petrobras at a glance
TRANSCRIPT
1
October, 2011
PETROBRAS AT A GLANCE
2
DISCLAIMER
FORWARD-LOOKING STATEMENTS:
DISCLAIMER
The presentation may contain forward-looking statements about future events within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, that are not based on historical facts and are not assurances of future results. Such forward-looking statements merely reflect the Company’s current views and estimates of future economic circumstances, industry conditions, company performance and financial results. Such terms as "anticipate", "believe", "expect", "forecast", "intend", "plan", "project", "seek", "should", along with similar or analogous expressions, are used to identify such forward-looking statements. Readers are cautioned that these statements are only projections and may differ materially from actual future results or events. Readers are referred to the documents filed by the Company with the SEC, specifically the Company’s most recent Annual Report on Form 20-F, which identify important risk factors that could cause actual results to differ from those contained in the forward-looking statements, including, among other things, risks relating to general economic and business conditions, including crude oil and other commodity prices, refining margins and prevailing exchange rates, uncertainties inherent in making estimates of our oil and gas reserves including recently discovered oil and gas reserves, international and Brazilian political, economic and social developments, receipt of governmental approvals and licenses and our ability to obtain financing.
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information or future events or for any other reason. Figures for 2011 on are estimates or targets.
All forward-looking statements are expressly qualified in their entirety by this cautionary statement, and you should not place reliance on any forward-looking statement contained in this presentation.
NON-SEC COMPLIANT OIL AND GAS RESERVES:
CAUTIONARY STATEMENT FOR US INVESTORS
We present certain data in this presentation, such as oil and gas resources, that we are not permitted to present in documents filed with the United States Securities and Exchange Commission (SEC) under new Subpart 1200 to Regulation S-K because such terms do not qualify as proved, probable or possible reserves under Rule 4-10(a) of Regulation S-X.
3
Overview
4
Incorporated in 1953 as government monopoly for all hydrocarbon activities. Little or no reserves, production or refining.
A history of organic, operated, self funded growth. Transition from a refiner of imported crude to integrated self sufficiency.
End of monopoly and opening of oil sector to international participants. Petrobras status as an operator, without privileged position.
Brazilian Government (directly and indirectly), owns 48% of Petrobras, and maintains control with 64% of voting shares.
Independent financial structure, with investment grade foreign currency ratings notched above the sovereign.
Listing on NYSE and SEC registration in 2000. Full quarterly disclosure in IFRS and U.S. GAAP. Market cap year-end 2010 of USD 237 billion.
Incorporation in 1953 as government monopoly
Reserves: 16.8 million boe
Production: 2.6 Thous. BPD* Refining Cap: 41 Thous. BDP*
Discovery of shallow water offshore fields Reserves: 800 million BOE Production: 177 Thous. BPD Refining Cap: 823 Thous. BDP
Discovery of mega fields in deepwater Campos Basin. Last refinery completed ‘81 Production: 467 Thous.BPD
Elimination of Monopoly, creation of oil law. Full deregulation by 2002. Production: 1 MM BPD oil in Brazil in ‘98
Brazil achieves self sufficiency in oil production Discovery of Santos Pre-salt
1953 1974 1984 1995-8
Listing on NYSE, with market cap of $ 31 billion 1st Investment grade rating
2000 2010
USD 70 bn capitalization and acquisition of rights to produce 5 bn BOE Production: 2MM BPD oil in Brazil
2006-7
* 1954
PETROBRAS HISTORY Becoming a major , publicly traded oil company through organic growth
5
Oct/1992 Jul/2000 After Aug/00 offering
After Jul/01 offering
Dec/2009 Dec/2010
OWNERSHIP Broad distribution among government, Brazilian, and foreign shareholders
Brazilian Non-Gov’t Shareholders
Non-Voting
Voting
Foreign Shareholders
Non-Voting
Voting
Brazilian Gov’t *
Non-Voting
Voting
48%
20%
32%
40%
21%
39%
41%
23%
36%
45%
25%
30%
61%
18%
21%
55%
45%
*Includes: Republic, BNDES, BNDESPAR, Sov. Wealth Fund
o Brazilian government, by law, must maintain control. Does so with 64% of voting shares.
o Petrobras is the most actively traded ADR on NYSE in three years, and among all stocks, the 8th most actively traded stock. On Bovespa, Petrobras most actively traded stock, by shares and by volume.
6
Exploration & Production
Gas and Power
Downstream
• Focus on production in deep and ultra-deep waters;
• Licensed blocks guarantee access to reserves and economies of scale;
• New exploratory frontier, adjacent to existing operations.
• Dominant position in a growing market, far from other refining centers;
•Balance and integration between production, refining and demand.
• Gas infrastructure develeped for processand and transfer of gas;
• Complete flexibility to consume domestic and imported gas.
Biofuels
• High productivitiy of Brazilian ethanol;
• Large areas of available unused agricultural land;
• Large consumer market, with fleet and distribution in place.
BUSINESS MODEL Operating as an integrated balanced oil company, dominant in Brazil
7
LOGISTICAL ADVANTAGES Uniquely positioned to integrate upstream and downstream operations
Upstream Operations Downstream Operations
Logistical Synergies Stable Cash Flows Growing Market Dominant Position
•Leadership in all segments of the value chain
•Market position ensures economies of scale and efficient business model
•Strong organic demand in one of the fastest growing global markets
•Attractive domestic market opportunities for upstream, downstream and other energy segments
•Main oil producing basins and refining located in S.E. Brazil, near GDP centers
•Logistical infrastructure fully developed
•Diversified cash flows with several growth drivers
•Reduced volatility of cash flows due to ability to smoothen prices fluctuations in the domestic market
Petrobras
Other Companies
Existing Pipelines
Refineries
Marine Terminal
In Land Terminal
8
BUSINESS SEGMENTS Fully integrated across the hydrocarbon chain, dominated by Brazilian production
Our Main Segments: Key Statistics and Market Positions (2010)
Adjusted EBITDA US$ 32.6 Billion1 (2010)
Exploration and Production
• 15.3 Bn boe of 1P(SPE)
• 2.3 mm boed production
•98.5% of Brazilian
production
• 20% of global DW and
UDW production
RTM (incl. Petrochemicals)
• 12 refineries (Brazil)
•2.0 mm bbld refining
capacity
• 11.2 mty materials
nominal capacity (2)
Distribution
• 7,306 service stations
•38.8% share of
distribution volume
Gas and Power
• 9,239 km of pipelines
• Participation in 20 of
the 27 gas discos in
Brazil
• 5,943 MW of
generation capacity
International
• 25 countries
• 0.7 Bn boe of 1P(SPE)
• 245 thous. boed
production
• 281 thous. bbl/d
refining capacity
•Petrochemicals, Gas &
Power activities
RTM 10%
G&P 4%
Distribution 3%
International 6%
E&P 77%
Biofuels
• 3 new Biodiesel
Plants
• Ethanol: Opening
new markets
• Responsible for 10%
of Brazilian ethanol
exports
Notes: (1) Includes Corporate and Elimination; (2) Through Braskem and Quattor
2010 Proven Reserves (SPE) 15.986 billion boe
Shallow Water
(0-300m)
9%
Ultra-Deep Water
(>1,500m)
32%
Deep Water
(300-1,500m)
50%
Onshore
9%
9
6.3
3.9
2.7 2.7 2.62.3 2.2
0.70.3
XOM RDS BP COP TOT BR CVX ENI STL
COMPARATIVE POSITION Ranked among the leading integrated energy companies
2010 Refining Capacity (mm boe/d)
2010 Proven Reserves – SEC (bln boe)
Notes: Peer companies selected above have a majority of capital traded in the public market; * 2009
Source: Evaluate Energy (barrels per calendar day, considering company % shareholding and including JVs) and Bloomberg
350
196 184147
115 103 8770 68
XOM RDS CVX PBR BP TOT COP ENI STL
Market Cap (US$ bn) – September 28nd, 2011
XOM BP RDS CVX BR TOT COP ENI BG
Oil Gas
2010 Oil and Gas Production (mm boe/d) 4.4
3.8
3.3
2.8 2.6
2.4 2.1
1.8
0.6
XOM BP RDS BR TOT CVX COP ENI STL
Oil Gas
24,8
17,8
14,2 12,7
10,7
8,3 6,8
5,4
10,6
* * * *
10
20
30
40
50
60
70
80
90
100
110
2000 2005 2010 2015 2020
• To meet growing world demand while replacing existing productionadditional capacity of 38 MMbpd will be needed by 2020
• Demand must be met by a combination of factors:
• New discoveries • Alternatives energy sources • Increase of energy efficiency
Source: WoodMackenzie
20
30
40
50
60
70
80
90
100
110
2000 2005 2010 2015 2020
(MM bpd)
GLOBAL LIQUIDS DEMAND SCENARIO
Projects under
development and
prospective
Project
Decline
Project
Decline Non-OPEP
OPEP
Projects under development,
prospective and new
discoveries
WORLD OIL DEMAND Replacing production with new discoveries will be a major challenge
11
62%38%
Brasil
Outros
New Discoveries 2005-2010
(33,989 million bbl) Deep-Water Discoveries
Source: PFC Energy
BRAZIL LEADERSHIP IN RECENT DISCOVERIES Deep-water discoveries in Brazil represent 1/3 of the worldwide discoveries in the last 5 years
• In the last 5 years, more than 50% of the new discoveries (worldwide) were made in deep waters
• The development of these reserves will demand additional capacity from the supply chain
• Expansion of the oil and gas chain in Brazil is in line with this perspective
Petrobras expects to double its proved reserves until 2020, keeping the discovery cost around US$2/boe
Other Discoveries Deep-Waters
Brazil
Other
12 Source: IEA – Outlook 2008
Expected Costs of Production
Pro
du
ctio
n c
ost
s (U
S$/b
bl-
20
08
)
Reserves (bn bbls)
1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 0
20
40
60
80
100
120
140
Deepwater and Ultra-deep water
Produced MENA
Other convention
al oil
CO
₂ -
EOR
EOR
Arc
tic
Heavy oil and
bitumen
Oil Shales
Gas to liquids
Coal to liquids
Petrobras expected maximum break-even cost
COMPETIVE ADVANTAGE Reserves in ultra-deep water in Brazil benefit from comparatively low break-even
13
100
5
8
8
9
10
12
12
13
15
15
45
0 20 40 60 80 100
Others
ENI/Agip
ConocoPhillips
CNOOC
Total
Anadarko
Chevron
BP
ExxonMobil
StatoilHydro
Shell
Petrobras
FPSO Semi Spar TLP Other
1977 Enchova
410ft 125m
1988 Marimbá 1,610ft 491m
1994 Marlim 3,370ft 1,027m
1997 Marlim Sul
5,600ft 1,707m
2003 Roncador
6,180ft 1,884m
2009 Lula
7,125ft 2,172m
Deepwater Production 2010 Gross Global Operated¹
Offshore Production Facilities
Source: PFC Energy Note: (1) These 15 operators account for 98% of global deepwater production in 2010. Minimum water depth is 1,000 feet (about 300 meters)
DEEPWATER LEADERSHIP A history of developing technology and know-how in Brazilian waters
14
1.855 1.971 2.004
321 317 334 435
618
1.120
111 132 144141
180
246
2.100
99 9693 96
125
142
2008 2009 2010 2011 2015 2020
Oil Production- Brazil Natural Gas Production - Brazil Oil Production - International Natural Gas Production - International
2,386 2,516
6,418
3,993
1,148 543
Pre-Salt ’00
0 b
oe
/day
2,772
845 Transfer of Rights
13
+10 Post-Salt Projects
+8 Pre-Salt Projects
+1 Transfer of Rights
+ 35 Systems
Added Capacity
Oil: 2,300,000 bpd
2,575
Note: Does not include Non-Consolidated International Production.
• Pre-salt and Transfer of Rights will represent 69% of the additional capacity up to 2020;
• Pre-Salt participation in the total production will enhance from the current 2% to 18% in 2015 and 40.5% in 2020.
3,070
4,910
OIL PRODUCTION With access to abundant reserves, Petrobras can more than double production
15 Source: BP Statistical Review 2011
While OECD oil consumption decreasing 0.04% p.a., Brazil consumption grew 2.1%.
In last two year, Brazilian consumption grew 20%
GROWING MARKET Brazil is the world’s seventh largest oil consumer and growing fast
1.61.71.82.02.32.42.42.62.83.23.34.5
9.1
EUA
Ch
ina
Jap
an
Ind
ia
Ru
ssia
Sau
di A
rab
ia
Bra
zil
Ge
rman
Sou
th C
ore
a
Can
ada
Me
xico
Iran
Fran
ce
Un
ite
d K
ingd
om
Total Oil Consumption per Country* – 2010 (MM bpd)
19,15
Above 3 MM bpd Between 2-3 MM bpd Under 2 MM bpd
Total Oil Consumption (Índex 1999 = 100)
90
110
130
150
170
190
210
230
1999 2001 2003 2005 2007 2009
BrazilEUAWorldOECDIndiaChina
* Including Ethanol + Biodiesel
16
0
5
10
15
20
25
30
USA Japan OECD Brazil China India
per
cap
ita
-b
arre
ls p
er y
ear
1980 2000 2010
Source: BP e US Census Bureau
HIGH GROWTH POTENTIAL Low per capita consumption supports demand growth in developing countries
17
Licenses for new vehicles
17,4
6,0 3,7
2,6 2,7 2,1 1,5 0,8
11,8
5,0 3,2 2,7 2,2
18,0
3,5 3,0 4,0
United States Japan Germany France Italy China Brazil India
2000
2010
2015
Mill
ion
of
un
its
814
592 545 599 688
47 153
16
208
United States Japan Germany France Italy China Brazil India
2010 2015
Number of vehicles per 1000 habitants
POTENTIAL INCREASE OF OIL PRODUCTS CONSUMPTION Brazil still has a low motorization rate
18
• Small refineries and with low complexity being closed in stagnant markets
• New large-scale refineries, high complexity, adapted to process heavy oil in growing markets
Source: Pira, Petrobras, 2011
3.204
1.997
736
1.755
153
703
437
Asia Middle East North America Latin America Europe Ex-USSR Africa
Expansion New Refineries
Adding Refining Capacity (2011-2016)
GLOBAL REFINING Regions with fast growth continue to invest in refining
Th
ou
san
d b
pd
19
Exploration & Production
20
Increase oil and gas reserves and production, in a sustainable manner, and be recognized for its excellence in E&P operations, placing the Company among the world’s
five largest oil producers
2011-15 Business Plan Highlights:
• 65% of Capex allocated to production development.
• 19 large projects, adding capacity of 2.3 million bpd.
• Drilling of more than 1,000 offshore wells, of these 40% is exploratory and 60% is production
development.
• In 2020, the pre-salt production will correspond to 40.5% of the oil production in Brazil.
E&P STRATEGY Sustainable development of hydrocarbon reserves
21
0
5.000
10.000
15.000
20.000
25.000
30.000
Onshore 0-300 m 300-1500 m > 1500 m Pre-salt's Recoverable Volume Transfer of Rights
Million boe Proved Reserves – SPE criteria
* Lula/Cernambi, Iara, Guará and Whales Park, ranging from 8.1 to 9.6 Billion boe
*
Garoupa Namorado
Marlim
Roncador
Whales Park, Mexilhão
Pre-salt: Lula and Cernambi 15,28 Bi boe
Carmópolis Guaricema
RESERVES AND RECOVERABLE VOLUMES Rapid growth in reserves from discoveries in deep waters
22
RESERVE PROFILE Proved reserves consist largely of offshore oil that is relatively heavy
15% 6%
34%
45%
Oil + Condensate
Proven Reserves as of Dec/2010 (SPE/ANP) (15.28 billion boe)
Developed Proven Reserves
Undeveloped Proven Reserves
< 22º API (heavy)
Gas > 31 º API (light)
22 – 31 º API (intermediate)
84%
5%11%
39% 61%
Associated Gas
Non-Associated Gas
23 t
USA
BRAZILIAN BASINS Offshore brazil is a vast area, still underexplored
24
0
500
1000
1500
2000
2500
1980 1990 2000 2010
106 211 230 21475
400 292189
42
749
1601
Deep water
Shallow water
Onshore
181
653
1.271
2.004
Thousand bpd
Onshore Shallow water Deep water Deep and ultra-deep
water Pre-salt
PRODUCTION Petrobras history is to grow production by expanding into new frontiers
25
Albian carbonates
Campos Basin Santos Basin
Pre-salt carbonates Pre-salt carbonates:
Supergiants oil fields
Post-salt turbidites:
current production
East West
Geological cross section in Santos Basin used to explain petroleum systems of Santos and Campos basins
Near-term production increase Mid and long-term production increase
OFFSHORE GEOLOGY Producing from pre-salt reservoirs will drive future investment
26
Tertiary and Upper Cretaceous Turbidites
Albian carbonates
Salt
Pre-salt carbonates
Santos Campos
E&P portfolio has around 3,000 projects
1 • Maintain production:
• Implement full development of the main production concessions.
• Decrease decline in existing fields.
• Operational maintenance in existing Production Systems.
• Continuous exploration effort.
1
2
2 • Explore, appraise and start production mostly in existing Production Systems (inside existing ring fences). 3
3 • Explore, appraise and start production mostly in existing Production Systems (inside existing ring fences).
4
4 • Explore & appraise. Extended Well Tests in main discoveries. Start production of pilot projects. Declare commerciality. Reduction of the project implementation time: equipments standardization, arrival of new drilling rigs, replicante FPSOs.
E&P FOCUS Maintain and expand traditional areas, while transitioning to new reservoirs
27
E&P INVESTMENTS IN BRAZIL– 2011-15 BUSINESS PLAN Pre-salt now more than half of development spending next five years
• Annual investments of more than US$ 4 billion in exploration
• 23% of the pre-salt investments are in the transfer of rights areas
Pre-Salt US$ 53.4 Billion
Post-Salt US$ 64.3 Billion
22%
57%
21%
54%
12% 2%
21%
13% Tranfer
of
Rights
Exploration Development Infrastrutucre and support
28
2.004 2.100
3.070
0
500
1000
1500
2000
2500
3000
2010 2011 2012 2013 2014 2015
Mil bpd
Lula Pilot FPSO BW Cidade Angra dos Reis
100.000 bpd
Cachalote and Baleia Franca
FPSO Capixaba 100.000 bpd
Marlim Sul module 3
SS P-56 100.000 bpd
Jubarte FPSO P-57
180.000 bpd
Baleia Azul FPSO Cidade de
Anchieta 100.000 bpd
(FPSO Espadarte reallocation)
Roncador Módule 4 FPSO P-62
180.000 bpd
Roncador module 3
SS P-55 180.000 bpd
Papa-Terra TLWP P-61 &
FPSO P-63 150.000 bpd
Guará (North) FPSO
150.000 bpd
Parque das Baleias FPSO P-58
180.000 bpd
Tiro/Sidon FPSO Cidade de
Itajaí 80.000 bpd
Tiro Pilot SS-11
Atlantic Zephir 30.000 bpd
Mexilhão Jaqueta
HG
EWT Guará FPSO Dynamic
Producer 30.000 bpd
ESP/Marimbá FPSO
40.000 bpd
Uruguá FPSO Cidade de
Santos 35.000 bpd
Aruanã FPSO
100.000 bpd
Guará Pilot 2 FPSO Cidade de
São Paulo 120.000 bpd
Lula NE FPSO Cidade de
Paraty 120.000 bpd
Maromba FPSO
100.000 bpd Siri
Jaqueta e FPSO 50.000 bpd
Cernambi South FPSO
150.000 bpd
FPSO P-67 Replicant 2 150.000 bpd BMS-9 our11
4 EWTs Pre-salt
FPSO P-66 Replicant 1 150.000 bpd BMS-9 or 11
Baleia Azul FPSO
60.000 bpd
Juruá GNA
Tambaú FPSO Cidade de
Santos NG
EWTs Lula NE e Cernambi
FPSO BW Cidade São Vicente 30.000 bpd
EWT Carioca FPSO Dynamic
Producer 30.000 bpd
Franco 1 Transfer of Rights
FPSO 150.000 bpd
3 EWTs Pre-salt
5 EWTs Pre-salt
5 EWTs Pre-salt
MAIN PROJECTS Large projects sustain production increases
EWTs
Pre-Salt and Transfer of Rights Projects
NG Projects
Post-Salt Projects
29
P-50
FPSO Frade
P-52
P-54
P-53
P-51 FPSO Marlim Sul
FPSO Espadarte
FPSO Cid. Niteroi
P-43
P-48
Installed Units
2004
P-43 – 150.000 bpd
FPSO Marlim Sul– 100.000 bpd
2005
P-48 – 150.000 bpd
2006
P-50 – 180.000 bpd
P-34 – 60.000 bpd
2007
P-52 – 180.000 bpd
P-54 – 180.000 bpd
FPSO Espadarte – 100.000 bpd
2008
P-53 – 180.000 bpd
2009
P-51 – 180.000 bpd
FPSO Frade – 100.000 bpd
FPSO Cid. Niteroi – 100.000 bpd
FPSO Espírito Santo – 100.000 bpd
2004 2005 2006 2007 2008 2009
Installed units in the Campos Basin since 2004 FPSO Espírito Santo
P-34
P-57
2010
2010
P-57 – 180.000 bpd
30
P-56
2011
P-62
P-55
FPSO
FPSO
P-61
P-63
2012 2013
New Units em Campos
Basin: 2011-15
New Units
2011
P-56 – 100.000 bpd
2012
P-55 – 180.000 bpd
FPSO Espadarte – 100.000 bpd
2013
P-58 – 150.000 bpd
P-61 – 150.000 bpd
P-62 – 180.000 bpd
P-63 – 150.000 bpd
FPSO (Marimbá) – 40.000 bpd
FPSO (Aruana) – 100.000 bpd
2014
FPSO (Baleia Azul) – 60.000 bpd
FPSO
FPSO
2015
FPSO (Maromba) – 100.000 bpd
FPSO Espadarte
P-58
2014 2015
31
2010
Lula Pilot
FPSO Cidade Angra dos Reis – 100.000 bpd
2013
Lula Northeast
FPSO Cidade Paraty – 120.000 bpd
Piloto de Guará
FPSO Cidade de São Paulo – 120.000 bpd
2014
Guará North
FPSO – 150.000 bpd
Cernambi
FPSO – 150.000 bpd
2015
Lula Central
FPSO – 150.000 bpd
Lula High
FPSO – 150.000 bpd
Franco – Transfer of Rights
FPSO – 150.000 bpd
PRODUCTION SYSTEMS 7 new systems until 2015, having already hired six
The 1st production well in Lula Pilot reached 36,000 boed (28,000 bpd of oil), being the most prolific well from Petrobras
32
• Additional recoverable volume from discoveries:
• Post-salt: Marimbá, Marlim Sul and Pampo: 1,105 MM boe;
• Pre-salt: Barracuda, Caratinga, Marlim, Marlim Leste, Albacora and Albacora Leste: 1,130 MM boe*.
• Well productivity exceeds 20,000 bpd
67 exploratory wells will be drilled between 2011 and 2015 in production areas in
Campos basin
Varredura Project
*No volumes have been announced regarding the Marlim Leste and Albacora Leste discoveries.
Descobertas do Pr é - sal na Bacia de Campos 2009/10 (VARREDURA)
Discoveries in Pre-salt Campos Basin 2009/10 (Varredura)
VARREDURA PROJECT
Technological development and exploratory optimization in existing concessions
33
SANTOS BASIN (PRE-SALT)
EWT Guará: 15,300 bopd EWT Lula NE: 14,400 bopd Lula Pilot: 28,300 bopd TOTAL: 58,000 bopd
CAMPOS BASIN (PRE-SALT)
Baleia Franca: 19,800 bopd Brava: 6,900 bopd Carimbé: 23,100 bopd Tracajá: 19,800 bopd TOTAL: 69,600 bopd
TOTAL PRODUCTION (JUL/11): 127,600 bopd
PRE-SALT PRODUCTION Appraisal stage production from Pre-salt already making significant contribution
34
42
55
75
95
0
20
40
60
80
100
2010 2011 2015 2020
• Mexilhão – 15MM m3/day
• Uruguá-Tambaú – 10 MM m3/day
• Juruá – 2 MM m3/day
2015-20 Associated Natural Gas from Pre-salt
2011-15 Non-Associated Natural Gas
Natural gas production from Pre-salt in Santos Basin must overcome 20 MM m3/day
Urucu
Coari
Manaus
Jurua
Amazon Basin
Santos Basin
Associated Natural Gas
Increasing production in the Campos and Santos Basin
Lula
Urugua
PMLZ-1
Mexilhão
UGN
RPBC
UTGCA
Million m3
NATURAL GAS PRODUCTION Start up of Plangas and Pre-salt projects will substantially increase capacity
35
VASPS
Technological Solution Technology Status
Subsea Pumping Systems
Subsea BCS In Operation
Subsea Pumping Model In Operation (Jubarte e Golfinho)
Skid BCS Prototype in TLD ESP 23 (Oct/11)
Subsea Muliphase Pump BMSHA Prototype in Barracuda (Dec/11)
Gas/Liquid Subsea Separation
VASPS Prototype Tested in P-08 (2011)
Oil/Water Subsea Separation
SSAO Prototype in Marlim (End of 2011)
Raw water injection SRWI Prototype in Albacora (End of 2011)
Subsea electric transmission and
distribution Under qualification Prototype scheduled to 2015
Underwater Electric Pump in Skid
Raw water injection Oil/Water Subsea Separation
NEW TECHNOLOGIES
Applications enhance recovery, while slowing decline and increasing production
36
OIL/WATER SUBSEA SEPARATION
- Resolves limitations from growing water production
- Separates water and oil under the sea, reinjecting water and relieving the size of the surface equipment on the platform
- Field: Marlim (Nov/2011)
RAW WATER INJECTION
- Increases production in existing systems
- 3 subsea systems for pumping raw water (with little treatment) to pressurize the reservoir, increasing recovery factor without increasing surface systems. Pioneer in the world in such water depth
- Field: Albacora (Dec/2011)
NEW TECHNOLOGIES - HIGHLIGHT Petrobras is implementing cutting-edge technologies
37
78.30 76.86
86.48
104.97
117.36
140.16134.51
147.02
175.30
187.78
LIFTING COSTS Costs pressured by higher oil prices
2Q10 3Q10 4Q10 1Q11 2Q11
17.54 18.46 17.34 19.00 20.93
26.37 24.26 26.1331.66
34.21
50.66
43.91 42.72 43.47
30.48
24.50 24.67 25.58
US$/barrel
35.00 55.14
R$/barrel
2Q10 3Q10 4Q10 1Q11 2Q11
9.79 10.6 10.29 11.38 13.12
14.71 14.07 15.2919.10
21.88
Lifting cost Brent Government Take 2Q11 vs. 1Q11:
o Higher expenses due to well interventions and preventive maintenance contributed to the upturn.
o Increase in government take reflects higher oil reference price.
38
0%
10%
20%
30%
40%
50%
60%
2005 2006 2007 2008 2009 2010
Peer Range
E&P PROFITABILITY IN BRAZIL
• E&P profitability strongly correlated to oil price
• Production in Brazil: 86% oil and 14% gas
• Higher net profit per barrel yields better return than its peers
• Stable regulatory environment allows for capturing the benefits of the increase in oil prices
Peers: BP, CVX, XOM,RDS, TOT
E&P ROCE
E&P Net Income ($/boe)
0
5
10
15
20
25
2005 2006 2007 2008 2009 2010
Peer Range
Brent vs. E&P Net income per Barrel
Profitability of oil Production in Brazil fully exposed to oil prices
Petrobras
Peers
Petrobras
Peers
Brent (Average in dollars)
Ne
t in
com
e p
er
Bar
rel (
US$
)
Source: PFC Energy
39
0,0%
5,0%
10,0%
15,0%
20,0%
25,0%
30,0%
35,0%
40,0%
45,0%
60 70 80 90 100 110
Key Assumptions:
• 150,000 bpd FPSOs
• Production of 500 MM barrels
• Ramp-up in line with industry
• Historic decline rate
• Oil value = 95% Brent
• Does not include exploration and acquisition costs
• The graph illustrates the cost-benefit ratio of a standard production development in Brazil, using assumptions based on previous experiences
Case 3 – US$12/boe Capex / US$5/boe Opex without Special Interest (such as Transfer of Rights)
Case 1 – US$12/boe Capex / US$5/boe Opex
Case 2 – US$15/boe Capex / US$7/boe Opex
(expected scenario)
PROFITABILITY New E&P projects generate attractive returns
US$/ bbl
40
DISTRIBUTION OF UPSTREAM REVENUES In higher oil price environment, net income per BOE benefits from concession terms
Distribution of the Realization Price of a Barrel of
Domestically Produced Oil
$ per Barrel Realization Price % Share of Realization Price
Net Income
Other COGS DD&A
R&D
Income Tax Lifting
SG&A Exploratory Costs
Other
Government Take
-20,0%
0,0%
20,0%
40,0%
60,0%
80,0%
100,0%
2003 2004 2005 2006 2007 2008 2009 2010 1S11$(10,00)
$10,00
$30,00
$50,00
$70,00
$90,00
2003 2004 2005 2006 2007 2008 2009 2010 1S11
41
PRE-SALT Pre-salt represent a large and relativly unexplored area
42
Ne
w R
igs
FPSO
s/
De
fin
itiv
e S
yste
ms
Piloto de Lula (AR)
FPSO
s/EW
Ts
SANTOS PRE-SALT MASTER PLAN HIGHLIGHTS From 2006 to 2010...
2006 2008 2009 2010 ... 2007
Pré-Sal/Parati
Tupi
Dis
cove
rie
s
Carioca
Bem-Te-Vi Guará
Iara
Caramba
Júpiter
Franco
Tupi (CSV) Guará (DP)
W Emminence (SS69)
W Polaris (NS28)
Clipper (NS21)
Louisiana (SS51)
W Taurus (SS68)
Stena (NS25)*
Victoria (SS70)
W Orion (SS78)
Ocean Valor (SS77)
Cajun (SS76)
Goldstar (SS73)
Dave Beard (SS71)
Deepwater Expedition (NS20)*
Paul Wolf (SS53)
Infr
aest
ruct
ure
Pipeline Tupi-Mexilhão
Iracema
* Sondas que não estão mais sob contrato com a Petrobras ou consórcios operados pela Cia.
43
SANTOS PRE-SALT MASTER PLAN HIGHLIGHTS ... 2011 and onwards
Ne
w R
igs
FPSO
s/
De
fin
itiv
e S
yste
ms
FPSO
s/EW
Ts
2011 2013 2014 2015 ... 2012
Piloto Guará
Piloto Lula NE
Guará Norte
Cernambi Sul
Replic. 3
Replic. 4
Lula NE (CSV)
Cernambi (CSV / 2S 2011)
Carioca (DP / 2S 2011)
Infr
astr
uct
ure
4 EWTs 3 EWTs 5 EWTs 5 EWTs
Replic. 1
Replic. 2
C.O. 1
7 drilling rigs
Vitoria 10000 (NS-30)
+ 3 sondas
Drilling Rigs to be contracted (includes up to 28 rigs to be constructed in Brazil)
ROTA 2
2016
ROTA 3
44
DEVELOPMENT OF PRE-SALT All first-phase units under construction or being contracted
Significant production increase
After 2017
Phase 1b
Production > 1 MM bbl in 2017
2013/2017
• Guará Pilot
• Lula NE Pilot
• Guará N
• Cernambi S
• 8 definitive production systems (replicant)
• 4 production units in the Transfer of Rights area
Phase 1a
2008/2013
Phase 0
3 FPSOs in operation
In operation (only 4 years after discovery)
Already contracted (start-up in 2012 and 2013)
Hulls already contracted (conversion in the Inhaúma shipyard)
Under construction (hulls being built in the Rio Grande shipyard) +
topsides under bid
1st already contracted and 2nd being negotiated
(start-up in 2014)
Acquisition of information
• Appraisal wells
• Extended well tests
• Lula Pilot
• Accelerated innovation
• Intensive use of new technologies specifically developed for pre-salt conditions
45
45
„
High exploration success ratio (all wells have found oil occurrences)
High productivity in producing wells
30 wells drilled up to July 2011 (26 exploratory)
Up to 15 wells scheduled for drilling in 2011
9 rigs in operation (July 2011) and another 5 scheduled for start-up by year-end
SANTOS BASIN PRE-SALT UPDATE Drilling campaign continues to accelerate
Wells undergoing drilling, completion or appraisal
LULA PILOT
LULA NE EWT
46
33.3%
33.3%
33.3%
Gathering Completion + Drilling Units
Pre-salt
CAPEX DISTRIBUTION
Deepwater Projects in Campos Basin*
CAPEX DISTRIBUTION
* Generic example, considering that these rates can change among the different existing projects in Campos Basin
o Additional drilling and completion cost
in the pre-salt compared with an
generic deepwater project in Campos
basin can be partially or fully offset by
higher quality and quantity of oil that is
expected in the pre-salt area.
20%
53%
27%
Gathering Completion + Drilling Units
CAPITAL COSTS: PRE-SALT VS. CAMPOS Similar equipment and processes: Principal difference is drilling and completion
47
34
35 5
41
4
1
2011 2012 2013 2014 2015
TLD - Pré-Sal e Cessão Onerosa TLD - Outras áreas
Constant production
Restriction due to gas burning limitation
Good behavior of the reservoirs
Good lateral communication
No issues regarding flow guarantee
Results obtained during EWTs
PRE-SALT RESULTS Reduced drilling time and exceptional reservoir behavior lead to growing optimism
Average drilling time of the wells completed during the year
(versus combined average time for 2006/7)
5 wells
4 wells
5 wells
6 wells
EWT Schedule
EWT – Pre-Salt and Transfer of
Rights
EWT – Other areas
48
100% 81%
55%
0%
50%
100%
150%
200%
PLANSAL 2008 (2008-2030) PLANSAL 2009 (2008-2030) PLANSAL 2010 (2008-2030)
Inve
stm
en
t
100% 118%
152%
0%
50%
100%
150%
200%
PLANSAL 2008 (2008-2030) PLANSAL 2009 (2008-2030) PLANSAL 2010 (2008-2030)
Net
Pre
sen
t V
alu
e
-45%
-32%
SANTOS PRE-SALT ECONOMICS Increasing knowledge lowers expected investment, increasing NPV for Master Plan
FLNG
Route 3 (3 options)
Route 2
Route 1
PROJECTS ROUTE 1 Year
Adequacy UTGCA May/2013
Pipeline PMXL-UTGCA 2010
Pipeline Lula-Mexilhão Feb/2011
PROJECTS ROUTE 2 Year
Pipeline Iracema-Cabiúnas Aug/2014
Expansion of Processing TECAB Aug/2014
ROUTE 3: Solution pipeline + processing/ Gas FSO Jan/2016
NATURAL GAS FLOW Route 1 in operation, Route 2 under construction and Route 3 in study to identify the best alternative
50 50
Central de Passageiros
(2014)
50
Central Fluido e Salmoura
Central Diesel
Central Fluido e Salmoura
Central Fluido e Salmoura
Central Diesel
Contratação Porto do Rio
Contratação Aeroporto de Cabo Frio
50 km
Instalações fora de escala
Contratação Angra dos Reis (2011/Fluidos)
Macae
INFRASTRUCTURE Status
Jacarepaguá Airport Operating
Itanhaem Airport Operating
Cabo Frio Airport Operating
Rio Port Operating
Macaé Port Operating
Fluids Center 1 Operating
Up to 2 new
centers of
diesel, up to 3
fluid centers,
passenger
center
LOGISTICS AND INFRASTRUCTURE Logistics solutions already in place to meet the
fleet of rigs and FPSOs in operation
51
2011 2012 2013
Parati (04/12/2012)
Guará (12/31/2012)
Carioca (11/11/2011)
2014 2016
BM-S-8
BM-S-9
BM-S-10
BM-S-11
BM-S-21
BM-S-24
2015
Caramba (04/30/2015)
Iara (12/31/2013)
Bem-Te-Vi (12/31/2012)
Júpiter (02/28/2016)
DECLARATION OF COMMERCIALITY Deadlines for the declaration of commerciality influences development plans
52
Transfer of Righs Aquisition
Volume 5,0 billion boe
Concession Area
3,865 km2 in 7 blocks
Average Price US$ 8,51 / boe
Initial Value US$ 42.5 billion / R$ 74.8 billion
Duration 40 years, extendable for
additional 5 years. 4 year exploration period
• 2C Contingent Resource
• Total Potential Oil and Condensate Quantities:
1,632 MM boe
• Total Potential Sales-Gas Quantities:
1,664 Bn ft3
• Brent Price: US$ 79.23 bbl
• Gas Price: US$ 4.27 thousand ft3
• 3 FPSOs, with 150 thousand BOPD processing capacity
D&M Assumptions for Franco: *
(10,000)
10,000
30,000
50,000
70,000
90,000
110,000
tt+
2t+
4t+
6t+
8t+
10t+
12t+
14t+
16t+
18t+
20t+
22t+
24t+
26t+
28t+
30t+
32
Beginning of
Production
Positive
Cash Flow
* Nominal values
Forecast - Accumulated Cash Flow from Franco’s field (2C) (US$ MM)
TRANSFER OF RIGHTS 5 billion BOE in contiguous and adjacent areas, adding scale and repeatability
53
Development
Duration: 4 years Extendable for 2 more years
Variable, according to Development Plan
Total Duration: 40 years, extendable for 5 more years according to specific criteria
TRANSFER OF RIGHTS Development of the areas fully under way
Declaration of Commerciality
Exploration Production
Area 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Franco
lara surroundings
Florim
NE of Tupi
South of Guará
South of Tupi
Resources already available for:
• 7 Exploratory wells • 1 contingent Exploratory well • 1 EWT • 2 contingent EWTs • 3D Seismic
First 4
production
units
undergoing
contracting
(*)
New technologies and definition of
resource allocation
* Conversion at the Inhaúma shipyard
54
There will be no regulatory changes in the areas under concession,
including the pre-salt area already granted
Petrobras 100%
Petrobras Operator
Other companies
trough Bidding
Process
Transfer
of Rights with
compensation
Production
Sharing
Agreement
Pre-salt
and
Strategic Areas
Other Areas
Current
Concession
Model
PRE-SALT PRODUCTION SHARING AGREEMENTS Proposed regulatory model for pre-salt areas not yet licensed
55
Profit
Oil
Cost
Oil
Companies
Government
o Petrobras will operate all blocks under this regime, with a minimum stake of 30%
o Consortium between Petrobras, Petro-sal and the winning bidder will be managed by the Operational
Committee
o Petrobras will be able to participate in the bidding process to increase its stake
o The winning bidder will be the
company that offers the highest
percentage of “profit oil” for the
Brazilian Government
o Petrobras will have to follow
the same percentage offered
by the winning bidder
o The Brazilian Government will not
assume the risks of the activities,
except when it decides to invest
directly
o Prior to contracting, the Government
may evaluate the potential of the
areas and may contract Petrobras
directly
PRE-SALT PRODUCTION SHARING AGREEMENTS Petrobras will be in every block as operator, with minimum 30% interest
56
Drilling Rigs, Critical Resources and
Local Content
57
Other operators
International Research Centers
Suppliers
Brazilian Universities and Research Centers
• Four R&D centers of Petrobras’ suppliers under construction; • In order to meet local content requirements, several companies will develop technological centers in the country.
Expenditures (investments and funding): US$1.3 billion / year
TECHNOLOGICAL LEADERSHIP Integration with suppliers, research centers and other oil companies
58
NEW VESSELS AND EQUIPMENTS
Resources required for production growth
Critical Resources Current Situation
(Dec/10)
Delivery Plan (to be contracted) Accumulated Value
By 2013 By 2015 By 2020
Drilling Rigs Water Depth Above 2.000 m 15 39 37 (1) 65 (2)
Supply and Special Vessel 287 423 479 568
Production Platforms SS e FPSO 44 54 61 94
Others (Jacket and TLWP) 78 80 81 83
Production
Platform (FPSO) Drilling Rigs Supply Vessel
(1) Two rigs reallocated from international operations, expire in 2015, so it is not considered in the 2020 accumulated value
(2) The demand for long-term will be adjusted as new demand assessments are made.
Water Depth 2006 2008 2010
Up to 1,000 meters 6 11 11
1,000 to 2,000 meters 19 19 21
Over 2,000 meters 2 3 15
2011 2012 2013
+2 +1 +1
+10 +13 +1
Drilling Rigs Under Contract
59
Rounds 7, 9 and 10
Rounds 5 and 6
Minimum limit by block Between 30% and 70% in the exploration and
production development phases
Rounds 1 to 4
Maximum limit 50% in the exploratory phase
70% in the production development phase
No local content required Round 0 Minimum and maximum limits by block:
In deep water, between 37% and 55% in the exploration phase, and between 55% and 65% in
the production development phase.
Transfer of Rights
Concession
Minimum exploration limit: 37% Minimum production development limit:
• Up to 2016: 55% • 2017-2018: 58% • After 2019: 65%
Marlim Sul
SS P-56
Baleia Azul
FPSO
Roncador
FPSO P-62
Roncador
SS P-55
Papa-Terra
P-61 &FPSO P-63
Guará (Norte)
FPSO
Parque das Baleias
FPSO P-58
Tiro/Sidon
FPSO
ESP/MARIMBÁ
FPSO
Aruana
FPSO P-62
Guará Piloto 2
FPSO Cid. São Paulo
Lula NE
FPSO Cid. de Paraty
Maromba
FPSO
SIRI
2 jacket and FPSO
Cernambi
FPSO
Lula 3 Central
FPSO
Franco 1
FPSO
Lula 4 Alto
FPSO
BALEIA AZUL
FPSO
LOCAL CONTENT Flexibility in concession agreements
Lower local content requirements in the ANP’s initial concession rounds give local industry time to adapt.
Concession and Transfer of Rights agreements permit waivers from local content requirements when terms are uncompetive relative to international metrics (e.g. price, deadline, technologies).
2011 2012 2013 2014 2015
2011-2015 Projects
60
Extensive experience of contracting FPSOs combined with operational scale and equipment standardization
will help create an internationally competitive offshore industry.
DEVELOPMENT OF NATIONAL INDUSTRY Detailing of needs into critical categories permits long-term strategy
▲Proportional share of FPSO cost
CATEGORY NATIONAL MARKET
AVAILABILITY FPSO cost
1 Process equipment ▲▲ 2 Turbomachinery ▲▲▲ 3 Mechanical equipment ▲ 4 Electrical equipment ▲▲ 5 Instrumentation/automation ▲ 6 Ship structure and systems ▲▲▲ 7 Pipeline and valves ▲ 8 Security
▲
9 Telecommunications 10 Ventilation and AC (VAC) 11 Engineering services 12 Architecture 13 Commissioning services
61
o 2 Jack-ups under construction (P-59 and P-60) in São Roque (BA)
o Inclusion of 900 new suppliers per year in Petrobras' Corporate Vendor List;
o 13 new shipyards currently under construction, raising the total number to 50*;
Recently built platform:
P-57: BrasFels – RJ Capacity: 180 thous. boe/day Value: US$ 1.2 billion Delivered two months ahead of schedule
8 FPSOs (Pre-salt - P-66; P-67; P-68; P-69; P-70; P-71; P-72; P-73 ): Ecovix – Rio Grande (RS)
P-61: Brasfels (RJ) P-62: Jurong (ES)
P-63: QUIP (RS)
FPSO Cidade de Paraty: Brasfels (RJ) - modules and integration
FPSO Cidade de São Paulo: Brasfels (RJ) - modules and integration
Under Construction:
Under Construction:
PLATFORM CONSTUCTION Joint ventures with foreign shipbuilders creating additional shipyard capacity
Under Construction: P-55: Estaleiro Atlântico Sul – PE (hull) /QUIP- RS (modules)
P-58: Estaleiro Rio Grande –RS , UTC Engenharia S/A – RJ e EBE – RJ.
*Source: Sinaval – Executive Summary -2011, Jan.
P-56: Brasfels (RJ)
62
LOCAL CONTENT ACHIEVEMENTS High level of local content already in place
Jubarte development P-57 65% Local Content
Roncador development P-54 68% local content
Marlim Sul development P-56 73% local content
63
Import
ACTION ROUTES GOODS AND SERVICES SUPPLY
Current Demand Future Demand
National Industry
Import
Expansion of
Capacity of National
Supply of Goods
and Services
1. Expand production capacity of high competitiveness sectors
2. Developing the competitiveness of middle competitiveness sectors
3. Encourage the development of new national entrants
4. Encourage association of domestic and foreign companies
MAPPING CAPACITY Identifying opportunitIes to expand the competive supplier base
5. Encourage the installation of foreign companies in Brazil
64
2010 2011 2012 2013 2014 2015 2016 2009 2008 2007
212.638 HR Demand (R$ 554 million)
PN 2010-14
78.402 Already been qualified
(R$ 228 million)
Business plan 2008 - 2012
28 Probes
146 Support boats
New production platforms
Promef II
19 charter vessels
Premium I Refinary
Premium II Refinery
Replanning Comperj and RNEST
New projects
HUMAN RESOURCES Intensive training programs created to meet Business Plan demands
65
HUMAN RESOURCES REQUIREMENTS Workers with elementary and high school education most needed
PROFESSIONALS REQUIRED FOR O&G PORTFOLIO IMPLEMENTATION
189 PROFESSIONALS CATEGORIES
212.638 Qualified professionals
ENGINEERING 41
4% 8.674
CONSTRUCTION & ASSEMBLY
90
79% 168.197
GRADUATE 24
45% 3.880
HIGH SCHOOL 14
44% 3.806
HIGH SCHOOL 27
21% 34.827
BASIC 21
71% 118.654
CIVIL CONSTRUCTION
7
9% 20.200
BASIC 7
100% 20.200
OPERATIONS MAINTENAINCE
51
7% 15.567
BASIC 12
25% 3.909
HIGH SCHOOL 19
49% 7.690
GRADUATE 19
7.553 4%
TECHNICIAN 2
1% 2.103
TECHNICIAN 3
11% 988
TECHNICIAN 1
22% 3.393
INSPECTORS 21
3% 5.060
GRADUATE 11
4% 575
66
Refining, Transportation & Marketing (RTM),
and Petrochemicals
67
Expand the downstream, ensuring domestic supply and distribution leadership,
developing markets for the oil surplus produced in Brazil
2011-15 Business Plan Highlights:
• Downstream capacity will increase by 395 thousand bpd between 2011-15 and 1,065 thousand bpd between 2016-2020;
• Completion of the process to modernize the downstream segment;
• Logistics integrated with E&P activities to ensure the commercialization of the oil surplus;
• Increase petrochemicals and biopolymers production.
DOWNSTREAM STRATEGY Expansion, quality, logistics and marketing
68
INVESTMENTS New refineries, fuel quality and modernization responsible for 75% of spending
• Refining Capacity Expansion: Abreu e Lima
Refinery, Premium I and II, and Comperj;
• Quality and Conversion: Modernization,
conversion, and hydrodesulfurization;
• Operating improvement: maintenance and
optimization, HSEE, and R&D;
• Fleet Expansion
• Logistics for Oil: oil supply for refineries and
infrastructure for oil exports.
Petrochemical Investments amount to US$3.8 billion
US$70.6 billion
50,1%
23,9%
13,9%
6,2% 4,9%
1,0%
Refining Capacity Expansion
Quality and Conversion
Operating Improvement
Fleet Expansion
Logistics for Oil International
69
3.016
2.147
2.571
+3,5% a.a.
0,4% a.a.
1.814 1.776
(GDP: 3% a.a.)
(GDP: 4,1% a.a.)
2.208
Others
Fuel oil
Gasoline
Middle destilates
mil
bp
d
BRAZILIAN MARKET Economic growth and rising incomes drive increase in oil product demand
70
INTEGRATION AND BALANCE Construction of new refineries intended to meet Brazilian demand
• No new refineries built since 1980 • Demand now exceeds refining capacity, with demand growing 20% last two years and growing
0
1000
2000
3000
4000
5000
1980 2000 2010 2015 2020
Oil and NGL Production - Brazil Total crude oil processed – Brazil Oil Products Market (2 scenarios)
Abreu e Lima Refinery (RNE) 230,000 bpd
(2012)
COMPERJ (1st phase)
165,000 bpd (2013)
PREMIUM I (1st phase)
300,000 bpd (2016)
PREMIUM I (2nd phase) 300,000 bpd
(2019)
PREMIUM II 300,000 bpd
(2017)
COMPERJ (2nd phase) 165,000 bpd
(2018)
Thous bpd
2,536
2,643 3,095
3,327
1,641
2,205
3,217
181
2,004
3,070
4,910
1,393 1,798
1,036
2,147 1,814
1,323
... ... ... ...
71
PRODUCT PRICING Free market follows international prices in the long term
20
40
60
80
100
120
140
160
2011 2010 2009 2008 2007 2006 2005 2004 2003 2002
US$/bbl
2002-2011
Average Realization Price - Brazil
Average Realization Price - USA
• No change in policy: Petrobras remains fully committed to international prices
72
DOWNSTREAM EXPANSION
New refineries needed to avoid excessive dependence on product imports
* Source: IEA – 2010 World Energy Statistica
** Without considering Capacity Expansion
2006 2007 2008 2011E 2009 2010
Brazil (2020)**
Indonesia
Mexico
Spain
Japan China
Germany
France
Brazil (2010)
USA
Net Imports as a percentage of total demand (%)*
• Increasing imports will lead to higher logistical costs and increasing exposure to
availability of international supplies
Net Product Imports (’000 bpd)
73
Market in 2015 Market in 2010
REFINING CAPACITY Large and growing deficits in the northeast determine refinery location
• Increase in demand in the Central-West, Northeast, and North explains the concentration of investments in the Northeast;
• Tax incentives combined with environmental restrictions also contribute to the concentration in the region.
552
Deficit
-416
Demand
968
Capacity
1.652
Deficit
-23
Demand
1.675
Capacity
299
-464
763
82
1.466
1.384
Deficit Demand Capacity
Superavit Demand Capacity
74
Capacity: 230,000 bpd
Stage: Implementation
Startup: 2012
REPRE I
Comperj
Abreu e Lima Refinery
Capacity: 330,000 bpd
Stage: Implementation
Startups: 2013 and 2018
Capacity: 300,000 bpd
Stage: Preliminary License issued
Startup: 2017
REPRE II
RNE
Comperj
Capacity: 600,000 bpd
Stage: Earthworks
Startup: 2016 and 2019
Premium I Refinery Premium II Refinery
60’s 50’s 70’s 80’s 90’s 00’s
RLA
M
REC
AP
RP
BC
REM
AN
RED
UC
REG
AP
REF
AP
REP
LAN
REP
AR
REV
AP
RN
EST
CO
MP
ERJ
10’s
32 years
Launch of Petrobras’ Refineries
• Learning curve from the two new refineries (Abreu e Lima Refinery and Comperj) to reduce Premium refineries CAPEX
DOWNSTREAM EXPANSION Abreu e Lima and Comperj under construction, Premiums in design stage
PR
EMIU
M I
PR
EMIU
M II
75
21%
4%
7%
10%
Light
36%
6%
9%
21%
Medium Distillated
43%
5%
38%
Others
Fuel Oil
Special
Naphtha
LPG
Gasoline
Jet Fuel
Diesel
Intermediary
4%
15%
19%
4%
11%
15%
65%
15%
50%
Productivity of existing refineries – 2020
Light Medium Distillated Others
Productivity of new refineries – 2020
• Increase in global demand for medium-distillated products tends to lead to an increase in price versus the gasoline price.
PRODUCTS New refineries will produce higher value-added oil products
76
Average API Processed (2020)*
-5,5
Premium Refineries
22,5
Existing Refineries
28,0
Crude Sulfur Content (2020)*
+0,1
Premium Refineries
0,6
Existing Refineries
0,5
(pp
m)
Average Naphthenic Acidity (2020)*
0,5
1,3
+0,7
Premium Refineries
Existing Refineries
(mg
KO
H/g
)
Average Crude Cost (2020)*
-5,8
-2,3
Premium Refineries
67
Existing Refineries
69
Brent
75
(US$
/bb
l)
* Estimates
PREMIUM REFINERIES New refineries will process a different crude profile, with lower oil costs
77
• Design competition based on the lowest final cost
• Selection of UOP - international company with extensive refining experience
• Single design integrating all the refinery on-site and off-site
• Designer involved from conceptual design to technical assistance in the start up
• Scale economies (RPRE: 300kbpd modules)
• Maximum standardization of equipments specification
Age (years)
Scale (’000 bpd)
Current downstream cost
(US$ / bbl in 2010)
Lower refining costs due to design
quality and scale
Economies of scale and new implementation
strategies to reduce Capex, including:
PREMIUM REFINERIES Future refineries designed to optimize scale and resources
78
70%
95%
69%70%67%
86%
36%
15%
0
20
40
60
80
100
Hydrorefining Capacity relative to Distillation Capacity
23%
23% (current)
59% (2015)
74% (2020)
Adding value to domestic crude oil by producing diesel and gasoline in-line with international standards.
Underinvested over the past years requires catching up with hydrorefining capacity (for removal of sulfur)
HYDROREFINING INVESTMENTS Catch up phase to meet international standards for quality products
79
US$ 16 billion
1.01.0
3.2
4.9
5.9
7.0
4.5
2.3
1.1
0.20.1
15 14 13 12 11 10 9 8 7 6 5
<250
US$16 billion in 2011-15 Reduction in sulfur level
Avg. Sulfur Level – Diesel (ppm)
• After 2013 investment can be focused principally on expansion alone
INVESTMENTS IN QUALITY Investment cycle in modernization and quality has peaked
80
Refinery prepared to process ultra-
heavy oil, ...
Average API
2010
API
RNEST
-38%
1
2010
Average
RNEST
... with high diesel yield on its product
mix ... 2
39%
70%
Solomon Indice
2010 Average RNEST
... by having high complexity 3 Additionally, simultaneous processing
of immiscible synthetic and ultra-heavy
crude required two separate trains of
115 kbpd, increasing project costs.
4
7,7
9,6
26
17
5 RNEST also requires $ 4.2 billion investment
in infrastructure and offsites, equal to 20% of
total project cost.
16
ABREU E LIMA (RNEST) CAPITAL COST Unique factors contributed to cost that can be avoided for Premium Refineries
81
BIOFUELS
82
2011-2015 INVESTMENTS US$ 4.1 billion
Ethanol
Ethanol Logistics
Biodiesel
R&D
273%
1.5
Pbio + Partners
5.6
16%
735
855
Pbio + Partners
Market Share Pbio+Partners:
• 2011: 28%
• 2015: 26%
Biodiesel supply (’000 m³)
2011 2015
Ethanol supply (million m³)
2011 2015
Market-share Pbio+Partners:
• 2011: 5.3%
• 2015: 12%
47%
7%
32%
14%
1.9
1.3
0.6
0.3
INVESTMENTS IN BIOFUELS Focus to increase the ethanol supply in Brazil
83
Natural Gas, Electric Energy and Fertilizers
84
INVESTIMENTS US$ 13.2 billion in gas-chemicals plants, electric energy, network and LNG
5,9
0,30,8
26%
21% 45%
2% 6%
Network
Electric Energy
Gas-chemicals plants
(Nitrogenized)
International
LNG
• Investment cycle in the expansion of the
transportation network to be completed in
2011;
• New natural gas delivery spots, negotiation with distributors to increase sales and diversification of contractual arrangements ;
• Consolidated investment in thermal power generation;
• Operating in the LNG chain and serving the thermal power market;
• Increased portion of investments allocated to the conversion of natural gas into urea, ammonia, methanol, and other fertilizers, and gas-chemicals.
2011-15 Investments US$13.2 billion
85
1ST INVESTMENT CYCLE Natural gas transportation and processing infrastructure now largely concluded
5.623 5.6676.098
7.086
7.991
9.538 9.728
0
1.000
2.000
3.000
4.000
5.000
6.000
7.000
8.000
9.000
10.000
2003 2005 2007 2008 2009 2010 2011
Transportation Infraestructure (km) km
Investments: R$ 29,2 billion
Compressor Stations and
Delivery Points
Compressor
Stations
Delivery
Points
By 2013 2003 to 2011
86
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
UFN III (Sep/14)
Regás Bahia
(Jan/14)
New NG TPPs
Urucu-Manaus
Gasbel II
Gasduc III
Gastau
Gasene
Gaspal II
Gasan II
Pilar-Ipojuca
Atalaia-Itaporanga
Cacimbas-Vitória
Catu-Pilar
Japeri-Reduc
Gascav
Gascar
LNG Pecém
LNG BGUA
TPP Bicomb. Conversion
Termoaçu
Cubatão
Sulfato de Amônio (May/13)
ARLA 32 (out/11)
Ecomps + Delivery Spots + Network Maintainance
UFN IV (Jun/17)
Acquisition TPPs
UPGN Cabiúnas – Route 2 Pre-Salt
(Aug/14)
Adaptation of the Gas Pipelines Network (US$ 3.34 bi)
New TPPs run on Natural Gas (US$ 1.82 bi)
LNG regasification (US$ 0.74 bi)
Chemical Transformation of NG (US$ 5.85 bi)
TPP Commitments (US$ 0.94 bi)
Renewable Energy: Wind Power and Biomass (US$ 0.02 bi)
Natural Gas Liquefaction (US$ 0.10 bi)
%
do
In
ve
sti
me
nto
To
tal
UFN V (Sep/15)
1st Investment Cycle
COMPLETED
2nd Investment Cycle
2011-2015 BP
86
2ND INVESTMENT CYCLE: Monetization of the pre-salt reserves drives future investments
87
Total
Demand
Thermal Power Plants Demand : Petrobras + Third parties
NATURAL GAS SUPPLY & DEMAND (MILLION M3/D)
Increasing domestic gas supply and demand flexibility
Firm
Flexible 30
24
30
24
30
24
2020 2015 2011
Total
Supply 173 149
106 200 151 96
Downstream
UPGN
Fertilizers 61
32
16 39
25
17
Petrobras’ Demand: Downstream + Fertilizers
Non-thermal power
NG Distributors Demand
2020 2015 2011
2011 2015 2020
2011 2015 2020
2011 2015 2020
Guanabara Bay
Pecém
Bahia 41
20
14 41
20
14 21
14
Bolivian Supply
Domestic NG Supply (Includes third parties)
Supply via LNG Regasification Terminals
Inflexible
Flexible 40
13
37 25
2011 2015 2020
To be contracted (5.5 GW)
76 (15.1 GW)
59 (10.7 GW)
38 (6.7 GW)
DEMAND PCS 9.400 kcal/m³
4969
936
9
9 Northern Region
Other Regions
55
78
102
SUPPLY
88
International
89 89
90
INVESTMENTS Focus on exploration and production in offshore and frontier areas
Key Projects:
• Cascade / Chinook
• Saint-Malo
• Tiber
Key Projects:
Bolivia San Alberto / San Antonio Serving the Brazilian market
Peru Integrated Gas Project – Lots 57 and 58 Oil Production – Lot X
Argentina Maintenance of Existing Assets
Key Projects:
• Nigéria Akpo Agbami Egina • Angola Block 26
US$11 billion
Activities in 27 countries in the E&P, RTCP, Distribution, and G&E segments
Africa’s West Coast
Gulf of Mexico
Latin America
Corporate
Distribution
G&E
E&P
RTCP
87%
1%
3% 2% 7%
91
CASCADE - CHINOOK DEVELOPMENT First oil expected from the ultra deep of GOM in 2011
Cascade
Chinook
FPSO Shuttle Tanker
FSHR
Tree
Control Umbilical
Power Umbilical
Flow line
Gas Export Pipeline
Manifold
Petrobras America operated fields
- Water Depth ~ 2,500 meters
(8,200 feet).
US regulators approved Petrobras
plans to bring first FPSO (*) to the
US Gulf of Mexico.
Technologies new to US Gulf of
Mexico, including disconnectable
turret buoy, allowing the vessel to
move offsite during hurricanes,
and transportation via shuttle
tanker.
(*) FPSO – Floating, Production, Storage and Offloading facility.
Petrobras has an extensive experience in the use of FPSO with
fifteen units currently under operation offshore Brazil.
Source: Petrobras America inc
92
6 blocks (1 in production)
Operator in prolific Block 18
with 30% stake (First oil: 2010)
WEST AFRICA
AGBAMI
(PB 13%, Operator:
Chevron):
First oil: July 2008 / Peak:
232,000 bpd in 2009 (total)
AKPO
(PB 20% - Operator: Total):
First oil: March 09 / Peak:
175,000 bpd in 2009 (total)
6 blocks (1 in production)
Operator in prolific Block 18 with
30% stake (First oil: 2010)
Petrobras Stake in Akpo
and Agbami: 64,000 bpd by
end of 2009.
Proven Reserves (SEC -
2008): 131,3 MM boe
(% Petrobras)
93
FINANCIAL CONSIDERATIONS
94
2010-14 Business Plan
53%
33%
2% 1%1% 2%
8%
2,9
• 5% of investments will be made overseas, 87% of which in E&P.
• Note: HSEE (US$ 4.2 bi), IT (US$ 2.7 bi), Technology (US$ 4.6 bi), Logistics (US$ 17.4 bi) and Maintenance & Infrastructure (US$ 20.6 bi)
2011-15 Business Plan
US$224.7 billion US$224 billion
65,5
14,74,1
3,24,2
2,3
65,5
14,7
4,1
3,24,2
2,4
2011-2015 INVESTMENTS Investment level similar to the previous Plan, with more focus in E&P
57%31%
6%2%
1%1% 2%
E&P RTC
Gás,Energia & Gás Química Petroquímica
Distribuição Biocombustíveis
Corporativo
(*) US$22.8 billion in Exploration
(*) 118.8
73.6
17.8
5.1
2.4
3.5
2.9
127.5 70.6
13.2
3.8
3.1
4.1
2.4
56%31%
7%2%
1%1% 2%
E&P RTC
Gás,Energia & Gás Química Petroquímica
Distribuição Biocombustíveis
Corporativo
Biofuels
Gas, Energy & Gas Chemicals
Distribution
Corporate
E&P
Petrochemicals
RTM
95
Exploration & Production
+ US$8.7 billion
New Projects
• Transfer of Rights
• New Pre-Salt Units (Lula)
• Infrastructure
• New Discoveries and R&D
Excluded, Revised and/or Postponed Projects
• Projects discontinued after unsuccessful exploratory phase
• Revision of Development Projects
KEY CHANGES IN PORTFOLIO Reassignment of E&P investments
Gas & Energy
- US$4.6 billion
Supply
(includes Petrochemicals)
- US$4.3 billion
New Projects • TPP Barra do Rocha I • TPP Bahia II
Projects concluded in 2010
• Gas pipelines: Gasene, Pilar-Ipojuca, Gasduc III and Gasbel II
Excluded, Revised and/or Postponed Projects
• Postponement of projects: UFN IV, UFN V, GTL Paraffins and Gas FSO
• Exclusion of Catu-camaçari gas pipeline and Ecomp Itajuípe
• Exclusion of TPP projects (from 2010 auctions)
New Projects
• New Comperj units
• Oil Logistics
Projects concluded in 2010
• Braskem capital contribution
• Fuels quality investment
Excluded, Revised and/or Postponed Projects
• Postponement of Premium I Refinery
96
Based on 2011-2012 forecasts: Banks (Source: Bloomberg)
Based on 2013-2015 forecasts: PIRA, DOE, CERA, WoodMackenzie, IEA
Petrobras’ Scenarios
95
80
US
$/b
bl
KEY VARIABLES Oil price assumptions within market expectations
Assumptions
No Capital Increase in the period
Investment grade maintenance
Key variables for Cash Generation and Investment Level
• Oil price • Foreign Exchange Rate • Brazilian Market Growth • Average Realization Price (ARP) – Brazil
– International Parity – International margins per product
• Oil and products exports and imports • Investment Program • Divestitures and business restructuring • Third-party funding
97
125,0148,9
224,7 224,7
91,4 67,0
31,4 30,926,1 26,1
13,6 13,6
Scenario A Scenario B
US$ 256.1 US$ 255.6 US$ 256.1 US$ 255.6 Key assumptions
Scenario A Scenario B
Exchange rate (R$/US$)
1.73 1,73
Brent (US$/bbl)
2011 – 110 2011 – 110
2012 – 80 2012 – 95
2013 – 80 2013 – 95
2014 – 80 2014 – 95
2015 – 80 2015 – 95
Leverage (Min. and Max.)
23% - 32% 22 % - 29%
Net Debt/EBITDA (Average)
1.9 1.5
ARP (R$/bbl) 158 177 Debt Amortization
Investments
Divestment and Restructuring
Cash
Third-Party Resources (Debt)
Operating Cash Flow (After Dividends)
Sources Use Sources Use
CASH GENERATION AND INVESTMENTS Divestment and traditional funding sources adequate for Plan needs
• 40% of capex in dollar in comparison to 37% in the Business Plan 2010-14
98
-5.000
10.000 15.000 20.000 25.000 30.000 35.000 40.000 45.000 50.000
OCF 2011* Capex 2009 Capex 2010 Capex 2011* Maintenance Capex (Est.)
E&P Downstream Gas & Energy Others
US$ MM
35,134 45,078
16,000
33,447
Assumptions to Maintain Existing Capacities: • $12 per barrel to replace 830MM BBL´s of production • $1.5 bn. - Exploration • $1.5 bn. - Refinery maintenance •$1.5 bn. - Gas & Power maintenance • $1.5 bn. - Other Maintenance
CAPEX AND CASH FLOW Cash flow supports maintenance plus growth
* LTM as of 6/30/11
45,897
99
EBITDA Growing and stable cash flow generation
Adjusted EBITDA (US$ bn)* Adjusted EBITDA Breakdown per Segment (US$ bn)**
Note: (*) US GAAP (**) Adjusted according average exchange rate
35,4
19,3
30,5
41,0
-1,6
11
4,2
0,8
-0,2
0,9
1,7
2,4
1,4
1,1
1,3
1,3
0,2
1,1
2,2
2,4
E&P RTM G&P Distribution International
31,1
29,0
32,5
34,9
2008 2009 2010 LTM
2008 2009 2010 LTM
99
100
LEVERAGE AND LIQUIDITY Solid balance sheet with high liquidity
R$ billion 06/30/11 12/31/10
Short-term debt 16.7 15.7
Long-term debt 111.6 102.2
Total Debt 128.3 117.9
Cash and Cash Equivalents 34.7 30.3
Tradeable Securities (maturing in more than 90 days)
24.8 25.5
Adjusted cash and cash equivalents 59.5 55.8
Net Debt 68.8 62.1
Net Debt/EBITDA 1.07X 1.03X
US$ billion 06/30/11 12/31/10
Net Debt 44.1 37.3
o Stable leverage, with maintenance of high cash position.
o Upgrade of Petrobras’ foreign-currency risk rating from Baa1 to A3 (Moody's).
1.550.96 1.03 1.03 1.07
35%
16% 17% 17% 17%
-20%
0%
20%
40%
-0,5
0,5
1,5
2,5
3,5
4,5
5,5
2Q10 3Q10 4Q10 1Q11 2Q11
Net Debt/EBITDA Net Debt/Net Cap.
101
2%
6%4%
5%
9%
74%
2011 2012 2013 2014 2015 After 2016
Total Indebtedness (US$ 69,431 million as of December 31, 2010)
By Category By Currency
By Maturity
By Maturity By Rate
Fixed57%
Floating
43%
LT Financing
87%
ST Financing
13%
BNDES
33%
Financial Institutions
29% Intl Capital
Markets 21%
Export Credit 10%
Other 7%
Dollar 46%
Real
27%
Yen
3% Real Indexed to Dollar
24%
DEBT PROFILE Diversified creditor base, long tenors, largely linked to dollars
102
2005 2006 2007 2008 2009 2010
Nyse
PBR
PBR/A
Bovespa
PETR3
PETR4
Turnover NYSE & Bovespa (Daily Average Turnover)
(US$ MM)
PETR4 (Bovespa) PBR/A (Nyse) PETR3 (Bovespa) PBR (Nyse)
(% category and US$MM)
1,308
1,930
992
483
219
Turnover 2010/2005 = 619%
o Turnover of PBR 3 times the volume of PBRA on the NYSE
o Turnover of PN 5 times the volume of the ON
o Probable explanation: Cultural. Brazilians familiar with PN´s and would not pay premium for ON´s
TRADING VOLUMES Voting and non-voting shares highly liquid on both the Bovespa and NYSE
31%
6% 5%6%
5%6%
7%
25% 21%20%
20% 19%
19%
43% 47% 43%50% 52%
47%
26% 23%27% 27%25%
2005 2006 2007 2008 2009 2010
Nyse
PBR
PBR/A
Bovespa
PETR3
PETR4
1,359
103 * Dividends includes the Interest on own Capital (IOC)
2006
0.8
2007 2008 2009
0.7
0.9
1.2
2006 2007 2008 2009
2.9 3.0
4.3 3.5
US$
Net Income per ADR
US$ US$
Price per ADR (Max-Min)
2006 2007 2008 2009
26.7 17.5
58.8
21.1
75.2
14.9
53.0
23.0 31.9
48.9
2010
3.9
2010 2010
1.4
Dividends per ADR
o Brazilian Corporate Law requires a minimum annual distributions equal to 25% of net income
o Dividends paid each year based on prior years income
DIVIDENDS Payments based on percentage of net income
