultsB$

ERMI* 37 $/t 21 $/t

2.42.1

9M 12 9M 13

+17%

-44%

* European refining margin indicator

1

2

Saudi Arabia 31

Taking up the challenge ofnew US oil and gas supplies

• Port Arthur refinery: capturing domestic crude supply opportunities and maximizing throughputs

• BTP cracker: maximizing ethane and LPG cracking

• Studying ethane side cracker project

Americas

• Developing 3 of the world’s best performing platforms

Middle East and Asia

• Priority to investments on integrated platforms

• Reducing refining and petrochemicals exposure by 20%

• Differentiate commodity polymer products on higher value markets

Europe

Integrated platforms to represent 70% of capital employedand 75% of refining & petrochemicals net income by 2017

Saudi Arabia 32

On track to achieve profitability target

* Subject to information and/or consultation procedures

Collective focus on transformational change

20152010

6%

13%

+1.5% +0.5%

+2.5%

+2.5%

Efficiencies/ synergies

Portfoliochanges

Specialty chemicals

Major projectson mainplatforms

200 M$in 2013 outof 650 M$

2015 target

CepsaDunkirkResins

Fertilizers Carling*

Port Arthur Normandy

QatarSatorpDaesanAntwerp

Profitability roadmapROACE in 2010 environment (ERMI 27 $10/t)

9.5%in 2013

Saudi Arabia 33

2006 20172011

Reduction / closureDisposal(incl. CEPSA, Fertilizers)

Reducing footprint in Europe

Before end-2011 After end-2011

-23%

-20%

Total’s refining and petrochemicalsEuropean exposure Base 100 end-2011

2006-13 Total’s European capacity reduction

Carling: subject to information and/or consultation procedures

Saudi Arabia 34

400,000 b/dArab heavy

Full-conversion

refinery with,MHC, DHC,

cokers

Integration with aromatic

complex

High Solomon complexity index 14.6

Designed specifically to process Arab heavy

• Optimized design and operations

• High availability

No fuel oil produced• More than 85% light products

• 55% middle distillates

1 Mt/y of petrochemicals products (PX, PP, benzene)

Satorp, a world-class fully converting platform

Successful project executionFinal Capex expected under 12 B$, below budget

Saudi Arabia 35

Product spec in line with world’s toughest specifications

Well located to arbitrage between markets

Price of Arab heavy crude depending on product destinations

Positioned to supply global markets

USA

Asia

Middle East

CokeSulfur

Diesel

Jet

Gasoline

Paraxylene Propylene Benzene

LPG

Europe

-5

-8

x2010-13 average Arab Heavy-Brent differential in $/b according to crude destination

-6.5SaudiArabia

Saudi Arabia 36

Satorp’s competitive margin advantage

30

75

0

50

100

Europeanmargin

Crude & ref.scheme

Energy Integrationwith

petchems

Access tomarkets

Satorpmargin

Margin on variable cost $/t

Margin benefiting from

• Access to heavy crude

• Full-conversion process

• Access to natural gas

• Integration with Petrochemicals

Designed to deliver industry-leading margins

Saudi Arabia 37

AverageEuropean refinery

Satorp(estimated)

Satorp’s competitive cost advantages

* Average for European refineries as calculated by Solomon EDC = Equivalent Distillation Capacity

Base 100

50

-40%

Satorp’s expected fixed cost below 15 $/t

Costs benefiting from

• Economies of scale

• Location in large industrial area

• Access to cheap and reliable electricity

• Logistic capacity

• Low crude inventories

Cash fixed cost $/EDC*

Saudi Arabia 38

‐15,00

‐10,00

‐5,00

0,00

5,00

10,00

15,00

Designed to deliver superior net cash margin

Satorp

Source Wood Mackenzie. Net Cash Margin = EBITDA, calculated as per WM mid‐cycle assumptions

15

10

5

0

-5

-10

-15

Net cash flows expected above 0.8 B$ per year

Net cash margin of East of Suez refineries In $/b

Saudi Arabia 39

A key asset for Total

Creating a new world-class leading platform

Reference partnership with Saudi Aramco

Successful joint-team project management

Asset built for the long term

Limited capital employed

Further development opportunities

FIELD TRIP

The Republic of Congo

The Republic of Congo

TOTAL IN CONGO

FIELD TRIP

Total in Congo

Jacques Marraud des Grottes Senior Vice President Africa Exploration & Production

Babak Bagherzadeh General Manager Total E&P Congo

TOTAL IN CONGO

Babak BagherzadehGeneral Manager Total E&P Congo

Jacques Marraud des GrottesSenior Vice President Africa Exploration & Production

The Republic of Congo 41

Total E&P: a strong presence in Africa

Africa SEC production Libya

2nd foreign producer

Algeria3rd foreign producer

Nigeria 3rd foreign producer

Gabon 1st foreign producer

Congo 1st foreign producer

< 50 kboep/d 50-100 kboep/d >100 kboep/d Exploration only

Angola3rd foreign producer

Presence in 16 countries

35%

2012 2017

28%

19%

39%

25%

16%

Nigeria Angola Congo

Libya Gabon Algeria

700 kboe/d


Importance of Congo to Total

• Third-largest pole for Total E&P in Africa

• Existing profitable business with diversified assets

• Many promising projects for the future

Total E&P Congo covers the spectrum of E&P activities

New business Exploration Projects under development Mature fields


Presence of Total E&P in Congo

1957 First exploration well

1969 First offshore discovery on Emeraude

1972-1996 First offshore developments:• Emeraude 1972• Yanga - Sendji 1981• Tchibouela - Tchendo 1987• Nkossa 1996

2008 First deep-offshore development: Moho Bilondo

2012 Historical agreement on Lianzi (Agreement between B14 Angola and Haute-Mer Congo)FID in 2012, first oil expected in 2015

2013 + New horizons for exploration and developments:• Deep-offshore: Moho North - first oil expected in 2015• Ultra deep-offshore: Mer Très Profonde Sud• Tight oil: Tchendo Senonian• New exploration themes: pre-salt, …

Emeraude1972

Moho Bilondo2008

Moho North2015/2016

Nkossa1996


Total E&P Congo assets

Large portfolio with diversified assets

NorthSouth

NkossaMoho

Djéno

Madingo

Lianzi

WI Total2012

Production (kboe/d)

Operator

North55%

37 Total65%

South 65% 26 Total

Nkossa 54% 37 Total

Moho 54% 66 Total

Madingo50%

25 ENI35%

Lianzi 37% First oil 2015 Chevron

Djéno 63% 248 Total


Total, the largest oil company in Congo

Operated production in Congokboed

A promising future for hydrocarbons production in Congo

0

100

200

300

400

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

Total E&P Congo Others

Maintain a profitable

growth

Yet to find40%

Resources(2P+2C)30%

Produced1969-2012

30%387

269

165

250


Safety and environment, our top priorities

Safety as a value as well as a duty.Improving our performance in safety on:

• Loss of containment due to external corrosion• Handling and lifting during drilling operations• Electrical interventions

Limiting environmental footprint

A dedicated HR policy, key success factor for the future

Corporate Social Responsibility at the heart of Total’s operations

Promoting local content to prepare for the future in Congo

• Develop a local industrial and economic network• Coach local companies• Create valuable competition within our suppliersLocal staff

Lost Time Injury Frequency and Total Recordable Injury Rate

0

10

0

1

2

3

2007 2008 2009 2010 2011 2012 2013

Working hours TRIRLTIF

TRIR objectiveLTIF objective

Total E&P Congo employees1,300 employees in 2013

Expatriates

MhrTRIR & LTIF


Implementing Total E&P strategy in Congo

• Maximizing existing production

• Bringing projects on streamon time and in budget

• Renewing and managing reserves portfolio

Total E&P Congo SEC productionkboe/d

Base Limiting natural decline of the base New projects

-2012 2013 2014 2015 2016 2017 2018 2019 2020

113

172

Total E&P Congo Capex (2013-2020)

22%67%

11%


Optimizing and rationalizing our portfolio• Identifying and capturing synergies• Supporting partners on non-operated assets• Concentrating efforts on most promising assets: Moho and Nkossa• Divesting: Emeraude (2000) and Likouala (2003)

Investing in growth sectors• Deep and ultra-deep offshore• Conventional resources• Tight oil, viscous oil and shale hydrocarbons

Negotiating attractive fiscal terms, adapted to each project

Starting-up our projects on time and at the best cost

Growing production profitably

Total E&P Congo estimated cash flow from operationsabove Group’s average over the coming 5 years


Renewing and managing reserves through exploration

Total E&P Congo, the largest operated acreage in Lower Congo Basin

Toward an ultra-deep offshore development

• New production licenses under negotiation

• Turbidites from Congo Delta

4 discoveries (MTPS)

• Post-salt carbonates

Nearby exploration (HMC)

A new license to target pre-salt carbonates• License awarded to SNPC in July 2013, Total operator • Carbonates and pre-salt• Exploration wells planned in 2015

Pre-salt (HMB)

Total11%

Eni8%

Free blocks52%

Others29%

Total Exploration Licenses

Total Production Licenses

Free blocks

Madingo

NorthSouth

NkossaMoho

Lianzi


Improving technology of our facilities

Moho North2015 / 2016

Nkossa1996

Moho Bilondo (Alima)2008

MATURE FIELDS

FIELD TRIP

Mature Fields

Dieudonné GangaOperations Manager Total E&P Congo

Laurent BarthélémyField Operations Manager Total E&P Congo


MATURE FIELDS

Dieudonné GangaOperations Manager Total E&P Congo

Laurent BarthélémyField Operations Manager Total E&P Congo



Diversified portfolio with strong growth potential

NorthSouth

NkossaMoho

Djéno

Madingo

Lianzi

WI Total2012

Production (kboe/d)

Operator

North55%

37 Total65%

South 65% 26 Total

Nkossa 54% 37 Total

Moho 54% 66 Total

Madingo50%

25 ENI35%




4 core operated zones

SouthNorth

MohoNkossa

Yanga – Sendji: 55%Kombi – Likalala – Libondo: 65%

13 platforms – 97 wells

Oil originally in place: 2.5 BbblProduced @ end-2011: 400 Mbbl

2012 oil production: 37 kbbl/d

Tchibouela – TchendoTchibeli – Litanzi: 65%

9 platforms + 1 flotel – 66 wells



Nkossa – Nkossa South – Nsoko: 53.5%

2 platforms + 1 barge + 1 LPG FSO – 37 wells

Oil originally in place: 1.2 BboeProduced @ end-2011: 310 Mboe

2012 oil production: 29 kbbl/d2012 LPG production: 8 kboe/d

Moho Bilondo – Moho North: 53.5%

2 subsea clusters + 1 Barge – 13 wellsIn construction: 1 FPU + 1 barge – 34 wells



11%9%

58%

13%

Total E&P Congoremaining reserves





Mature fields, a reliable base for the future of Total E&P Congo

50

100

150

kboe/d

Moho

Nkossa

South

North

Mature fields: 60%

• Production upsides– Infill wells, re-entries, workovers …

• Development of satellite fields– Libondo in 2011

• Mature fields redevelopment – Ongoing studies on South area

• Development of non-conventional reservoirs– Tchendo Senonian tight oil

– Sendji C viscous oil

2012 Total E&P Congo operated production

Incremental projects with high profitability


Compression upgrade and major turnaround on Nkossa: • Compression upgraded: + 8 Mboe• Anchor chains and critical flexibles changed• Flare upgraded

Maintaining the integrity of our facilities

CoGa project (2011-2013)

Nkossa major turnaround (2013)

Djéno revamping campaign (ongoing)

High pressure flexibles replaced on North and South:• 18 I-tubes installed • 9 flexibles changed• Project conducted in cooperation with Total Gabon

Djéno Terminal (95% Congo production) revamping:• Upgrading safety and integrity• Improving storage and treatment capacity• Limiting environmental footprint• Remaining competitive and attractive to receive

new developments’ production


15% decline rate without any actionLimiting the decline to 5%, through:

Light intervention• Dewaxing, gas lift, perforations,

acid stimulations …

Heavy intervention• Increased recovery on developed reservoirs

– 10 re-entries on Yanga and Sendji fields in 2012: + 5 kbbl/d

– Identified infills on Libondo and Nkossa

• Production from new layers– Work-overs on Tchibouela field in 2013: + 2 kbbl/d

• Well activation conversions

Production optimization • Sustaining reservoir pressure

• Optimizing well activation

• Optimizing current facilities – North debottlenecking: + 9 Mbbl @ 2029– Tchibeli H2S mitigation: + 6 Mbbl @ 2020

Development of satellite fields– Libondo start-up in 2011: 8 kbbl/d and 16.5 Mbbl @ 2020

Fighting the decline, a day-to-day challenge

Libondo

Drilling rig on Yanga

Pulling unit on TchendoBase

Limiting natural decline

New projects

2012 2013 2015 2017 2020

Total E&P Congo SEC productionkboe/d


Implementing new technology to capture hidden barrels

Leveraging Total E&P Congo high-tech expertise• Improved Oil Recovery with multi-stage fracturing

in horizontal wells, fishbone wells, hydraulic fracturing• Enhanced Oil Recovery with gas injection for viscosity

reduction

Developing Sendji C viscous oil level• Viscous oil > 40 cP• 635 Mboe in place• Increasing oil recovery with fishbone wells,

hydraulic fracturing• 60 Mboe potential

Studying the first tight oil offshore reservoir• Tchendo Senonian shallow reservoir• 850 Mboe in place• Increasing oil recovery (from 1% to 11%)

with multi-stage fracturing in horizontal wells• 85 Mboe potential

Redevelopment scheme Tchendo

MOHO NORTH PROJECT

FIELD TRIP

Moho North Project

Yves DuteilProject Manager

Jean-Yves PouletProject Integration Manager

MOHO NORTH PROJECT

Yves DuteilProject Manager

Jean-Yves PouletProject Integration Manager


Moho North, one of Total’s top 10 projects

Nearly doubling number of start-ups in next 3 years compared to previous 3 years

Execution on track

Major projects key features:

• 2017 production > 750 kboe/dContribution from Moho North >10%

• Cash flow from operations ~ 50 $/boeMoho North above average

0% 50% 100%

In blue: projects sanctioned in 2012-2013

CLOV

Laggan-Tormore

GLNG

Ofon 2

Surmont 2

Eldfisk 2

Ichthys

Tempa Rossa

Martin Linge

Moho North

Vega Pleyade

Incahuasi

Egina

1H 2014

1H 2014

2015

2H 2014

2015

2015

2016

2016

2016

2015 / 2016

2015

2016

2017

Start-up

Status of major projectsPost-2013 start-ups contributing to 2017 production% EPC progress



Large portfolio with diversified assets

NorthSouth

NkossaMoho

Djéno

Madingo

Lianzi

WI Total2012

Production (kboe/d)

Operator

North55%

37 Total65%

South 65% 26 Total

Nkossa 54% 37 Total

Moho 54% 66 Total

Madingo50%

25 ENI35%




New developments: Moho North and Phase 1 bis

AlimaPhase 1 bis

MHNM-2

MHNM-3

• Moho Bilondo producing since 2008 through Alima FPU

• Moho North objective to develop all the discoveries not yet producing under the Moho Bilondo license

• Total operator with 53.5%

• 2-stage project– Phase 1 bis – 120 Mbbl: development of the central

part of the production license and connection to ALIMA.

– Moho Nord – 365 Mbbl: development of the north part of the Moho Bilondo license from a new production hub.

• Water depth ranging from 750 – 1,100 m

• First oil: 2015 (Phase 1 bis) / 2016 (Moho North)

• Exploration: upsides in Miocene playPhase 1

Moho Bilondo

Moho North

Albian Tertiary


Moho North, a major project for Congo and Total

140,000 b/d production at peak

45% of the discovered reserves in Congo (2012)

10 B$ Capex

Local construction in Pointe Noire (12,000 tons from 2014 to 2016) Training programs for future operators

Moho production profile100%, in kbbl/d

‐

100

200

Moho NorthMoho Phase 1 bisMoho Bilondo

2013 2015 2020 2025


Improved fiscal terms

• Moho negotiation conducted from 2011

• New fiscal terms agreed in Q3 2012, enabling project sanction

– Improved cost stop

– Rapid cost recovery

• Cash flow from operations above Group’s major projects average

• Robust profitability at 80 $/b Brent


Key dates

Moho North

Phase 1 bis

2008Discovery

March 2013Final

investment decision

Q3 2014Start drilling

Q3 2015First oil

Phase 1 bis

Q2 2015Arrival of TLPon site

Q2 2016Arrival of FPUon site

Q3 2016First oil Moho North

July 2011Project team mobilization


Moho North reservoir characteristics

wateroil

• Unconsolidated sands• Turbidite channels• 5 to 23 million years (2,100 m)• Subsea development:

- 11 oil production wells- 6 water injection wells- 850 m to 1,100 m water depth

Moho North: 365 Mbbl

Miocene

• Carbonates • Light oil• 99 to 112 million years (4,000 m)• Dry tree TLP development:

- 12 oil production wells- 5 water injection wells- 750 m to 850 m water depth

Albian


A technological development which combines new and upgraded facilities

Optimal use of innovation and proven technologies for production recovery

Environmentally-friendly design: no flaring and produced water re-injection into the reservoirs

• Receival Miocene and Albianproduction

• Export to Djeno• Gas export / import to Nkossa• Living quarter facilities

Floating Production Unit

A first in Congo• Albian reservoir production • Dry trees • No processing – Limited utilities• Export to FPU by flow lines

Tension Leg Platform

• Production loop 24 km• Water injection line 12 km• Gas injection line 12 km• Umbilicals

Subsea Moho North

• 6 km extension of Bilondo existing lines • 6 km hybrid loop• The most powerful Subsea Multi–Phase

Pumps ever installed to produce oil

Subsea Phase 1 bis

• 3 deep-offshore drilling rigs

Drilling


Key Engineering and Procurement Contracts secured to satisfy project’s needs

DEVELOPMENT8,000 direct & indirect jobsEXPLOITATION130 managers & technicians (onshore & offshore )

Houston

Paris

Bergen Oslo

Pointe Noire

OffshoreDjeno

Mokpo

Ulsan

A worldwide contractual strategy to satisfy our technological needs

3 deep offshore drilling rigs


Moho North, planning and budget on track

2012 2013 2014 2015 2016Start basic: Q3 2011Basic engineeringPh1Bis pre-projectCall for tenderPROJECT SANCTION

EPC contract awards

DrillingPhase 1 BisMioceneAlbian

FIRST OIL

FID

Floating production unitTension leg platformSubsea production systemUmbilicals, flowlines, risersIntegration to existing facilities(Alima, Nkossa, Djéno)

Moho Ph 1 bis3Q2015

Moho North3Q2016

Overall progress as of Nov. 2013

100%

Janv.13 3Q15 3Q16

5%

Saudi Arabia & The Republic of Congo 69

This document may contain forward-looking information on the Group (including objectives andtrends), as well as forward-looking statements within the meaning of the Private SecuritiesLitigation Reform Act of 1995, notably with respect to the financial condition, results ofoperations, business, strategy and plans of TOTAL. These data do not represent forecasts withinthe meaning of European Regulation No. 809/2004. Such forward-looking information andstatements included in this document are based on a number of economic data and assumptionsmade in a given economic, competitive and regulatory environment. They may prove to beinaccurate in the future, and are subject to a number of risk factors that could lead to a significantdifference between actual results and those anticipated, including currency fluctuations, the priceof petroleum products, the ability to realize cost reductions and operating efficiencies withoutunduly disrupting business operations, environmental regulatory considerations and generaleconomic and business conditions. Certain financial information is based on estimatesparticularly in the assessment of the recoverable value of assets and potential impairments ofassets relating thereto. Neither TOTAL nor any of its subsidiaries assumes any obligation toupdate publicly any forward-looking information or statement, objectives or trends contained inthis document whether as a result of new information, future events or otherwise. Furtherinformation on factors, risks and uncertainties that could affect the Company’s financial results orthe Group’s activities is provided in the most recent Registration Document filed by the Companywith the French Autorité des Marchés Financiers and annual report on Form 20-F filed with theUnited States Securities and Exchange Commission (“SEC”).

Financial information by business segment is reported in accordance with the internal reportingsystem and shows internal segment information that is used to manage and measure theperformance of TOTAL. Performance indicators excluding the adjustment items, such asadjusted operating income, adjusted net operating income and adjusted net income, are meantto facilitate the analysis of the financial performance and the comparison of income betweenperiods. These adjustment items include:

(I) Special itemsDue to their unusual nature or particular significance, certain transactions qualified as "special

items" are excluded from the business segment figures. In general, special items relate totransactions that are significant, infrequent or unusual. However, in certain instances,transactions such as restructuring costs or asset disposals, which are not considered to berepresentative of the normal course of business, may be qualified as special items although theymay have occurred within prior years or are likely to occur again within the coming years.

(II) Inventory valuation effectThe adjusted results of the Refining & Chemicals and Marketing & Services segments arepresented according to the replacement cost method. This method is used to assess thesegments’ performance and facilitate the comparability of the segments’ performance with thoseof its competitors. In the replacement cost method, which

Disclaimer

approximates the LIFO (Last-In, First-Out) method, the variation of inventory values inthe statement of income is, depending on the nature of the inventory, determined usingeither the month-end prices differential between one period and another or the averageprices of the period rather than the historical value. The inventory valuation effect is thedifference between the results according to the FIFO (First-In, First-Out) and thereplacement cost.

(III) Effect of changes in fair valueThe effect of changes in fair value presented as an adjustment item reflects, for tradinginventories and storage contracts, differences between internal measures ofperformance used by TOTAL’s management and the accounting for these transactionsunder IFRS. IFRS requires that trading inventories be recorded at their fair value usingperiod-end spot prices. In order to best reflect the management of economic exposurethrough derivative transactions, internal indicators used to measure performance includevaluations of trading inventories based on forward prices. Furthermore, TOTAL, in itstrading activities, enters into storage contracts, which future effects are recorded at fairvalue in Group’s internal economic performance. IFRS precludes recognition of this fairvalue effect.

The adjusted results (adjusted operating income, adjusted net operating income,adjusted net income) are defined as replacement cost results, adjusted for special items,excluding the effect of changes in fair value.

Dollar amounts presented herein represent euro amounts converted at the averageeuro-dollar exchange rate for the applicable period and are not the result of financialstatements prepared in dollars.

Cautionary Note to U.S. Investors – The SEC permits oil and gas companies, in theirfilings with the SEC, to separately disclose proved, probable and possible reserves thata company has determined in accordance with SEC rules. We may use certain terms inthis presentation, such as resources, that the SEC’s guidelines strictly prohibit us fromincluding in filings with the SEC. U.S. investors are urged to consider closely thedisclosure in our Form 20-F, File N° 1-10888, available from us at 2, Place Jean Millier –Arche Nord Coupole/Regnault - 92078 Paris-La Défense Cedex, France, or at ourwebsite: www.total.com. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or on the SEC’s website: www.sec.gov.

This presentation, including all photographs contained herein, are copyrighted byTOTAL.

FIELD TRIP

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