Xx xxxxxxxx 20xx
Equity Research
Petrobras
xxxxxxxxxxxxxxxxxxxxxxxxxxx
The Petrobras Handbook
An investor’s guide to a unique oil company
March 2014
Research Analysts
The oil company
FOTO
Vinicius Canheu, CFA
+ 55 11 3701 6310
vinicius.canheu@credit–suisse.com
Andre Sobreira, CFA
+ 55 11 3701 6299
andre.sobreira@credit–suisse.com
With over 85 thousand employees, $140bn in revenues, 2,000kbd of oil production, 16bn barrels of reserves, privileged
access to one of the world’s largest oil frontiers and to a large and growing Brazilian fuel market, Petrobras is Brazil’s
most important company and also one of the most unique and intriguing oil companies in the planet. Founded 60 years
ago, the company is now at a crucial moment in its history, facing great opportunities but also meaningful challenges.
Understanding the company, its opportunities and challenges have never been more important.
The investor
Investors, as the company, are also at one of the most unique, controversial, and important moments in their investment
decisions in Petrobras’ shares. Despite close to $200bn in investments over the past five years, Petrobras’ financial
performance and balance sheet is at one of the lowest points in history. Production has not grown significantly since
2010, Downstream losses have never been higher, and the balance sheet has never been as stretched. The share price
has reflected those trends, and Petrobras’ market value today is at similar levels as 2005, before the discovery of the
pre-salt, and lower than in 2008, when the oil price hit close to $30/bbl, compared to $100/bbl today. Looking ahead,
production can finally get back to a strong growth path, but issues remain, especially regarding how the new pricing
policy will be implemented in a year with a number of economic challenges, and Brazilian presidential elections. Does the
current share price offer an opportunity, or is Petrobras a value trap?
The guide
At such an important moment for the company and for investors, a deep understanding of Petrobras and the factors
influencing the share price is paramount. With this in mind, we provide a detailed but user-friendly 120-page guide,
addressing current debates in the investment case, key new and old themes for a better understanding of Petrobras,
how to deal with a tough valuation dilemma, further detail on each of the company’s divisions, extensive comparison with
other Global Oil Companies, and other topics relevant from a wider Brazilian Oil sector perspective.
Vinicius Canheu, CFA
55 11 3701.6310
[email protected]
DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, AND THE STATUS OF NON-US
Andre
Sobreira,
CFA Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm
ANALYSTS.
US Disclosure:
55
3701.6299
may11
have
a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.
[email protected]
DISCLOSURE APPENDIX CONTAINS ANALYST CERTIFICATIONS AND THE STATUS OF NON-US ANALYSTS. U.S. Disclosure: Credit Suisse does and seeks to do business with companies covered in its research
reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment®
CREDIT SUISSE SECURITIES RESEARCH & ANALYTICS
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LatAm Oil & Gas
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Table of Contents
Four slides you can’t forget (pages 3-7)
A little m ore on Upstream (pages 66-81)
If we had to pick four slides to understand Petrobras and the
investment case, these would be it: (1) a summary slide
explaining how PBR works, (2) an explanation of production
growth, (3) PE and EV/EBITDA sensitivities, (4) mathematics of
the impact of 10% change in key variables for PBR.
We provide detail and a recap of the Brazilian pre-salt, and also
analyse Petrobras’ ten most important fields, which represent
almost 70% of current production and therefore are very relevant
to understanding the company.
Six debates you need to know (pages 8-32)
A little m ore on Downstream (pages 82-95)
A deeper explanation on the six themes most debated by
investors: (1) production growth and decline rates, (2) the
Downstream pricing dilemma, (3) Libra, (4) Transfer of Rights,
(5) Dividend rules and differentials, (6) the balance sheet and
hypothetical capitalisation scenarios.
In this section, we overview Petrobras’ refineries, study the
Brazilian Downstream demand alongside the drivers for each
fuel type, and also the Distribution segment, with detailed
analysis on pricing and profitability dynamics in each region of
Brazil.
How to value Petrobras? (pages 33-40)
Understanding Gas & Power (pages 96-99)
For every year since 2010, anyone who would have tried to
make a value call on PBR would have been wrong. We discuss
the PBR value trap dilemma, the problems of a DCF for PBR,
absolute and relative value references, and why we think PBR
shouldn’t trade like the Russian Oils.
Gas & Power is one of Petrobras’ least known business, partly
because of its smaller size, but also because of complexity.
Results are volatile, and rising energy prices can actually imply in
lower profitability for the business.
Petrobras vs Big Oil: The Order of Merit (pages 41-59)
Petrobras financial statem ents (pages 100-107)
In this section, we provide a thorough analysis of Petrobras
versus the Global Oil Industry across a number of financial and
operational metrics, using the depth and breadth of Credit
Suisse’s Global Energy coverage.
A numerical review of PBR’s financials
The business plan (pages 60-65)
Other Braz ilian oil them es (pages 108-119)
In the longer-term, Petrobras should be able to cater for the
Brazilian market, with production = refinery capacity = domestic
demand, and PBR partners exporting. We also provide a view of
how the plans evolved over time and impact of Graça’s
structural programmes.
We analyse two wider topics for the Brazilian Oil Industry: (1)
Labour trends and wage inflation – Brazil has presented one of
the highest wage inflations in the oil sector globally; and (2) The
comeback of the licensing rounds, with 2013 seeing three
rounds – Equatorial Margin, Libra, and Onshore.
Disclosures (pages 120-124)
2
March 2014
LatAm Oil & Gas
Equity Research
Four slides you can’t forget
FOTO
#1: Petrobras in one slide
Petrobras’ business model is unique among oil companies in that Petrobras is
close to fully integrated between Upstream and Downstream. The E&P assets are
just off the Brazilian coast, which is also the company’s Downstream market. Both
E&P assets and the Downstream market have strong growth potential. In one slide,
we show the main volumes, costs and prices of PBR’s Upstream and Downstream,
a quick way to understand the company’s business model.
#2: Production will grow now
The Petrobras growth story has proved to be a disappointment for the past four
years. Since 2010, Petrobras has not managed to grow its oil production above the
current 2,000kbd level. Causes for lack of growth are by now well-known: (1)
Capacity additions delays, (2) Focus of resources (human and financial) on
exploration and discovery of the pre-salt province, (3) a resulting lack of focus in
the Campos basin, which have increased observed decline rates above 10% and
decreased efficiency to c.70%. All of these three main reasons are being resolved
now: (1) Platforms are finally coming on stream, with 2013 being the highest year
ever for additions (660kbd), (2) Focus is back on production, (3) Efficiencies in
Campos are being resolved. The growth path is back.
#3: Back-of-the-envelope sensitivities
Ever since Petrobras announced the possibility of a transparent pricing mechanism
by end November, knowing the impacts of gasoline and diesel price increases
became paramount. If Petrobras indeed manages to grow production by 7%+ pa
in the next years and closes the gap with international prices, the performance of
the business can improve significantly, implying in a cheap valuation for the shares.
If the FX depreciates further to 2.6x, if Petrobras manages to grow production by
c.15% and increase prices by 10-15% in the next two years, it would be trading at
5.5-6.3x PE and 6.0-6.6x EV/EBITDA. A comeback to sector-average performance
in the medium-term would put PBR at $25/ADR, a significant upside to current
levels.
#4: 10% m athem atics
We provide simple mathematics on the impact of a 10% increase in production, a
10% depreciation of the BRL, a 10% increase in gasoline and diesel prices, and a
10% domestic-international price gap.
March 2014
LatAm Oil & Gas
Equity Research
Four slides you can’t forget
#1: Petrobras in one slide
 Integrated. Petrobras’ business model is unique among oil companies in that the company is close to fully integrated between Upstream and Downstream. The E&P
assets are just off the Brazilian coast, the company’s Downstream market, which enable significant logistics advantages. Both E&P assets and the Downstream market
have strong growth potential. Below we show the main volumes, costs and prices of PBR’s Upstream and Downstream, the core of the company’s operations and value.
E&P
Refining
Distribution
FOTO
FOTO
FOTO
Crude oil import/export
to adequate refinery mix
Revenues at $10/bbl discount to
crude
300kbd lighter
oil imports
$10/bbl royalties
$8/bbl Special Participation tax
$15/bbl lifting costs
$5/bbl of exploration costs and
SG&A
Crude Oil
Production
2,000kbd
300kbd heavier
oil exports
2,000kbd
refining capacity
200kbd
Diesel
imports
50kbd
Gasoline
imports
200kbd
Other products
200kbd
Jet and Fuel Oil
200kbd
Naphtha
200kbd
LPG
500kbd
Other
product
imports
1,000kbd
Gasoline
Gasoline and diesel future growth
at c.5% per year
Refined
Products
2,300kbd
18%
18%
4%
Other
5%
Diesel
30%
Fuel imports to supply
domestic market
White Flag
25%
Refined products sold at a
discount to international levels
$50/bbl cash generation
Source: Petrobras, Credit Suisse Research.
Products sold at parity / moving
average to international levels
4
March 2014
LatAm Oil & Gas
Equity Research
Four slides you can’t forget
#2: Production will grow now
 It’s different this tim e. The Petrobras growth story has proved to be a disappointment for the past four years. Since 2009-10, Petrobras has not managed to grow its
oil production above the current 2,000kbd level. Causes for lack of growth are by now well-known: (1) Capacity additions delays, (2) Focus of resources (human and
financial) on exploration and discovery of the pre-salt province, (3) a resultant lack of focus in the Campos basin, which have increased observed decline rates above
10% and decreased efficiency to c.70%. All of these three main reasons are being resolved now: (1) Platforms are finally coming on stream, with 2013 being the highest
year ever for additions (660kbd net to PBR), (2) Focus is now on production, (3) Efficiencies in Campos are being resolved. The growth path is back.
Petrobras production profile
4.5
CS estimates
10%+ p.a. growth
after 2016
Historical production
4.0
3.5
3.0
7%+ p.a. growth
until 2016
No growth
since 2010
2.5
 Franco (Buzios) 2
 P-75
 150kbd
 Espadarte
 Cd. Rio de
Janeiro
 100kbd
 Polvo
 90kbd
 Piranema
 30kbd
 Golfinho
 Cd. Vitória
 100kbd
 Marlim Leste
 P-53
 180kbd
 Golfinho
 Cd. Vitoria
 100kbd
 Roncador
 P-52
 180kbd
 Siri Pilot
 Cd. Rio
das Ostras
 15kbd
 Roncador
 P-54
 180kbd
 Marlim South
 P-51
 180kbd
2007
2008
 Tupi South
 Cid Sao Vicente
 30kbd
 Frade
 Frade FPSO
 100kbd
 Marlim Leste
 Cd. Niteroi
 100kbd
 Lula Pilot
 Cd. Angra dos
Reis
 100kbd
 Sidon / Tiro
 Atlantic Zephyr
20kbd
 Parque das
Conchas
 100kbd
 Jubarte
 FPSO P-57
 180kbd
Source: Petrobras, Credit Suisse Research.
 Sapinhoa Pilot
 Cd São Paulo
 120kbd
 FPSO Capixaba
 Cachalote/Balei
a Franca
 100kbd
 Camarupim
 Cid Sao Mateus
 25kbd
2009
 Lula NE
 Cd Paraty
 120kbd
2010
 Papa – Terra
 P-63
 150kbd
 Roncador
 P-55
 180kbd
 Marlim Sul
 SS P-56
 100kbd
2011
 Baleia Azul
 Cid Anchieta
 100kbd
2012
 Bauna /
Piracaba
 Cid Itajai
 80kbd
2013
 Sapinhoá
Norte
 Cid. Ilhabela
 150kbd
 (Start-up Q3)




 Franco (Buzios) 1
 P-74
 150kbd
Iracema Sul
Cd. Mangaratiba
150kbd
(Start-up Q4)
 Papa – Terra
 P-61 & TAD
 (Start-up Q2)




2014e
 Franco (Buzios)
3 (NW)
 P-76
 150kbd
 Carioca (Lapa)
 Cd.
Caraguatatuba
 100kbd
 Iara Horst
 P-70
 150kbd
 Lula Central
 Cid Saquarema
 150kbd




Iracema Norte
Cd Itaguai
150kbd
(Start-up Q3)
2015e
 Franco (Buzios)
4 (Sul)
 P-77
 150kbd
 Lula Norte
 P-67
 150kbd
 Lula Sul
 P-66
 150kbd
Pq. Baleias
P-58 FPSO
180kbpd
(Start-up Q1)
 Roncador
module 4
 P-62
 180kbd
 (Start-up Q2)
mnbpd
Petrobras targets
 Lula Alto
 Cd Marica
 150kbd
2016e
 Lula Oeste
 P-69
 150kbd
2.0
 Tupi NE
 P-72
 150kbd
 Entorno de
Iara
 P-73
 150kbd
1.5
Pre-Salt + Libra
 Iara NW
 P-71
 150kbd
Transfer of Rights
 Sul
 Pq Baleias
FPSOs already
contracted
Post-Salt
 Carcará
 Deepwater
Espirito Santo
 Florim
 Libra
 Lula Ext Sul +
ToR Sul de Lula  Deepwater
 P-68
Sergipe I
 150kbd
 Tartaruga Verde
e Mestiça
2017e
 Deepwater
Sergipe II
 Maromba
 Franco (Buzios)
5 (Leste)
 Marlilm Revitali II
 Marlim Revital I
 Júpiter
 Espadarte III
2018e
2019e
2020e
5
March 2014
LatAm Oil & Gas
Equity Research
Four slides you can’t forget
#3: Back-of-the-envelope sensitivities
 Know the num bers. Ever since Petrobras announced the possibility of a transparent pricing mechanism by end November, knowing the impacts of gasoline and diesel
price increases became paramount. If Petrobras indeed manages to grow production by 7%+ pa in the next years and close the gap with international prices, the
performance of the business can improve significantly, implying in a cheap valuation for PBR shares. In the charts below we show how much.
2014 bear case: 5% production growth
EV/EBITDA sensitivities
0%
5%
10%
15%
20%
25%
2.0
4.4
3.9
3.4
3.1
2.8
2.6
FX rate (BRL/USD)
2.2
2.4
6.0
8.5
5.1
6.9
4.4
5.8
3.9
5.1
3.5
4.5
3.2
4.0
2.6
13.1
9.9
8.0
6.7
5.7
5.0
2.8
24.7
15.8
11.6
9.2
7.6
6.5
Price
increases
Price
increases
P/E sensitivities
0%
5%
10%
15%
20%
25%
2.0
4.8
4.4
4.0
3.7
3.4
3.1
FX rate (BRL/USD)
2.2
2.4
5.9
7.3
5.4
6.5
4.9
5.9
4.4
5.3
4.1
4.9
3.8
4.5
2.6
8.9
7.9
7.1
6.4
5.8
5.3
2.8
11.0
9.6
8.5
7.6
6.9
6.3
2.0
4.6
4.1
3.8
3.5
3.2
3.0
FX rate (BRL/USD)
2.2
2.4
5.5
6.7
5.0
6.0
4.6
5.5
4.2
5.0
3.9
4.6
3.6
4.2
2.6
8.1
7.2
6.5
5.9
5.4
5.0
2.8
9.8
8.7
7.8
7.0
6.4
5.8
2.0
4.5
4.1
3.8
3.5
3.2
3.0
FX rate (BRL/USD)
2.2
2.4
5.4
6.3
4.9
5.8
4.5
5.3
4.1
4.8
3.8
4.5
3.5
4.1
2.6
7.5
6.7
6.1
5.6
5.2
4.8
2.8
8.7
7.9
7.1
6.5
6.0
5.5
2014 base case: 7% production growth
EV/EBITDA sensitivities
0%
5%
10%
15%
20%
25%
2.0
4.1
3.6
3.3
3.0
2.7
2.5
FX rate (BRL/USD)
2.2
2.4
5.5
7.4
4.7
6.2
4.1
5.3
3.7
4.7
3.3
4.1
3.0
3.7
2.6
10.8
8.5
7.0
6.0
5.2
4.6
2.8
17.4
12.5
9.7
7.9
6.7
5.8
Price
increases
Price
increases
P/E sensitivities
0%
5%
10%
15%
20%
25%
2015 bull case: 20% production growth in two years
EV/EBITDA sensitivities
0%
5%
10%
15%
20%
25%
Source: Credit Suisse Research.
2.0
3.6
3.2
2.9
2.6
2.4
2.2
FX rate (BRL/USD)
2.2
2.4
4.5
5.9
4.0
5.0
3.5
4.4
3.2
3.9
2.9
3.5
2.7
3.2
2.6
7.8
6.5
5.5
4.8
4.3
3.9
2.8
10.9
8.6
7.1
6.1
5.3
4.7
Price
increases
Price
increases
P/E sensitivities
0%
5%
10%
15%
20%
25%
6
March 2014
LatAm Oil & Gas
Equity Research
Four slides you can’t forget
#4: 10% mathematics
A 10% increase in production equals…
A 10% FX depreciation equals…
2,000kbd of current oil production
$80bn of revenues in USD
x 10% increase in production
$60bn of revenues in BRL
= 200kbd
x 10% BRL depreciation
x $50/bbl cash margin per Upstream barrel
= $6bn decrease in BRL-related revenues (i)
x 0.365
= $3.6bn/ year in additional cash generation
$85bn of cash costs in USD
$10bn of cash costs in BRL
x 10% BRL depreciation
A 10% gasoline and diesel price increase equals…
= $1bn decrease in BRL-costs (ii)
(i)+(ii) = $5bn decrease in cash generation
500kbd gasoline sold by PBR
x $90/bbl price of domestic gasoline (with FX at 2.3)
x 10% gasoline price increase
x 0.365
= $1.6bn/ year in additional cash generation from gasoline
1,000kbd diesel sold by PBR
x $100/bbl price of domestic diesel (with FX at 2.3)
x 10% diesel price increase
x 0.365
= $3.6bn/ year in additional cash generation from diesel
Source: Credit Suisse Research.
A 10% gap with international prices equals…
200kbd of current diesel imports
+ 50kbd of current gasoline imports
= 250kbd of imports
x $10/bbl (equal to a 10% gap with int’l prices)
x 0.365
= $900m / year of losses
PS: note current gap is around 20%
7
March 2014
LatAm Oil & Gas
Equity Research
Six debates you need to know
FOTO
#1: Production growth and decline rates
Petrobras’ production has been one of the most hotly debated topic in the past
three years. Despite all the capex involved, production has remained stubbornly
stable at 2,000kbd. Decline rates in the Campos basin, alongside capacity addition
delays, have had a strong influence on production. In this section we review the
decline rate topic, and provide detail on how PBR’s decline rates seem to be
evolving recently (increasing in 2010-12, but in a downward trend in 2013).
#2: The Downstream dilemma
Downstream has been one of the main responsible for a deterioration in PBR’s
financials since 2010. High domestic gasoline and diesel demand coupled with fixed
refining capacity means rising imports. High and rising domestic inflation means there is
resistance to let Petrobras increase domestic prices. Rising oil price and a depreciating
BRL increase the difference between domestic and international prices, and PBR’s
losses with imports. We deep-dive in the Downstream dilemma, including its importance
for the country and whether it’s better for PBR to build a new refinery or to keep
importing at a loss.
#3: Libra was better than you thought
In our view, a high quality consortium (Shell and Total with a combined 40% stake) and
a bid at the minimum 41.65%, plus a technical body at the PPSA helm are reasons for
optimism that Libra can yield good returns, contrary to wider investor perception.
#4: Transfer-of-rights renegotiation. Will PBR have to pay?
2014 is the year when discussions for the ToR renegotiation between Petrobras and
the Federal Government will start. The market is generally of the view that higher oil
prices will mean a higher valuation for the 5bn bbls, and that Petrobras will have to pay
up more to the Government. We propose that higher costs and delays almost fully
offset the increase in oil prices. We provide extensive background in the ToR discussion
in this section, including valuation of the barrels and timing for the discussion.
#5: Different dividends, different ON-PN spread
In 2012 (and 2013), for the first time in its history, Petrobras decided to pay different
dividends for the different classes of shareholders. Extremely low earnings and tight
cash balances were the culprits. This has a direct implication for the PBR/PBRa
(PETR3/PETR4) spreads. We detail the dividend discussion in this section, suggesting
investors should think about three scenarios for the spread: R$1.0-1.4-2.0.
#6: The balance sheet
In this section, we provide a recap of Petrobras’ balance sheet, showing how it
deteriorated to the worst levels in PBR’s history. We also discuss expensing vs
capitalising debt.
March 2014
LatAm Oil & Gas
Equity Research
Debate #1: Production growth and decline rates
The production equation
 Production (t) = Production (t-1) + Additions (t) – Decline (t). Petrobras’ production has been one of the most hotly debated topics in the past three years. Despite all the
capex involved, production has remained stubbornly stable at the 2,000kbd. Growing production revolves around a fairly simple equation that is difficult to put into
practice. The production additions in any given year depends not only on the volume of new projects (and keeping them on schedule), but also on how quickly those
projects ramp-up production once onstream (here, the supply chain is also important to keep drilling and plugging new wells fast enough, and also weather conditions
needed to allow the installation of the new wells). The production decline, on its turn, is dependent both on geological factors that determine the actual decline rate of the
fields, and on operational efficiency factors that include adequate equipment maintenance. Both the additions (delays of new capacity, slower ramp-up) and decline
(seemingly less an issue of geology but more of operational efficiency) have been responsible for PBR not growing production and coming short of targets (which were
arguably more aggressive in the past than they are now).
Petrobras production breakdown (kbd): new capacity additions, ramp-up, and decline are key
4,000
Domestic oil production (kbd)
3,500
Growth projects:
43 new platforms
from 2010 to 2020
3,000
2,500
2,000
1,500
Legacy offshore production:
trying to manage decline
rates and increase
operational efficiency
1,000
500
0
Q1 06
Onshore production
Q1 07
Q1 08
Source: Petrobras, ANP, Credit Suisse Research.
Q1 09
Q1 10
Q1 11
Q1 12
Q1 13
Q1 14E
Q1 15E
Q1 16E
Q1 17E
Q1 18E
Q1 19E
Q1 20E
9
March 2014
LatAm Oil & Gas
Equity Research
Debate #1: Production growth and decline rates
Decline rates, a global issue
 Diagnosis. Increasing decline rates are not only a potential problem to Petrobras in the Campos
basin. Indeed, this is an important trend globally, as evidenced by an IEA study (World Energy
Outlook 2008). The IEA concluded that decline rates for fields which started producing in the
1990s-2000s (the same period where most of Petrobras’ fields in Campos had first oil) are on
average 10.6%-12.6%, much higher than decline rates of 3.9%-7.9% in the three decades
preceding this period (top right chart).
 Reasons. The IEA gives a number of reasons for the increase in decline rates over the years, with
field size and location being the two most important factors in explaining a field production profile
(and thus its decline rates). Small fields reach peak production sooner, produce a higher share of
initial reserves at peak, but decline more rapidly than large fields. This rule only does not apply to
deepwater fields. Although deepwater fields are usually large in size, their production profile
behaves similarly to the ones of small offshore fields, with peak production being achieved
relatively quickly and representing a larger share of total field reserves, implying a shorter plateau
and steeper decline rates. The IEA attributes this in part to the need of offshore developers to bring
in production faster as a means to justify the larger capital expenditures relative to onshore fields.
IEA observed post-peak decline rates by vintage (%)
14.5%
OPEC
Newer fields showing
higher decline rates
Non-OPEC
12.6%
11.6%
World
10.6%
8.3%
6.8%
5.9%
5.9%
5.0%
4.6%
3.9% 3.5%
2.8%
7.9% 7.5%
 Outlook. The IEA argues that natural decline rates could change significantly in the future in all
regions, with a higher mix of smaller, offshore reservoirs. This would be offset by large-onshore
developments in the Middle East. Decline rates in US shale are still unknown at this stage.
IEA-projected change in decline rates and RP ratios by 2030
22%
2030
Pacific
20%
Natural decline rate
1970s
2007
Super-giant
Giant
Large
All fields
World
8.9%
Latin America
6.6%
5.6%
Africa
6%
10.9%
7.7%
Asia
8%
2000s
Deepwater, large sandstone
fields showing the highest
decline rates
14.2%
13.3%
13.1%
8.8%
Europe
12%
10%
1990s
11.2%
North America
14%
1980s
IEA observed post-peak decline rates by field type (%)
18%
16%
Pre 1970s
E. Europe/ Eurasia
Midde East
3.4%
6.5%
6.6%
6.3%
4.8%
3.4%
4.3%
3.4%
2.3%
4%
2%
0%
0
10
20
30
40
50
60
Remaining reserves/ production ratio (years)
70
80
Onshore
Offshore - shelf
Offshore deepwater
Carbonate
Sandstones
Source: ©OECD/IEA, World Energy Outlook 2008. Definition: Super Giant field defined as a fields with initial 2P reserves > 5bn bbls. Giant fields have initial 2P reserves between 500mmbbls and 5bn bbls, and large
fields contain more than 100mmbbls of reserves.
10
March 2014
LatAm Oil & Gas
Equity Research
Debate #1: Production growth and decline rates
Campos basin decline rates by vintage*
 Looking at vintages. Vintages are the best way we found to assess the decline rate issue for the Campos
basin. Looking at field-by-field or platform-by-platform production has the shortcome of not distinguishing
between ‘old’ production that is declining and ‘new’ production that comes from new platforms or from new
wells in existing platforms. Looking at vintages gets around these issues by looking at the production profile
of wells that started in any given year, and also allows us to see how the decline varies with time. We look at
vintage production both on an aggregate basis and on a per well basis.
 Conclusions: (1) Wells from 2005 and before show the lowest and more stable decline rate within the PBR
portfolio, which is expected given they have been declining for longer; (2) 2009 and 2010 wells have so far
shown the higher decline rates, mostly above 25%. FPSO Capixaba and P-57 have been declining strongly
and certainly have an impact in the 2010 vintage. P-51, P-53, Cid de Vitoria and Frade explain the 2009
vintage; (3) We observe a rise in decline rates in most vintages in 2010-2012, when PBR has not managed
to grow production. More recently in 2013, decline rates seem to be coming down, arguably due to PBR’s
efforts to increase operational efficiency (PROEF) together with a wider catch-up on maintenance.
 Im portant caveat. Decline rates are a technically complex issue. To be able to fully, correctly, and
technically analyse decline rates, one would have to look not on a field basis, platform basis, or even vintage
basis, but on a reservoir basis. One would have to consider initial reservoir potential, and try to break down
the decline into geological decline and declines due to operational efficiency. New wells being drilled in an
existing reservoir are part of reservoir management and should also be considered in decline rate analysis.
The public data provided by the ANP is already one of the most extensive compared to any other country,
but it does not allow the equity markets to break-down production by reservoir, or to distinguish what part of
the decline is due to operational efficiency vs geology. Petrobras is vocal about these points when defending
its c.10% decline rate. Our analysis is therefore a simplified version of reality, but which we believe serves
the purpose of educating the market in a very important topic for the Petrobras investment case.
Campos decline rates by vintage over time** (%)
40%
2009 wells
35%
30%
25%
2006 wells 2007 wells
20%
15%
2010 wells
2005 and before wells
10%
2008 wells
5%
0%
2006
2007
2008
2009
2010
2011
2012
2013
Campos basin production by vintage (kbd)
2,000
1,800
1,600
2013
1,400
2012
1,200
2011
2010
2009
2008
2007
2006
1,000
800
600
400
2005 and before
200
0
Jan-05
Aug-05
Mar-06
Oct-06
May-07
Dec-07
Jul-08
Feb-09
Sep-09
Apr-10
Nov-10
Jun-11
Jan-12
Aug-12
Mar-13
Oct-13
Source: ANP data, Credit Suisse Research analysis. Note: * We define vintage as the year in which a well starts production. ** Chart shows until 2010 wells – 2011 onwards wells were still either ramping up or with just
one year of decline for us to observe proper decline trends.
11
March 2014
LatAm Oil & Gas
Equity Research
Debate #1: Production growth and decline rates
Vintage production: 2005-2008
Campos basin 2005 and before vintage production (kbd)
1,600
1,400
Campos basin 2006 vintage production (kbd)
3.0
Average production
per well (RHS)
Decline of 13% p.a
since 2005
1,200
2.5
Vintage production (LHS)
1.0
0.5
200
0.0
Jun-06
Nov-07
Apr-09
Sep-10
Feb-12
Jul-13
Campos basin 2007 vintage production (kbd)
Decline of 17% p.a
since 2007
7
6
5
Average production
per well (RHS)
200
Decline of 19% p.a
since 2008
150
Vintage production (LHS)
50
350
8
7
2
0
Apr-07
Jul-08
Oct-09
Jan-11
Apr-12
Jul-13
May-12
Sep-13
10
Average production
per well (RHS)
Decline of 14% p.a
since 2009
300
9
8
7
6
250
6
5
200
5
4
150
0
Source: ANP data, Credit Suisse Research analysis.
0
Jan-06
9
1
Jan-11
3
Vintage production (LHS)
1
400
2
Sep-09
50
10
3
May-08
4
100
Campos basin 2008 vintage production (kbd)
250
0
Jan-07
200
8
1.5
400
100
Average production
per well (RHS)
150
800
0
Jan-05
9
2.0
1,000
600
250
4
Vintage production (LHS)
3
100
2
50
0
Jan-08
1
0
Dec-08
Nov-09
Oct-10
Sep-11
Aug-12
Jul-13
12
March 2014
LatAm Oil & Gas
Equity Research
Debate #1: Production growth and decline rates
Vintage production: 2009-2013
Campos basin 2009 vintage production (kbd)
400
Campos basin 2010 vintage production (kbd)
12
Average production per well (RHS)
350
10
300
8
200
6
150
4
Vintage production (LHS)
100
2
50
0
Jan-09
0
Dec-09
Nov-10
Oct-11
Sep-12
Campos basin 2011 vintage production (kbd)
500
350
12
300
350
10
250
300
8
200
450
400
Decline of 28%
since 2012
Aug-13
200
150
150
4
100
100
50
0
Jan-11
2
Vintage production (LHS)
0
Sep-11
May-12
Jan-13
Source: ANP data, Credit Suisse Research analysis.
Sep-13
Decline of 27% p.a
since 2011
50
0
Jan-12
Vintage
production
(LHS)
Jun-12
Nov-12
10
300
8
250
6
200
150
100
4
Vintage production (LHS)
2
50
0
Jan-10
0
Oct-10
Average
production
per well (RHS)
250
6
12
400
Campos basin 2012 vintage production (kbd)
14
Average
production
per well (RHS)
Average production
per well (RHS)
350
Decline of 30%
p.a since 2010
250
450
2012 vintage
apparently reached
peak, but not
enough time for us
to reach decline
conclusions
Apr-13
Sep-13
Jul-11
Apr-12
Jan-13
Oct-13
Campos basin 2013 vintage production (kbd)
16
160
14
140
12
120
10
100
8
80
6
60
4
40
2
20
0
0
8
Average
production
per well (RHS)
7
6
5
Production still
ramping-up
4
3
2
Vintage production (LHS)
1
0
Jan-13
Apr-13
Jul-13
Oct-13
13
March 2014
LatAm Oil & Gas
Equity Research
Debate #1: Production growth and decline rates
Two other themes: Watercuts and capacity additions
Watercuts in the Campos basin (%): producing more water than oil
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Jan-05
% of oil + NGL
Watercuts
above 50% for
the first time
end 2013
% of water
Aug-05
Mar-06
Oct-06
May-07
Dec-07
Jul-08
Feb-09
Sep-09
Apr-10
Capacity additions: a key driver of future production growth
 Espadarte
 Cd. Rio de
Janeiro
 100kbd
 Polvo
 90kbd
 Piranema
 30kbd
 Golfinho
 Cd. Vitória
 100kbd
 Marlim Leste
 P-53
 180kbd
 Golfinho
 Cd. Vitoria
 100kbd
 Roncador
 P-52
 180kbd
 Siri Pilot
 Cd. Rio
das Ostras
 15kbd
 Roncador
 P-54
 180kbd
 Marlim South
 P-51
 180kbd
2007
2008
 Tupi South
 Cid Sao Vicente
 30kbd
 Frade
 Frade FPSO
 100kbd
 Marlim Leste
 Cd. Niteroi
 100kbd
 FPSO Capixaba
 Cachalote/Balei
a Franca
 100kbd
 Camarupim
 Cid Sao Mateus
 25kbd
 Sidon / Tiro
 Atlantic Zephyr
20kbd
 Parque das
Conchas
 100kbd
 Jubarte
 FPSO P-57
 180kbd
2009
2010
Source: ANP data, Petrobras, Credit Suisse Research.
Very little
additions in
2011-2012
contributed
for low growth
 Marlim Sul
 SS P-56
 100kbd
2011
 Baleia Azul
 Cid Anchieta
 100kbd
2012
Jun-11
 Franco (Buzios) 2
 P-75
 150kbd
 Lula NE
 Cd Paraty
 120kbd
 Lula Pilot
 Cd. Angra dos
Reis
 100kbd
Nov-10
 Sapinhoa Pilot
 Cd São Paulo
 120kbd
 Papa – Terra
 P-63
 150kbd
 Roncador
 P-55
 180kbd
 Bauna /
Piracaba
 Cid Itajai
 80kbd
2013
 Sapinhoá
Norte
 Cid. Ilhabela
 150kbd
 (Start-up Q3)
Strong
additions in
 Iracema Sul
 Cd. Mangaratiba 2013-2014
 150kbd
 (Start-up Q4) key for future
growth
 Papa – Terra
 P-61 & TAD
 (Start-up Q2)




2014e
 Franco (Buzios)
3 (NW)
 P-76
 150kbd
 Carioca (Lapa)
 Cd.
Caraguatatuba
 100kbd
 Iara Horst
 P-70
 150kbd
 Lula Central
 Cid Saquarema
 150kbd




Iracema Norte
Cd Itaguai
150kbd
(Start-up Q3)
2015e
 Franco (Buzios)
4 (Sul)
 P-77
 150kbd
 Lula Norte
 P-67
 150kbd
 Lula Sul
 P-66
 150kbd
Pq. Baleias
P-58 FPSO
180kbpd
(Start-up Q1)
 Roncador
module 4
 P-62
 180kbd
 (Start-up Q2)
 Franco (Buzios) 1
 P-74
 150kbd
Jan-12
 Lula Alto
 Cd Marica
 150kbd
2016e
 Lula Oeste
 P-69
 150kbd
Aug-12
Mar-13
 Tupi NE
 P-72
 150kbd
 Entorno de
Iara
 P-73
 150kbd
Pre-Salt + Libra
 Iara NW
 P-71
 150kbd
Transfer of Rights
 Sul
 Pq Baleias
FPSOs already
contracted
Post-Salt
 Carcará
 Deepwater
Espirito Santo
 Florim
 Libra
 Lula Ext Sul +
ToR Sul de Lula  Deepwater
 P-68
Sergipe I
 150kbd
 Tartaruga Verde
e Mestiça
2017e
Oct-13
 Deepwater
Sergipe II
 Maromba
 Franco (Buzios)
5 (Leste)
 Marlilm Revitali II
 Marlim Revital I
 Júpiter
 Espadarte III
2018e
2019e
2020e
14
March 2014
LatAm Oil & Gas
Equity Research
Debate #2: The Downstream dilemma
Downstream losses in context
 Down 55% since end 2010. That’s how much the PBR share price has moved over the past three years. A number of factors contributed to that, from poor corporate
governance perception post the 2010 follow-on and Transfer of Rights, and lack of production growth since then. But Downstream, too, has been a key contributor. Until
end 2010, the business was run at a profit, with still low demand and low imports, and domestic refinery prices above international levels. Since 2010, higher domestic
demand and a fully utilised refinery park meant that gasoline and diesel imports soared. In addition, higher oil prices (from $70/bbl to a $100-120/bbl range), a
depreciated BRL (from 1.7x to 2.3-2.4x), and slow-to-increase domestic prices meant that Petrobras has been losing more money the more the domestic fuel market
grows. The chart below illustrates this well: Petrobras-refinery prices are now c.20% below international levels, and Downstream has been a loss-making business, to the
tune of $10bn/year. This has been a strong drag to Petrobras group earnings, which have fallen by 50%, precisely the $10bn Downstream is losing. It’s no surprise that
the share price is down by a similar amount. Therefore, understanding the Downstream dynamics is crucial to the investment case.
Gasoline and diesel gap vs international prices and Downstream EBITDA (% and BRLm)
Downstream quarterly EBITDA (BRLm)
8,000
Low consumption: no
need to import fuels
High consumption and discount on domestic
prices: PBR needs to import fuels with losses
60%
40%
6,000
Diesel gap (%)
4,000
20%
2,000
F
0
0%
Downstream EBITDA
(2,000)
-20%
(4,000)
Gasoline gap (%)
(6,000)
-40%
Gasoline and diesel gap vs int'l (%)
10,000
(8,000)
(10,000)
Jan-07
-60%
Jul-07
Jan-08
Jul-08
Jan-09
Source: Credit Suisse Research based on Petrobras, ANP and Bloomberg.
Jul-09
Jan-10
Jul-10
Jan-11
Jul-11
Jan-12
Jul-12
Jan-13
Jul-13
15
March 2014
LatAm Oil & Gas
Equity Research
Debate #2: The Downstream dilemma
Pieces of the puzzle: The price gap
Diesel
Gasoline
2.0
Oil prices and int’l gasoline
and diesel prices have rallied
since 2010
3
Diesel
GoM
2.5
BRL to USD
120
70
Brent
20
Jan-07
Gasoline
GoM
Jan-10
Jan-13
2
1.5
1
Jan-07
Jan-10
Source: Credit Suisse Research based on Petrobras, ANP and Bloomberg.
Jan-13
INTERNATIONAL PREMIUM
(+), DISCOUNT (-) TO
DOMESTIC PRICES (%)
170
$/bbl
The Braz ilian Real has
depreciated strongly since
2010 too
DOMESTIC VS
INTERNATIONAL PRICES
(R$/LITER)
2.5
2.0
1.5
1.5
Domestic
diesel
(R$/l)
1.0
1.0
0.0
Jan-07
Jan-09
Jan-11
Jan-13
0.0
Jan-07
60%
60%
30%
30%
0%
0%
(30%)
(30%)
(60%)
Jan-07
Jan-09
Domestic
Gasoline
0.5
Diesel
Gulf
(R$/l)
0.5
Gasoline
Gulf
(R$/l)
Jan-11
Jan-13
(60%)
Jan-07
Jan-09
Jan-09
Jan-11
Jan-11
Jan-13
Jan-13
16
March 2014
LatAm Oil & Gas
Equity Research
Debate #2: The Downstream dilemma
Pieces of the puzzle: Rising imports
Source: Credit Suisse Research based on Petrobras, ANP and Bloomberg.
1,000
0
(1,000)
(2,000)
(3,000)
(4,000)
(6,000)
Q1 13
(5,000)
Q1 12
(100)
2,000
Q1 11
(50)
3,000
Q1 10
0
4,000
Q1 09
50
Q1 13
Q1 13
Q1 12
Q1 11
Q1 10
Q1 09
Q1 08
Q1 07
5
100
Q1 12
Output of dom estic refineries
150
Q1 11
10
200
Q1 10
kbd
15
Q1 07
Imports (exports), kbd
250
Q1 09
20
0
Diesel
Gasoline
300
Q1 08
Dom estic dem and
Q1 08
350
25
… Higher im ports coupled with a
higher dom estic-international price
differential im ply in a higher
Downstream losses, to the tune of
$10bn/ year.
Q1 07
… Rising dem and im plies in higher
im ports. Petrobras today on average
im porting 200kbd of gasoline and
diesel com bined…
Downstream quarterly net income ($m)
Braz il has not added a new refinery
since the 1980s: the sm all
increm ental output is com ing from
higher utilisation (today already
90%+) or debottlenecking (already
done). Dem and continues to grow at
6% per year….
17
March 2014
LatAm Oil & Gas
Equity Research
Debate #2: The Downstream dilemma
Macroeconomic background: difficulty to increase prices
Government primary surplus
(% of GDP)
4.6%
4.3%
Diesel and gasoline price composition to the final consumer:
taxes are a large chunk of it (BRL/liter)
4.8%
4.3%
2.9
Lowest result since
2003 lim its relief of
federal taxes
4.0% 4.1%
2.8%
Resale margin
13%
4%
27%
3.1%
7%
1%
13%
2.4%
2.0%
1.9%
Distribution margin
2.5
11%
6%
14%
6%
1%
5%
State taxes
57%
Gasoline A
Federal Taxes
Freight
Anhydrous Ethanol
1.3%
35%
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014e
Inflation close to top range of target limits fuel price increase
(%)
Biodiesel
Gasoline
Diesel
Inflation: Fuels weight in IPCA Index
A 10% increase in gasoline increases inflation by 0.28pp
8%
7%
Food and beverages
Top range of
target
22%
Habitation
16%
6%
Transportation
4%
14%
5%
5%
2%
Jan-06
19%
IPCA, 12m
25%
Healthcare and Personal
Other
4%
3%
Diesel A
1%
0%
Gasoline
Ethanol
Diesel and GNV
Jun-07
Nov-08
Apr-10
Sep-11
Source: Credit Suisse Research, Credit Suisse Economics, MME, Bloomberg, ANP, IBGE.
Feb-13
18
March 2014
LatAm Oil & Gas
Equity Research
Debate #2: The Downstream dilemma
To build or to import?
 Is it better to keep im porting or to build a new refinery? We make the case* that the choice for Petrobras face within Downstream capital allocation is relatively
simple. It is less about whether the new refineries will be NPV positive or negative, but whether that NPV will be higher or lower than the negative NPV of continued
imports into the country. If we compare the economics of building a new-refinery in Brazil to continuation of imports, the decision of whether to build or not is independent
of domestic pricing policy, and rather on international gasoline-diesel spreads, freight, and capex/opex for the refinery. The scheme below shows why.
Choice 1: Build a new refinery
 Crude oil price
 Refinery capex
 Refinery opex
Decision taking: To build, or to import?
 Crude oil price
 Domestic
gasoline/diesel
prices
 Refinery capex
 Refinery opex
 Logistics capex
 International
gasoline/diesel prices
 Freight/cost to internalize
products
Domestic prices cancel out when comparing both options
Choice 2: Keep importing
 International
gasoline/diesel prices
 Domestic
gasoline/
diesel prices
 Freight/cost to
internalize products
 Capex to increase import
logistics, already strained
 Refinery capex
MINUS the capex
needed to increase
import logistics
 Refinery opex
 International
gasoline/diesel SPREADS
 Freight/cost to internalize
products
Source: Credit Suisse Research. Note: * IMPORTANT ASSUMPTION: This exercise assumes that the decision to build or import be taken strictly on an NPV basis and without any balance sheet constraints. With balance
sheet constraints, the balance favors a continuation of imports given the capex to finance the construction of a refinery could imply in expensive capital-raise needs.
19
March 2014
LatAm Oil & Gas
Equity Research
Debate #2: The Downstream dilemma
It’s better to build, if the newbuild capex is right
 We reach the conclusion* that if Petrobras manages to keep new refinery capex at $33k/bbl as planned (Abreu e Lima was $87k/bbl! but the overrun was very significant.
Recent refineries have averaged $18k/bbl), building a new 300kbd refinery has a NPV $3bn higher than importing, equivalent to a 15% ‘relative-IRR’.
Step 1: Decision taking: To build, or to import?
 Crude oil price
Step 2: Setting the assumptions
 International
 Refinery capex
gasoline/diesel
prices
 Refinery opex
 Freight/cost
 Capex to increase
Key assumptions for building a
new 300kbd refinery:
 $33/bbl capex
 $3/bbl opex
 Heavy-crude purchases at $10/bbl
discount to $100/bbl Brent
to internalize
products
import logistics,
already strained
Conclusion: ‘Building advantage’ cashflow IRRs
Key assumptions for importing
300kbd of oil products:
 Diesel spread to Brent of 15/bbl
 Import costs of $7/bbl
 Capex to increase import infrastructure
not taken into account (conservative)
as hard to gauge
Step 3: Modeling and comparing both options
25%
15,000
CS base case: building can be
better than importing if the
20%
10,000
IRRs (%)
newbuild capex is right
10%
0
(5,000)
5%
(10,000)
0%
20,000
30,000
40,000
50,000
Capex ($/bbl)
Costs to keep im porting
5,000
USDm
15%
60,000
70,000
80,000
(15,000)
Costs to build and operate a refinery
Building vs
import
advantage
2013
2016
2019
2022
2025
2028
2031
2034
2037
2040
Source: Credit Suisse Research. Note: * IMPORTANT ASSUMPTION: This exercise assumes that the decision to build or import be taken strictly on an NPV basis and without any balance sheet constraints. With balance
sheet constraints, the balance favors a continuation of imports given the capex to finance the construction of a refinery could imply in expensive capital-raise needs.
20
March 2014
LatAm Oil & Gas
Equity Research
Debate #2: The Downstream dilemma
Single refinery economics
Northeast Premium refineries (focussed on diesel, not gasoline), could yield a 6%
IRR if capex is controlled and kept at $33/bbl (implying a $10bn budget for one train),
and if long-term prices are aligned with international levels. This single simulation is
testimony to the lower returns Downstream face vs Upstream.
 Sensitivities: Budget overruns and pricing policy are the two single most important
factors that affect refining project profitability. A 20% capex overrun from $33/bbl to
$40/bbl capex would bring IRRs down from 6% to 4%. A 5% decrease on long-term
pricing would bring returns down from 6% to close to zero.
 Partnerships: In order to enhance expertise in design and operations, PBR executed
a Letter of Intent with Sinopec for the development of the Premium I refinery in
Maranhão. PBR had a similar LOI with Korean GS Energy for the Premium II in
Ceara, but it did not go through. In ‘exchange’ for expertise and a stake in the
refinery, PBR would have to ‘guarantee’ export-price parity for the partners, to ensure
the economics of the project work-out. Brazil is a country long-crude and short-refined
products which in theory would be a good place to build a refinery.
Refinery IRR sensitivity to capex at three pricing scenarios
6,4
50
4,7
40
2,6
30
20
0
100
200
Size (Kbd)
300
400
10
5% above int'l levels
10%
IRRs (%)
60
15
13%
5
8%
0
CS base case
International price levels
3%
Increase in capex
0%
(3%)
70
300kbd refinery train base case cash-flows (USDm)
15%
5%
PBR current park refining costs by size ($/bbl)
Age (years)
 Conclusion: A single 300kbd train with the product slate similar to the new
(10)
Decrease in price
(15)
5% below int'l levels
(5%)
20,000
30,000
40,000
Source: Petrobras, Credit Suisse Research.
50,000 60,000
Capex ($/bbl)
(5)
(20)
70,000
80,000
2012
2015
2018
Construction capex
2021
2024
2027
Maintenance capex
2030
2033
EBITDA
2036
2039
Free cash-flow
21
March 2014
LatAm Oil & Gas
Equity Research
Debate #3: Libra was better than you thought
Libra basics
 The first pre-salt auction. In 2010, a new law established that future pre-salt areas would have
to be auctioned under a PSC contract, with PBR mandatory operatorship and a minimum 30%
stake, and the oversight of a government company that has a 50% weight and veto power in the
operating committee. Much industry and equity market skepticism surrounded the new model,
especially in 2013, when the bid rules dictated a R$15bn fixed bonus payment, and a minimum
bid of 41.65% government share of profit oil that could scare Big Oil away. Final results were
announced on Oct 21st. In our view, a high quality consortium (Shell and Total with a combined
40% stake) and a bid at the minimum 41.65%, plus a technical body at the PPSA helm are
reasons for optimism that Libra can yield good returns, contrary to wider investor perception.
Map of the Libra prospect and other pre-salt acreage
Uruguá
Tambuatá
Carapia
Florim
Franco
Iara
Entorno
SP RJ
Abaré
Oeste
Source: Credit Suisse Research, Woodmackenzie, ANP.
Tupi
NE
Cernambi
Lula
Carioca
Iguaçu
Abaré
Sapinhoá
 $100bn field-life spend
 12 FPSOs first assessment, starting in 2020
 Oil com panies: Petrobras (Operator, 40%), Shell (20%),
Total (20%), and the Chinese: CNPC (10%), CNOOC (10%)
 Minim um exploratory com m itm ents: 1,547km2 of 3D
seismic that covers the full area of the block, two exploration
wells and 1 extended well test
 15% royalty
Gato do
Mato
Bem-Te-Vi
 Developm ent strategy:
 Fiscal term s for the pre-salt PSC:
Dolomita Sul
Carcará
 Resource siz e: 8-12bn bbls
 Bonus paym ent: R$15bn due December 2013
Oliva
Macunaíma
Libra basic facts
Lula
Sul
Jupiter
Libra
 41.65% base government share of profit oil, variable
according to well productivity and oil prices
 50% cost-recovery ceiling
 Other taxes: up to 9% sales tax, 34% Brazilian
income tax, 1% of profit R&D spend
 Local content rules: 37% in the exploration phase, 55-59%
in development phase depending on year of production
 PPSA: PPSA (Pre-Sal Petroleo S.A.) is a government created
company which will act as the manager of the contract and
have a 50% weight and veto power in the operating committee.
Executive directors appointed with a technical, not political,
profile/background.
Sul de Guará
22
March 2014
LatAm Oil & Gas
Equity Research
Debate #3: Libra was better than you thought
IRRs, government take, and oil break-even
 Decent returns, if execution is sound. We make the case that the
consortium bid at the low 41.65% ensured an adequate ‘margin of safety’ to
guarantee decent returns. With the fiscal terms now known, Petrobras and
partners will have to deliver on execution. Libra is a $100bn development with
high 60% local content requirements that will start-up at a time the local
supply chain might still be busy with Petrobras’ current demands. Our
calculations lead us to healthy high-teens project IRRs under the following
assumptions:
– Capex : $12/bbl
– Opex : $7/bbl opex
– Well productivity: 20kbd, each FPSO drains 600mmbbls of oil
– Developm ent schedule: 12-14 FPSOs in total, gradually from 2020-24
IRR sensitivity in different oil price scenarios
Royalties
Special participation
Libra
70%
74%
6%
40%
34%
12%
Income tax
85%
6%
Profit oil
Signature bonus
91%
6%
96%
6%
51%
59%
68%
13%
7%
18%
21%
21%
4%
21%
1%
21%
Concession
PSC 40% (Min)
PSC 60%
PSC 70%
PSC 80%
Break-even oil prices for 10% and 15% IRRs regimes
35%
10% IRR
30%
15% IRR
140
Concession
109
25%
IRRs
Total government take on various fiscal regimes
Libra
Libra
PSC 40% (min)
20%
PSC 60%
PSC 70%
PSC 80%
15%
90
80
75
60
63
70
53
43
10%
5%
0%
40
50
60
70
80
90
Oil price levels ($/bbl)
Source: Credit Suisse Research.
100
110
120
Concession
PSC 40% (Min)
PSC 60%
PSC 70%
PSC 80%
23
March 2014
LatAm Oil & Gas
Equity Research
Debate #3: Libra was better than you thought
Four tables with further economics
Libra Government share of profit oil for well productivity and oil prices
Oil price ($/bbl)
Production per well (kbd)
Min
8
10
12
14
16
18
20
22
Min
Max
10
12
14
16
18
20
22
24
0
60
35.3% 37.4% 39.1% 40.2% 40.8% 41.4% 41.9% 42.3% 42.8%
60
80
37.0% 38.7% 40.2% 41.1% 41.7% 42.1% 42.6% 43.0% 43.3%
80
100 39.1% 40.5% 41.7% 42.4% 42.8% 43.2% 43.5% 43.8% 44.1%
100
120 40.5% 41.7% 42.6% 43.2% 43.5% 43.8% 44.1% 44.4% 44.6%
120
140 41.5% 42.4% 43.2% 43.7% 44.0% 44.3% 44.5% 44.7% 44.9%
140
160 42.2% 43.0% 43.7% 44.1% 44.4% 44.6% 44.8% 45.0% 45.2%
160
43.3% 44.0% 44.5% 44.8% 45.0% 45.1% 45.3% 45.4% 45.6%
60
6
8
10
12
14
16
18
20
bn barrels
2.5
3.7
4.9
6.1
7.3
8.5
9.7
10.9
12.1
PSC 40 (Min) 14.0% 15.8% 17.1% 17.9% 18.6% 19.1% 19.5% 19.8% 20.1%
PSC 50
12.8% 14.6% 15.8% 16.6% 17.3% 17.7% 18.1% 18.5% 18.8%
PSC 60
11.2% 13.0% 14.1% 14.9% 15.5% 16.0% 16.3% 16.6% 16.9%
PSC 70
9.5%
11.1% 12.2% 12.9% 13.5% 13.9% 14.3% 14.6% 14.9%
PSC 80
7.4%
9.0%
10.0% 10.7% 11.2% 11.6% 11.9% 12.2% 12.5%
# FPSOs
4
6
8
10
12
14
16
18
20
bn barrels
2.5
3.7
4.9
6.1
7.3
8.5
9.7
10.9
12.1
PSC 40 (Min)
0.37
0.69
1.01
1.30
1.60
1.87
2.14
2.40
2.66
PSC 50
0.25
0.52
0.79
1.04
1.29
1.52
1.75
1.97
2.19
70
80
90
100
110
120
PSC 40 (Min) (1.26) (0.73) (0.19) 0.34
0.78
1.19
1.50
1.87
2.17
2.52
PSC 50
(1.35) (0.85) (0.34) 0.16
0.56
0.92
1.20
1.52
1.78
2.08
PSC 60
(1.46) (0.99) (0.53) (0.06) 0.29
0.61
0.83
1.10
1.30
1.56
PSC 60
0.11
0.32
0.53
0.72
0.92
1.10
1.28
1.46
1.63
PSC 70
(1.57) (1.14) (0.71) (0.28) 0.03
0.30
0.46
0.68
0.83
1.03
PSC 70
(0.04)
0.12
0.27
0.41
0.55
0.68
0.82
0.94
1.07
PSC 80
(1.68) (1.29) (0.89) (0.50) (0.24) (0.02) 0.10
0.26
0.36
0.50
PSC 80
(0.18)
(0.09)
0.01
0.09
0.18
0.26
0.35
0.43
0.51
Source: Credit Suisse Research, ANP.
50
4
PBR’s Libra NPV-10 under various fiscal regimes and sizes, at $100/bbl
(US$/ADR)
Oil prices ($/bbl)
40
# FPSOs
24
PBR’s Libra NPV-10 under various fiscal regimes and oil prices
($/ADR)
30
IRRs at $100/bbl for different Libra sizes and fiscal terms
24
March 2014
LatAm Oil & Gas
Equity Research
Debate #3: Libra was better than you thought
PSC vs concession
 A quick recap. The schemes below provide a brief overview of how the oil money flows between oil company and government, for the current concession regime and
the pre-salt PSCs. In the current concession regime, the oil company simply pays three types of 'taxes' to the government: a 10% royalty on sales, a tax on operating
profit called Special Participation Tax, which varies from 0-40% dependent on type of field (onshore, shallow water, deepwater – high productivity fields pay more tax than
less productive fields), year of production, and amount of oil produced, and a 34% tax on income. In the PSC regime, the oil company stills pays royalty (a higher, 15% of
revenues) to the government. Then it recovers the amount invested to bring the field onstream (capex+opex) through cost oil or cost recovery. What is left after cost oil is
called excess oil or profit oil, which is then split between the oil company and the Government.
Current concession regime
Libra and future pre-salt PSCs
Revenues
Government
cashflows
Oil company
cashflow
Revenues
Sales tax (up to 9%)
& Royalties (10%)
Government
cashflows
Sales tax (up to 9%)
& Royalties (15%)
Net revenues
Net revenues
Cost recovery
(50% ceiling)
Opex & depreciation
Operating profit
Excess oil, or profit oil
Special participation
tax (0-40% of profit
variable on productivity,
year of production,
water depth)
Contractor share
of excess oil
Government share
(min 41.65% at $100/
bbl and 10-12kbd/well)
Profit before tax
Depreciation
Income tax (34%)
Oil company
cashflow
Source: Credit Suisse Research.
Income tax (34%)
Oil company
post-tax cashflow
25
March 2014
LatAm Oil & Gas
Equity Research
Debate #4: ToR renegotiation. Will PBR have to pay?
Transfer-of-Rights basics
 Back to Septem ber 2010. Petrobras conducted a c.$70bn capitalisation, of
which $42bn was used as an ‘oil for shares’ mechanism by which Petrobras
acquired the right to produce up to 5bn barrels from certain pre-salt blocks
(“Transfer of Rights”).
Transfer of rights maps and key metrics
 Key features of Transfer of Rights:
– Price: $8.5/bbl
– Fiscal terms: 10% royalties, 0.5% R&D spend
– Local content: Exploration 37%, Development 65%
– Terms: 40 years, 4 of which exploration period
– Renegotiation: After the declaration of commerciality, PBR and the
Franco
 $9/bbl
 3bn bbls
Government will renegotiate the economics. This has been a key focus point
for the equities market, which we discuss in the next slide.
Parati
Valuation detail by block
Area
Price
($/bbl)
Volume (mmbbls)
Value
(US$bn)
Florim
9.0
467
4.2
Franco
9.0
3,058
27.6
South of Guará
7.9
319
Carcará
Bem-te-vi
5.8
600
3.5
South of Tupi
7.9
128
1.0
Northeast of Tupi
8.5
428
3.7
-
-
-
$8.5/bbl
5,000 mmbbls
$42.5bn
Iara
NE of Tupi
 $8.5/bbl
 428mn bbls
Sapinhoá
Abaré
Abaré Oeste
Caramba
Lula
Surround Iara
 $5.8/bbl
 600mn bbls
Júpiter
Carioca
Biguá
2.5
Surround Iara
Libra
Florim
 $9/bbl
 467mn bbls
South of Guará
 $7.9/bbl
 319mn bbls
South of Tupi
 $7.9/bbl
 128mn bbls
Peroba
 Contingent block
Transfer of Rights
Peroba (Contingent)
Total
Source: Petrobras, ANP, Credit Suisse Research.
Libra
Pre-salt concession
26
March 2014
LatAm Oil & Gas
Equity Research
Debate #4: ToR renegotiation. Will PBR have to pay?
The renegotiation
 Why now? With the exploratory period of the ToR areas ending in September
Renegotiation mathematics: little to be paid ($bn)
2014, the market has started to focus on the renegotiation, concerned that PBR
would have to pay more to the government as oil prices are higher now, which
would stress even more the company’s balance sheet.
+$20/ bbl in oil prices offset by a 20% inflation and a 2 year delay.
‘Only’ further $4bn to be paid (on a bear case inflation can be higher
than 20% and future oil prices lower due to US shale)
 Tim eline. Petrobras has to declare any commerciality by September 2014 (end
of the exploratory period). 10 months prior to the DoC of each area, PBR has to
notify the Brazilian Government and the ANP of its intentions to DoC, so that the
renegotiation process can start. The review process will only be concluded when
PBR have declared commercial all the areas it intends to. The review will include
a renegotiation of the volumes (up to the 5bn bbls limit), price, and level of local
content. Once the review is completed, the parties have up to 3 years to pay.
7.7
18.3
6.6
46.5
42.5
42.5
 Mechanism . If the revised valuation is higher than in 2010, Petrobras can opt to
either (i) pay the difference in cash or equivalents or (ii) relinquish some areas. If
the revised price is lower, the Government will have to pay Petrobras in cash.
 What we think. We don’t think valuation will be too different: higher oil prices
now are offset by delays and cost inflation. Furthermore, even if PBR had to pay
up, the company would have up to three years after the renegotiation was
completed to pay (ie, probably at a time when the balance sheet was healthier).
Price paid
(2010)
+$20/bbl in
oil price
20% cost
inflation
2 year delay Renegotiated
price (2013)
Price paid
(2010)
Renegotiation timeline
Signature of the
 PBR to notify Gov
and ANP of
intention to DoC:
renegotiation begins
No set period for how long
review should take
 DoC deadline
 Review ends and new
valuation, volumes and
local content are set
ToR contract
Sep-10
…
…
Nov-13
4 years exploratory period
Source: Petrobras, Credit Suisse Research.
Sep-14
…
 2 Franco FPSOs
…
Review
ends
…
2016
 1 FPSO in Iara
1 FPSo in NE of Tupi
 2 Franco
FPSOs
2017
 1 Franco
FPSOs
2018
2019
 End of
40-year
contract
 1 FPSO
in Florim
2020
…
…
Sep-50
3 years for parties to pay revised values
27
March 2014
LatAm Oil & Gas
Equity Research
Debate #4: ToR renegotiation. Will PBR have to pay?
Follow-on recap and shareholder structure
 The chart on the right shows the structure of the 2010 follow-on. Of the
c.$70bn equity raise, c.$42bn was used to purchase the 5bn bbls from the
Government, in a transaction that was close to cash-neutral for the Government.
Of the $70bn, ‘only’ $28bn was injected in the company to recompose cash
balances. Of the $28bn, minorities participated with $23bn.
Cash Raised in the Capitalization (R$ bn)
Oil for shares: c. R$ 80bn raised from public entities, c. R$ 75bn im m ediately
given back to buy oil from the governm ent in the ToR agreem ent.
 Before and after. With the ToR, the Government increased its stake from 40%
37
to 49% of the total shares of Petrobras. Government participation in the voting
shares increased from 58% to 70%, and from 16% to 34% in the non-voting
shares.
29
45
40
Others
BNDES*
Shareholding Structure (mn shares)
Before capitalization
75
14
 Governance discussion. Because the purchase of barrels and the follow-on
were characterised as two different transactions, minorities could not vote on the
barrels acquisition. In practice, minorities were effectively diluted to fund a deal
that they did not had the opportunity to vote for (or against).
120
Sovereign
Federal
Fund
Government
Total
Transfer or
Rights
Net cash
Raised
After capitalization
13,044
51%
8,774
60%
5,073
42%
2%
56%
Common
7,442
3,701
84%
16%
Preferred
Federal Governemt
40%
10%
8%
32%
Total
BNDES*
5,602
50%
66%
7%
27%
Common
Preferred
Other
Source: Petrobras, Credit Suisse. Note: Shareholding structure shown in number of local shares. Each ADR is equivalent to two shares.
3%
17%
29%
Total
Free-float
28
March 2014
LatAm Oil & Gas
Equity Research
Debate #5: Different dividends, different ON-PN spread
There’s always a first time
 Petrobras has always paid sim ilar dividends to ordinary (ON) and
preferred (PN) shareholders. Firstly, balance sheet has never been an
impediment, so the company always distributed more than the minimum 25%
payout required by law. Secondly, the earnings levels were high enough so that
the 25%+ payout has always been close to 2x the book value rules that put a
floor on the PN dividend. This apparent stability meant that through most of its
history, the ON shares have traded at an average 13% premium vs the PNs.
Better liquidity plus voting power justified that premium.
 But 2012 (and 2013) were the first tim e when dividends were different. By
end 2012, earnings level were low enough, one of the lowest of PBR’s history.
PN’s book value dividend rules were higher than the ON’s minimum 25% payout,
so that PBR implemented different payments (PNs got R$0.96/sh, ONs
R$0.47/sh in 2012, in 2013 the values were 97 and 52 cents respectivelly). This
caused a major shift in the PN-ON spread. With different dividends, PNs shares
started to trade at a premium to the ONs, which persists to this day.
Dividends vs Interest on Equity
PBR dividend distribution rules
In Brazil, companies have the choice
of distributing cash to shareholders in
the form of dividends, or alternatively
as ‘interest on equity’ (IOE). Key
differences are: (1) dividends do not
pass onto companies’ P&L, and
shareholders do not pay tax on
received dividends; and (2) IOE
enters the P&L as a financing cost,
thus decreasing the tax bill; but
shareholders have to pay a 15-25%
tax rate on IOE received. Historically,
Petrobras has paid 88% of
distributions as IOE.
Preferred shares (PNs): the higher of:
 3% of PN book value;
 5% of PN paid-in capital;
 25% of net income;
 The ON dividend.
Ordinary shares (ONs): by law, PBR is
required only to distribute a minimum of
25% of net income to shareholders, but
does not specify which type of
shareholder. Therefore, in theory, the
ON dividend could be zero if the PN
dividend already consumed the full 25%
of net profit. However, PBR has an
explicit commitment to pay the ONs at
least 25% of net profit.
A dividend story: low earnings forcing different dividends
4.5
Low level of earnings
forced different dividend
payments for the first
time in Petrobras’ history
in 2012…
Earnings per share
4.0
3.5
R$/sh
3.0
2.5
4
2
(4)
1.5
PN dividend
1.0
ON dividend
0.5
2006
2007
2008
2009
Source: Bloomberg, Company data, Credit Suisse Research.
2010
2011
2012
2013
0%
PN discount to ONs
(R$/sh)
(10%)
(6)
(10)
Nov 08
(20%)
PN discount to ONs
(%)
(8)
0.0
10%
0
(2)
2.0
20%
… resulting in PNs having a
premium vs the ONs for the
first time too.
(30%)
Jul 09
Mar 10 Nov 10
Jul 11
Mar 12 Nov 12
Jul 13
29
March 2014
LatAm Oil & Gas
Equity Research
Debate #5: Different dividends, different ON-PN spread
What should the spread be?
 A first approach: “2 x 50cents = R$1.0 spread”. With 2012 and 2013 dividends differing in around 50 cents between the two classes of shares, we think a simple way
to think about the spread is as follows: if Petrobras takes two years to return to adequate performance levels to reestablish equal payments, a fair spread should therefore
be R$1.0/sh. Indeed, this was our approach through much of the recent past, recommending going long or short the spread whenever it went too far off R$1.0.
 Justifying a R$1.4 spread. "R$1.40 = 2 x R$0.70/ sh = 3x R$0.50". Earnings and book value in 2013 did not differ much from 2012’s, resulting in a close to R$0.50/sh
differential between the ON and PN dividends. However, with a deteriorated 2014 outlook, earnings will decrease, implying in a lower 2014 dividend for the ONs and a
differential of R$0.70/sh in our view. Therefore a simple way to see a R$1.40/sh fair spread would be to assume the R$0.70/sh would persist for two years, or alternatively
to assume that the current R$0.50/sh dividend difference will persist for three years, and not two, given a 'lost‘ 2014.
 R$2.0 = could the balance sheet force PBR to cut the ON dividend to z ero? Technically, Petrobras can cut the ON dividend to zero. The company is only obliged to
(1) distribute a minimum 25% of earnings as dividends, regardless if it is to ON, PN or both types of shareholders, and (2) pay the PNs the minimum 3% of book value or
5% of share capital, equivalent to the current R$0.96/sh dividend. Technically, R$0.96/sh distributed to the preferred shareholders is already equivalent to a 25% current
payout required by corporate law, and would even be higher than 25% on lower 2014 earnings. This would allow PBR to distribute zero to common shareholders. The
company, however, has made an explicit commitment of also paying a minimum 25% payout to the ONs. With a tight balance sheet in 2014, that commitment could be
relaxed to save PBR R$3.4bn in cash. If the ON dividend is zeroed, the dividend gap would be c. R$1.0 per year. With two years of zeroed ON dividend, the ON-PN
spread could go to close to R$2.0.
The lack of a clear formula and a
tough 2014 could warrant a new
R$1.0-1.4-2.0/sh spread range in
our view
Short-term history of the PN-ON spread
(R$/sh)
Different dividends and new
earnings level warranted a
change in the spread, with a
fair value of R$1.0 initially
2.00
1.50
1.00
0.50
Very low current spread levels
Mar 14
Feb 14
Jan 14
Dec 13
Nov 13
Oct 13
Sep 13
Aug 13
Jul 13
Jun 13
May 13
Apr 13
Mar 13
Feb 13
(0.50)
Jan 13
0.00
(1.00)
Source: Bloomberg, Credit Suisse Research.
30
March 2014
LatAm Oil & Gas
Equity Research
Debate #6: The balance sheet
Balance sheet overview
 The tightest levels ever. No matter how we look at it, Petrobras’ balance sheet
is at the worst situation in history, and notably worse than in 2009, prior to the
capitalisation. Debt levels are at peak, cash levels close to lowest, gearing and
leverage ratios also.
 No covenants. While Petrobras doesn’t have any formal covenants in its debt
structure, high debt levels coupled with still negative free-cash flow for the next
couple of years (1) put PBR in an increasingly fragile position to keep investing,
(2) also leave the company overly dependent on external debt markets for
financing, at a time concerns for Brazil’s investment grade are resurfacing, and
(3) destroy value for the shareholders.
Total debt levels, net debt levels, and cash levels
($bn)
140,000
Peak debt levels. Cash levels
dangerously low, at same levels
as in 2009, prior to the
capitalisation
120,000
100,000
Total debt
levels
80,000
60,000
Net debt levels
40,000
Cash levels
20,000
0
2006
Net debt / EBITDA (x) and Net debt / (net debt + equity) (%)
45%
3.5
40%
ND/EBITDA (x)
35%
Net debt /
(ND + Equity)
3.0
2.5
30%
25%
2.0
Net
debt/EBITDA
1.5
20%
15%
1.0
10%
0.5
5%
0.0
0%
2006
2007
2008
2009
Source: Company data, Credit Suisse analysis.
2010
2011
2012
2013
2008
2009
2010
2011
2012
2013
Petrobras Enterprise Value split (Book value + Net debt)
(USDm)
300,000
250,000
ND/(ND+Equity) (%)
4.0
2007
200,000
Growing ‘book value’ of the
enterprise until 2010, via
equity. Post 2010, destruction
of value to the shareholders
Net debt
150,000
100,000
Book value
50,000
0
2006
2007
2008
2009
2010
2011
2012
2013
31
March 2014
LatAm Oil & Gas
Equity Research
Debate #6: The balance sheet
Capitalising vs expensing debt costs
 The fact. Accounting wise, Petrobras is allowed to capitalise borrowing costs directly attributable to acquire or construct particular assets. These borrowing costs
bypass the P&L, go into PP&E. Whenever the asset is on productive stage, those costs go back to the P&L, amortised over the useful life of the asset. Because a large
part of Petrobras debt is used to finance capex and specific projects, PBR does capitalise a large portion of its borrowing costs. Since 2007, on average 74% of
borrowing costs have been capitalised.
 Investors’ argum ent. Because of this issue and of Petrobras’ high capital needs, some investors argue that Petrobras’ earnings are overstated compared to peers,
and therefore should be adjusted. This is usually an argument of bear investors making the case that Petrobras PEs, while optically cheap, are not so. If we were to
expense all borrowing costs, Petrobras earnings would have been 8-40% lower than reported since 2007. Because the company has been gearing up substantially,
the earnings downgrade are greater for recent years.
 The question: should we adjust? While we understand the willingness to adjust earnings downwards due to debt costs, we make the point that such an adjustment
would mean expensing a cost that does not generate revenue yet. Conceptually, one could argue that this would be equivalent to expensing capex in the P&L, which to
us sounds too extreme. We therefore would look at PBR’s PEs at face value, and would get around the high-capital intensity issue directly via longer-term DCFs.
Petrobras borrowing costs and capitalised/expensed split
Borrowing costs (USDm)
5,000
% of debt
capitalised
100%
Reported net income
90%
Net income if all debt was expensed in the P&L
80%
Expensed debt
4,000
70%
60%
3,000
50%
40%
2,000
30%
Capitalised
debt
1,000
20%
10%
0
% of debt costs that are capitalised
6,000
Petrobras earnings and impact of expensing all debt costs
(USDm)
19,994
18,432
16,982
16,850
14,491
12,866
11,048
9,345
19,948
15,540
10,807
-16%
-8%
10,912
-22%
7,016
-11%
-15%
6,977
-35%
-40%
2012
2013
0%
2007
2008
2009
Source: Company data, Credit Suisse analysis.
2010
2011
2012
2013
2007
2008
2009
2010
2011
32
March 2014
LatAm Oil & Gas
Equity Research
How to value Petrobras?
FOTO
Valuation dilem m a
For every year since 2010, anyone who would have tried to make a value call on
PBR would have been wrong. The share price has fallen on average 25% per year
since then, and the downward trend continues. We discuss the PBR value trap
dilemma, the problems of a DCF for Petrobras, and argue that up until 2013, it
would have been ‘easier’ to avoid the value trap, whereas now that dilemma is
more difficult with the ‘only’ variable left being domestic price increases.
The problems of a DCF for Petrobras
Deriving an absolute valuation reference for Petrobras is not straightforward, in our
view, due to three inter-related issues: (1) negative cashflows for a long time, leaving
much of the value of the company far out in the future, (2) uncertainty on future
performance, (3) uncertainty whether high capital intensity with price controls could
imply in further dilution to current shareholders.
HOLT®: Share price implying current performance into eternity
Using HOLT lead us to two interesting conclusions: (1) the current PBR share price is
implying current (trough?) business performance into perpetuity, and (2) Global Oils as
a whole are pricing in low levels of return – if PBR’s performance doesn’t improve, PBR
would be the third most expensive stock within Global Oils.
Should Petrobras trade like Gazprom?
We argue it shouldn’t. PBR returns have historically been significantly above GAZP’s
(current returns are not, though), and Brazil discount rates are lower than Russia’s.
These two points argue for PBR to trade at a higher multiple than GAZP.
Absolute value reference and other value guideposts: is now the time?
Hypothetical equity issuance: at what price would you buy?
‘Petrobras in 2020’ is the best way we found to come up with an absolute value
reference for PBR, which would get us close to book value of $25/ADR, significantly
higher than current prices. Trying to look at other metrics, we (1) derive a conservative
level of earnings, (2) look what Big Oil PE on trough earnings, (3) want PBR to be
offering a high dividend+buyback yield compared to global peers, and (4) incorporate
balance sheet deterioration on valuation. These approaches get us to a c.$12/ADR.
While PBR is vocal about not having to issue equity, we think it’s useful for investors to
run a scenario of where the share price would go to should there be future dilution, in a
way to test the downside. In a scenario where the FX goes up to 2.8x and with little
price increases, PBR would need to raise $10-25bn in equity. In our view, the price of
this hypothetical issuance would have to be at the $7.5/ADR level in our view, so that
investors would get a cheap PE of c.6.0x on earnings that are reasonably conservative.
March 2014
LatAm Oil & Gas
Equity Research
How to value Petrobras?
Valuation dilemma
 The value trap. For every year since 2010, anyone who would have tried to
make a value call on PBR would have been wrong. The share price has fallen on
average 25% per year since then, and the downward trend continues.
PBR historical PE multiples (x)
16x
 Before it was ‘easy’ to avoid the trap. We argue that up until 2013, it would
14x
have been easier not to fall in that trap, as a sluggish production profile and the
always present issue of the Downstream pricing policy effectively decreased the
likelihood of a better underlying business performance.
12x
 Now it’s a harder decision. Starting from 2013, however, that job has become
more difficult, in our opinion. With a production profile that is now on the cusp of
turning around with record-high 840kbd capacity additions last year and early this
year, the main 'piece of the puzzle' left for earnings to revert the downward trend
is the Downstream pricing policy. Unfortunately, the balance sheet is in an
extremely fragile position, 2014 is an election year in Brazil, inflation is at the
forefront of politicians' minds, and the FX, as important to Petrobras as gasoline
and diesel price increases, is on an unhelpful trend, with the USD appreciating vs
the BRL to the highest levels since 2009.
10x
8x
6x
Close to 6x PE, almost as
low as end 2008 when the
oil price hit $30/bbl
4x
2x
0x
Jan-07
Jan-08
Jan-09
Jan-10
Jan-11
PBR historical price-to-book multiples (x)
PBR historical EV/EBITDA multiples (x)
5.0x
9x
Jan-12
Jan-13
Jan-14
8x
4.0x
7x
6x
3.0x
Below book since late 2011.
Now PBR below 0.5x book,
lowest levels ever
2.0x
5x
4x
High and increasing net debt levels keep
the EV/EBITDA multiple stable at 5-6x
despite a market cap that is down more
than 50% since 2010. Given PBR’s vast
capex plan, there is significant debt that
does not generate EBITDA yet
3x
2x
1.0x
1x
0.0x
Jan-07
Jan-08
Source: Bloomberg.
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
0x
Jan-07
Jan-08
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
34
March 2014
LatAm Oil & Gas
Equity Research
How to value Petrobras?
The problems of a DCF for Petrobras
 Absolute valuation: a way out of the value trap. One way to avoid the PBR value
ROEs and ROCEs (%): falling since 2008. What will future levels
be?
trap dilemma would be to come up with a conservative, absolute value reference for
the company. In that way, time would ensure that the shares would converge to that
absolute value reference, and investors, with a decent margin of safety, would be
‘safer’ from the trap.
35%
30%
 Three issues. Unfortunately, coming up with such a value reference is no easy job
for Petrobras, for three inter-related reasons, in our view:
25%
1. Negative cashflows for long. The first, more evident issue to built a DCF for
20%
Petrobras are negative cashflows. Petrobras has been cashflow negative
since 2007, and that is likely to continue into 2016-2017. A great part of value
is therefore far away in the future.
2. Uncertainty of future performance. Not only is current capex intensity high, but
10%
the returns on those heavy-investments are also uncertain. PBR has seen
declining returns since 2008, and since 2010 we have been below cost-ofcapital territory. Will returns ever pick-up again?
0%
uncertain returns and high capital intensity, do current shareholders face the
risk of future dilution, such as happened in 2010?
Cash from operations
21,087
25,814
(21,265)
2007
22,636
(28,325)
2008
Capex
28,173
(34,480)
2009
Source: Petrobras, Credit Suisse estimates.
Free-cashflow
29,457
(41,573)
2010
29,000
(41,584)
2011
27,901
(40,440)
2012
ROCE
5%
3. Will there be future dilution? A third issue derives of the first two: with
Petrobras cashflows (USDm): very negative for very long
ROE
15%
2006
2008
2010
2012
2014E
2016E
2018E
2020E
Negative cash-flows for a long time. Capex intensity is high, and investments are
so far not translating into higher cash generation. Will future cashflows be positive
enough for a DCF? Will there be future dilution?
70,667
61,850
52,035
43,364
37,772
25,775
22,636
(45,388)
2013
(41,420)
2014E
(41,420)
2015E
(41,420)
2016E
(41,420)
2017E
(41,420)
2018E
(41,420)
2019E
(41,420)
2020E
35
March 2014
LatAm Oil & Gas
Equity Research
How to value Petrobras?
Arriving at an absolute value reference: ‘Petrobras in 2020’
 Looking at 2020. One of the best ways we found to look for absolute value in
Petrobras is using our ‘Petrobras in 2020’ approach. The approach consists of
looking at asset valuation in a ‘normalised’ state in 2020, assuming Petrobras
Upstream will continue to perform strongly, while the Downstream will either be worth
zero (not creating, but not destroying any value) or else restore profitability to Global
Industry average (which is still poor). We then translate that asset valuation into equity
value today, by accounting for changes in net debt from today to 2020, and also by
time-value-of-money differences.
 $25/ ADR. That exercise gets us to an intrinsic value of $25/ADR, incredibly close to
book value. Another way to intellectualize the $25/ADR would be to look at Petrobras
business plan capex: with c. 60% of the capex in Upstream (where returns are
c.20%), and the remaining in Downstream and other sectors (where we’d assume
returns would be zero in the long-run). This would yield a blend-return close to cost of
capital, and therefore Petrobras would have to trade close to book value.
Step 1: Arriving at an asset valuation in 2020
E&P division
Units
Values
2020 Oil & Gas production
kboed
5,200
2020 Oil & Gas production
mmbbls
1,898
Net income per boe
$/boe
24
PBR 2020 R&P net income and FCF
USDm
45,552
Upstream asset value (i)
USDm
455,520
Downstream, scenario 1
Refining asset value (ii)
Unit
Values
PBR asset value in 2020, scenario 1
USDm
455,520
PBR asset value in 2020, scenario 2
USDm
479,217
PBR net debt in 2020
USDm
(80,645)
PBR equity value in 2020 scenario 1
USDm
374,875
PBR equity value in 2020 scenario 2
USDm
398,572
PBR equity value in 2014 scenario 1
USDm
162,069 Brought to 2014 at a 15% Ke
PBR equity value in 2014 scenario 2
USDm
172,314 Brought to 2014 at a 15% Ke
PBR equity value in 2014 scenario 1
USD/ADR
25
PBR equity value in 2014 scenario 2
USD/ADR
26
Source: Credit Suisse Research.
Comments
USDm
Comments
2020 refining capacity
kbd
2,497
2020 refining capacity
mmbbls
911
$/bbl
2.6
PBR 2020 Refining net income and FCF
USDm
2,370
Refining asset value (iii)
USDm
23,697
Global Oils average refining NI/bbl
10% real rate, ex-growth
Assumes Downstream does not
destroy value on the long term
0
(net income offset by
loss-making imports)
Downstream, scenario 2
Step 2: Translating asset value in 2020 to equity value in 2014
Industry average $15/bbl,
PBR E&P more profitable
Comments
 Does it m ake a difference? Petrobras has been trading below our $25/ADR
reference since late 2011. Therefore, being pragmatic, such a value reference would
have not helped investors avoid a significant fall in the share price. We have to try to
look elsewhere for value guideposts to try to judge at what price we should buy into.
Comments
PBR asset value
Doesn't assume new
Premiums or Comperj2
PBR is able to restablish
refining profitability
10% real rate, ex-growth
Comments
Scenario 1
USDm
455,520
Sum of (i)+(ii)
Scenario 2
USDm
479,217
Sum of (i)+(iii)
36
March 2014
LatAm Oil & Gas
Equity Research
How to value Petrobras?
Other value guideposts: Is now the time?
 Beyond absolute value. We try to look at other value guideposts outside our ‘Petrobras in 2020’
absolute value reference. To try to buy into Petrobras on a weak year for operational performance,
we would: (1) derive a reasonably conservative level of earnings, (2) look what Big Oil PE on trough
earnings was, (3) want PBR to be offering a high tangible support of value, with a high
dividend+buyback yield compared to global peers, and (4) try to incorporate some degree of
balance sheet deterioration. These four approaches would get us to a c.$12/ADR (R$14/share) for
the preferred shares, similar to current levels.
Deriving a conservative earnings estimates for PBR: $7bn (US$bn)
0.5
2.0
4.5
 $7bn: a conservative earnings estim ate? At $1.5bn, Q3’13 earnings were the second worst
levels in PBR history since 2006 (losing only to Q2’12 when PBR posted a loss due to $3.8bn of
non-cash FX losses). From Q3’13, we derive a $7bn annual earnings level including production
growth, the 4-8% price increases late 2013, and further FX depreciation to 2.6. This looks to us as
a reasonably conservative earnings level to start from.
3.0
 $77bn ($12/ ADR): a conservative m arket cap? As a group, Big Oil had a PE on trough
earnings of 11x. If applied to PBR, we’d get to a $77bn market cap, already above current levels.
7.0
6.0
 7.2% dividend yield: the highest am ong global peers. At the current share price, Petrobras
preferred shares are offering the highest yield within global oils.
1.5
 Writing-off $25bn of the m arket cap. Before the pricing formula announcement last November,
Source: Bloomberg, Credit Suisse Research.
+4%
gasoline
+8% diesel
-15% FX
2014
earnings
CNOOC
Total
Statoil
Sinopec
RDShell
BP
11.0
CVX
16
14
12
10
8
6
4
2
0
Petrochina
Petrochina
BP
CNOOC
Statoil
Sinopec
XOM
Repsol
Total
RDShell
CVX
ENI
5.3%
+7%
production
Big Oil PE on trough earnings is c. 11x, implying a PBR market
cap of $77bn, already above current levels
Repsol
7.2%
PBRa
8.0%
7.0%
6.0%
5.0%
4.0%
3.0%
2.0%
1.0%
0.0%
Q3
annualised
XOM
PBRa / PETR4 now offer the highest dividend+buyback yield in
Global Oils
Q3 13
earnings
ENI
PBR’s market cap was c. $100bn. One simplistic way to incorporate a tougher outlook (assuming a
flat EV and that any further debt issuance would come at the expense of the equity) would be to
write-off $25bn of the market cap, getting us to the current $75bn.
37
March 2014
LatAm Oil & Gas
Equity Research
How to value Petrobras?
HOLT®: Share price implying current performance into eternity
20%
10%
5%
(10%)
 The charts on the right compare PBR with other global oil peers. As the top-right chart
(15%)
CFROI
Source: Credit Suisse HOLT®.
Forecast CFROI
Market implied CFROI
NVTK
ROSN
ECOPETROL
XOM
GALP
BG
REP
PBR
PRE
PETROCHINA
BP
TOTF
STL
CVX
COP
SHELL
ENI
OMVV
GAZP
YPF
RNHS
GALP
BG
PBR
REP
ROSN
YPF
XOM
TOTF
BP
STL
COP
ENI
PETROCHINA
1995 1997 1999 2001 2003 2005 2007 2009 2011 2013E 2015 2017
NVTK
0
SHELL
2
CVX
4
GAZP
6
If performance does not improve,
PBR is the third most expensive oil
stock globally
SINOPEC
8
0.3%
ECOPETROL
10
10%
5%
0%
(5%)
(10%)
(15%)
(20%)
(25%)
OMVV
CFROI (%)
12
Spread: implied CFROI® minus CFROI expected by the sell-side
PRE
PBR share price implying
that current business
performance will be
perpetuated into eternity
SINOPEC
(5%)
shows, all global oil stocks are pricing in low returns into eternity, and PBR, despite pricing-in
the current low performance, is actually one of the highest implied returns in the global oil
universe. The bottom-right chart shows that in another way, comparing the spread (implied
CFROI in the share price minus CFROI expected to consensus). Another way to illustrate that,
if current business performance does not improve, PBR is actually fairly priced and one of the
most expensive oil stocks globally.
14
3.2%
0%
bars), compares that with the expected future performance from consensus (red bars), and with
what expectations are embedded in the current share price (brown circle). What the chart tells
us is that the current share price is implying that PBR’s current weak performance levels is
being priced to eternity. This can be interpreted as extreme, and as a buying signal.
PBR historical, forecast, and implied CFROI® (%)
PBR implied
returns one of the
highest amidst
Global Oils
15%
RNHS
 The chart on the bottom left shows what PBR historical CFROI performance has been (blue
Global Oils implied CFROI® in the current share price
LKOH
on future discounted cashflows, and uses cashflow returns on investment (CFROI®) as a key
performance and valuation metric. A key appeal of the methodology, in our opinion, is to be able
to compare companies of different geographies and accounting standards, and to derive what
the current share price is implying in terms of future performance. Comparing those implied
returns in one stock with implied returns in other stocks can provide interesting insights, and
also comparing implied returns in one stock against what we expect the company will be able to
deliver.
LKOH
 HOLT’s appeal. HOLT is a proprietary valuation framework of Credit Suisse’s. HOLT is based
38
March 2014
LatAm Oil & Gas
Equity Research
How to value Petrobras?
Should Petrobras trade like Gazprom?
 A bear case. An often-cited bear case for Petrobras is that, due to increasingly
deteriorating performance of the business, and perceived higher Government intervention in
the company, Petrobras could end up trading like Gazprom, at 3x PE, 3x EV/EBITDA, and
at c.35% of book value.
 Should it, or should it not? To answer this question, we compare two key determinants
of multiple ratios (including the PE): returns, and cost of ownership. (1) Returns-wise, in the
bottom-right chart, we see that, Gazprom has never managed to sustain CFROI above the
5% level for long. Petrobras, on the other hand, has historically achieved much higher
return levels, sometimes above 10%. Higher returns should warrant a higher PE. However,
Petrobras recent returns profile has been similar or worse than Gazprom’s. A higher PE
multiple for Petrobras should be warranted inasmuch as investors believe that Petrobras’
could return to historical levels, or if current poor performance should be extrapolated into
perpetuity. (2) Cost of ownership wise, in the bottom left chart we look at HOLT’s countryimplied discount rates. With Brazil having a lower discount rate than Russia for much of the
past 20 years, a higher multiple for Brazilian companies is also warranted.
 For an in-depth discussion of the drivers and meaning of a Price/Earnings multiple, we
recommend an insightful reading from Credit Suisse’s Michael Mauboussin: ‘What Does a
Price-Earnings Multiple Mean? An Analytical Bridget between P/Es and Solid Economics’,
January 29 2014.
Brazil and Russia HOLT-implied discount rates* (%)
Petrobras and Gazprom PEs over time (x)
16.0x
12.0x
8.0x
6.0x
GAZP
4.0x
2.0x
0.0x
Jan-07
Nov-07
Sep-08
Jul-09
May-10
18%
18
Brazil’s lower market-implied discount rates historically
should warrant a higher PE multiple, ceteris paribus
16
14
Russia
12
10
Jan-12
Nov-12
Sep-13
PBR’s historically higher returns
should warrant a higher PE, if PBR
manages to revert the recent poor
trend, which is worse than GAZP’s
16%
14%
12%
PBR
10%
8%
6%
GAZP
4%
Brazil
6
4
1994-Feb
Mar-11
Petrobras and Gazprom CFROI over time (%)
CFROI (%)
HOLT-aggregate discount rates
(%)
PBR
10.0x
20
8
PBR historical PE premium to GAZP.
Should they trade at a similar
multiple?
14.0x
2%
1997-Jun
2000-Oct
2004-Feb
2007-Jun
2010-Oct
2014-Feb
0%
1995
1997
1999
2001
2003
2005
2007
2009
2011
2013E
Source: Bloomberg, Credit Suisse Research, Credit Suisse HOLT®, Aswath Damodaran. Note: full link to Michael Mauboussin’s report on https://plus.credit-suisse.com/u/kw6kLT. *Definition: HOLT discount rates are
solved for using firms' forecasted cash flows and market prices. HOLT derives discount rates by equating firms' enterprise values to the net present value of their forecasted free cash flows (FCFFs).
39
March 2014
LatAm Oil & Gas
Equity Research
How to value Petrobras?
Hypothetical equity issuance: At what price would you buy?
 Hypothetical. Petrobras is extremely vocal about not needing to issue further equity to finance
the current capex plan, which demonstrates management confidence that domestic prices will
rise enough to deleverage the company and that the company will be able to tap the debt
markets for further external finance if the short term scenario becomes (more) challenging. That
confidence, while unshakable, should not preclude an analysis of what should happen in an
extreme scenario where the company needs to come to be equity markets again, and a view of
at what price such hypothetical capitalisation would need to happen. We address this frequent
investor concern below.
Equity needs for PBR to keep cash levels at $25bn under different
FX and price increase scenarios ($m)
FX
2.0
2.2
2.4
2.6
2.8
3.0
0%
565
8,520
15,150
20,760
25,599
29,800
5%
0
6,382
13,190
18,950
23,919
28,232
10%
0
4,243
11,229
17,140
22,238
26,664
15%
0
2,105
9,269
15,331
20,558
25,095
20%
0
0
7,309
13,521
18,878
23,527
production growth of 7% in 2014 and slightly higher 10% in 2015, (2) that the debt markets
will be accessible up to $20bn/year of net new issuance, and (3) that PBR would need to raise
equity to recompose cash in the balance sheet of $25bn (= a minimum level of $15bn needed to
run the business + $10bn cushion in case of macro deterioration) – this assumption would
require less capital than an alternative scenario where PBR raised equity to get back to its 2.5x
ND/EBITDA target, and implicitly assumes that the scenario would improve further in the future.
 Conclusions: (1) PBR would need to raise $10-25bn in equity in scenarios where the FX goes
up to 2.8x and price increases until 2015 are between 5-15%, (2) even with the incremental
issuance, PBR would remain geared at c.4.0x ND/EBITDA – performance would need to
improve in the future to de-lever the company, (3) the price of the issuance would have to be at
the $7.5/ADR level in our view, so that investors would get a cheap PE of c.6.0x on earnings
that are reasonably conservative (ie price increases only close half of today’s gap, and the FX
goes to 2.6x).
PEs of an issuance done at $7.5/ADR under various FX and price
increase scenarios
Price increases in
2014-2015
 Assum ptions. In the exercise below, we use the following two important assumptions: (1)
PEs of an issuance done at the current c.$11.5/ADR share price
under various FX and price increase scenarios
FX
2.0
2.2
2.4
2.6
2.8
3.0
0%
2.8
4.2
6.3
9.8
16.4
34.2
5%
2.4
3.5
5.1
7.6
11.7
19.9
10%
2.2
3.0
4.3
6.1
9.0
13.9
15%
2.0
2.5
3.6
5.1
7.3
10.6
20%
1.8
2.2
3.1
4.3
6.0
8.4
Source: Company data, Credit Suisse analysis.
Price increases in
2014-2015
Price increases in
2014-2015
FX
2.0
2.2
2.4
2.6
2.8
3.0
0%
4.2
6.1
8.9
13.4
22.2
45.5
5%
3.7
5.1
7.3
10.5
15.9
26.7
10%
3.3
4.4
6.1
8.6
12.3
18.7
15%
3.0
3.8
5.3
7.2
10.0
14.3
20%
2.7
3.4
4.6
6.2
8.3
11.5
40
March 2014
LatAm Oil & Gas
Equity Research
Petrobras vs Big Oil: The Order of Merit
FOTO
Credit Suisse Order of Merit
Every year, the Credit Suisse Global Energy team publishes a comprehensive
analysis of the Integrated Oil Companies across a number of financial and
operational performance metrics. In this context, we analyse how Petrobras screen
vs its global peers in Upstream, Downstream and Overall.
Upstream vs Downstream
Returns: Lower for longer
Probably one of the most interesting trends of the global integrated oil industry is
the fact that it has not benefited from higher oil prices: returns in 2012 remained at
c.9% levels for the past four years, despite a rise in oil price from $60/bbl to
$110/bbl. This is also the same level of returns as in 2002, when oil prices were at
c.$30/bbl. Both in Upstream and Downstream, higher prices are not translating in
higher returns.
Capital intensity is the reason returns have not improved. Rising capital intensity
entirely offset rising profitability. Global oils as a group has been investing close to
90% of cash-generation for the past four years, a stark contrast to the c.60%
invested in the early 2000s. Even more impressive is the fact that, as a group, our
universe has not managed to significantly increase production despite rising
intensity.
Another interesting conclusion of our analysis is a clear ‘bifurcation’ in Petrobras
Upstream and Downstream businesses. Petrobras Upstream is one of the bestperforming globally, in all metrics we analyse: it grows more, it has the highest
profitability, cash-generation, and also returns. Downstream, on the other hand,
stands-out as the worst business globally: it is the only that is significantly loss
making, and capital intensity is three times above the industry average. The
downstream drag is so strong that as an integrated business, Petrobras, ranks
lowly in our analysis: (1) 2012 returns of 7% are the lowest in our universe, (2)
capital intensity is among the three highest, and (3) at 36% gearing, Petrobras is by
far the most-levered company in our analysis, which is a major impairment to the
company’s ability to keep investing in the future.
With a growing production profile from 2014, this will partially change, but a more
efficient Downstream pricing policy is needed for PBR to start to be competitive on
a global scale.
March 2014
LatAm Oil & Gas
Equity Research
Order of Merit
Returns trends
 All-tim e high oil prices, all-tim e low returns. Probably one of the most
interesting trends of the global integrated oil industry is the fact that it has not
benefited from higher oil prices: returns in 2012 remained at c.9% levels for the
past four years, despite a rise in oil price from $60/bbl to $110/bbl. This is also
the same level of returns as in 2002, when oil prices were at c.$30/bbl. Both in
Upstream and Downstream, higher prices is not translating in higher returns.
 Upstream vs Downstream . Comparing both charts on the right, we see two
clear trends, both which are crucial to the Petrobras investment case: (1)
Upstream has significantly higher returns than Downstream – both for PBR and
for the Industry; and (2) Petrobras performs significantly better than peers on
Upstream, but lags significantly on Downstream. The Downstream drag is so
significant that it brings the overall Petrobras returns below industry average, as
we can see on the bottom left chart.
Upstream ROGIC over time
(%)
40%
35%
16%
14%
12%
10%
8%
6%
4%
2%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Sector
Petrobras
80
25%
20%
60
15%
40
10%
20
5%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Sector
Petrobras
Oi price ($/bbl)
0
Downstream ROGIC over time
(%)
18%
0%
100
30%
0%
Consolidated ROGIC over time
(%)
120
Oi price ($/bbl)
120
20%
100
15%
80
10%
60
5%
40
0%
20
(5%)
0
(10%)
(15%)
Sector
Petrobras
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Source: Company data, Credit Suisse analysis. Note: ROGIC calculated as EBIDAX divided by Gross Invested Capital; all averages are weighted by company scale.
42
March 2014
LatAm Oil & Gas
Equity Research
Order of Merit
Returns rankings
 Petrobras best-in-class Upstream returns. The three charts on this slide
show a similar conclusion to the previous slide. Petrobras Upstream business
generates one of the highest Upstream returns in our universe, testimony to the
quality of the company’s assets, and even despite of lack of production growth in
the past years, something which has impacted the industry as a whole.
Upstream ROGIC rankings
(%)
2011
21%
18%
 Petrobras worst-in-class Downstream returns. The bottom-right chart makes
16%
14% 13%
very clear the impact Downstream has for Petrobras. It is the only company in our
universe that has significantly negative returns in Downstream. The only other
company that has a loss-making Downstream is ENI, but close to break-even.
13%
12% 11% 11% 11%
10% 9%
9%
2012
8% 7%
Consolidated ROGIC rankings
(%)
12%
9%
9%
9%
Repsol
Marathon
Total
ConocoPhillips
BP
R.D. Shell
ExxonMobil
BG
Average
Hess
Statoil
Chevron
ENI
Downstream ROGIC rankings
(%)
2011
11% 11% 10%
Petrobras
Downstream drag is so significant that it puts Petrobras on the bottom of the list
on a consolidated basis, with 7% returns level below the company’s cost of
capital and therefore value destructive. This also shows an opportunity: should
PBR achieve pricing parity, we can see the company quickly going close to the
top in our overall returns rankings in a very short timeframe.
OMV
 The need for transparent pricing. As the chart on the bottom-left shows, the
9%
9%
8%
8%
8%
7%
7%
2012
11%
9%
9%
2011
7%
7%
7%
5%
4%
3%
2012
3%
7%
Source: Company data, Credit Suisse analysis. Note: ROGIC calculated as EBIDAX divided by Gross Invested Capital; all averages are weighted by company scale.
Petrobras
ENI
R.D. Shell
Average
Repsol
Total
Hess
Statoil
BP
OMV
Chevron
(9%)
ExxonMobil
Repsol
Marathon
Petrobras
Total
ENI
R.D. Shell
ConocoPhillips
OMV
Average
ExxonMobil
BP
Hess
Statoil
BG
Chevron
(0%)
43
March 2014
LatAm Oil & Gas
Equity Research
Order of Merit
Capital deployment trends
 The reason returns have not im proved. Rising capital intensity is the reason
returns have not improves in the past decade, despite higher oil prices. Higher oil
prices also resulted in industry cost inflation. Coupled with the need to increase
investments in ever more complex environments to sustain an ever larger
production base, this means that wider industry capex in 2012 is at all-time high
levels, close to the $300bn mark.
 Investing m ost of the cash. Global oils as a group has been investing close to
90% of cash-generation for the past four years, a stark contrast to the c.60%
invested in the early 2000s. Here, Petrobras also stands out. The company has
been investing substantially more than cash generated since 2007, testimony to a
huge resource base. At some point, as production ramps-up and the benefits of
capex are reached, capital intensity should come down. Petrobras expects to
become free-cash positive by 2015-2016, an assumption dependent on
Downstream performance.
Capex/EBIDAX over time
(%)
180%
160%
Sector
140%
Petrobras
120%
100%
80%
60%
40%
20%
0%
Capex/Gross Invested Capital over time
(%)
Aggregate segmental capex over time
(US$bn)
25%
Upstream
Downstream
Other
Sector
20%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Petrobras
297
263
231
293
248
205
15%
176
10%
83
81
96
95
103
127
5%
0%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
44
March 2014
LatAm Oil & Gas
Equity Research
Order of Merit
Capital deployment rankings
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
72%
ExxonMobil
OMV
73%
76%
BP
76%
Repsol
80%
ENI
84%
StatoilHydro
84%
Chevron
93%
94%
2011
5
5
3
OMV
8
Marathon
11
Repsol
14
Hess
18
BG
19
ConocoPhillips
19
ENI
BP
Total
Chevron
2012
30
Average
34
Statoil
38
R.D.Shell
ExxonMobil
Petrobras
Repsol
ENI
OMV
ExxonMobil
BP
R.D.Shell
Marathon
ConocoPhillips
Total
Average
Statoil
Chevron
Petrobras
BG
Average
95%
R.D.Shell
105%
135%
106%
Total
Hess
40
5%
6%
6%
7%
7%
8%
8%
8%
8%
43
24
Hess
ConocoPhillips
2012
2012
Aggregate capex rankings
(US$bn)
9%
9%
10%
11%
2011
2011
Marathon
15%
16%
Capex/Gross Invested Capital rankings
(%)
Petrobras
clearly illustrated by company performance is the fact that Upstream is a much
higher capital intensity business than Downstream. Petrobras, BG and Hess, thre
three most-E&P focussed companies in our universe, are also the three that
present the higher capital intensity, both on a capex/EBIDAX and Capex/GIC
basis.
BG
 High E&P capital intensity. Another interesting feature of the industry that is
Capex/EBIDAX rankings
(%)
149%
by Exxon ($40bn) and Shell ($38bn), with Shell being the company with most
capex hikes in the past year. With its $237bn plan for the next five years, we
would expect Petrobras to keep the highest spend in the industry in the future.
153%
 The largest capex in the industry is from Petrobras ($43bn in 2012), followed
45
March 2014
LatAm Oil & Gas
Equity Research
Order of Merit
Balance sheet and leverage
5%
 Petrobras m ost-levered balance sheet. Petrobras gearing levels have
OMV
R.D.Shell
BG
ExxonMobil
Average
Total
Hess
Marathon
Petrobras
ConocoPhillips
BP
20%
2012
1%
9%
14%
17%
19%
20%
25%
20%
21%
30%
2011
24%
Petrobras
26%
Sector
27%
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
R.D.Shell
Statoil
Average
Total
BP
OMV
ENI
BG
ExxonMobil
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Marathon
0%
Hess
5%
ConocoPhillips
Petrobras
10%
Repsol
(9%)
15%
Chevron
35%
(7%) (8%)
(11%)
Net debt/Total capital rankings
(%)
27%
Net debt/Total capital trends
(%)
(1%) (2%) (2%)
(3%) (3%)
(4%) (5%)
30%
remained above those of the industry for most of the past decade. 2010 was the
exception year, when the company recapitalised, but it took only one year for
PBR to already be back to the highest gearing in the sector. The company is not
only the highest levered balance sheet, but also the one that is gearing up the
fastest. PBR’s gearing increased by 6 percentage points from 2011 to 2012, only
behind Conoco, and at a time most competitors delevered their balance sheets.
So far in 2013, gearing has continued to increase strongly, reaching 36% in
Q3’13. With production set to resume growth from 2014-onwards, a decrease in
gearing is now dependent on the Downstream pricing mechanism.
1%
ENI
3%
Repsol
6%
Statoil
6%
Chevron
mark. The sector never went up above the 25% mark in the past ten years. Low
gearing allows re-investment and capital intensity to remain high, which bodes
well for the oil services industry and for further M&A as a means to improve
RRRs, especially in U.S shale.
Net debt/Total capital change in 2012 over 2011
(% points change)
25%
 Gearing levels rem ain com fortable (for m ost) global oils, below the 20%
46
March 2014
LatAm Oil & Gas
Equity Research
Production & Reserves
Production overview
Oil and gas production rankings
(million barrels per day)
4.4
2011
55% 55% 55% 55% 54%
1.6
Repsol
OMV
2012
1.2
1.0
1.0
0.9
0.8
Marathon
ConocoPhillips
ENI
Statoil
Average
Total
R.D.Shell
Chevron
Petrobras
BP
ExxonMobil
BG
Repsol
R.D.Shell
ConocoPhillips
ExxonMobil
ENI
Statoil
Average
OMV
Total
BP
Chevron
Marathon
0.3 0.3
1.6
0.3
Hess
Hess
BG
ConocoPhillips
ENI
Statoil
Average
Total
BP
1.8
26%
Petrobras
0.4
2011
2.1 2.0
44%
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
0.5
Oil production rankings
(kbd, Thousands)
2.2
50% 50% 49%
1.6
0.3
0.2
0.2
0.1
Repsol
61%
1.8
OMV
69% 68%
1.8
BG
73%
2012
2.2
Hess
2011
84%
2.4
0.7
R.D.Shell
Oil production rankings and oil as % of total
oil as % of total production
2.6
ExxonMobil
companies in our universe, with 84% of total production being oil. We expect this
picture to continue in the future. LatAm has a large gas potential (coming from
pre-salt gas and some potential shale structures in Brazil – like Solimoes, Sao
Francisco, Parnaiba, and from shale in Argentina, mostly in the Vaca Muerta
formation), but Petrobras visible future production is still very levered to oily presalt.
2012
3.3
 Petrobras is oily. Another interesting metric is the fact that PBR is the most oily
Marathon
3.4
Petrobras
analysis universe, only behind Exxon, BP, Shell and Chevron. On the oil side,
PBR’s position is even more relevant, the third largest producer only behind
Exxon and BP. If PBR manages to get close to its goal of doubling production by
2020, it will not take long for us to see PBR on top of that list.
Chevron
 Petrobras is big. Petrobras is the 5th largest oil and gas producer among our
47
March 2014
LatAm Oil & Gas
Equity Research
Production & Reserves
Production growth (poor) track-record
 Growing is not easy. Production growth is one of the items that always gets our
Oil and gas production growth rankings
(%)
attention. Despite this being well-known, it is always impressive how difficult it is
for the industry to grow. We complain that Petrobras has not grown for the past
four years, but the industry has not grown significantly since 2001!
2011
19%
12% 11%
9%
 2011 was bad, 2012 better (but not good). 2011 was a poor year for the
industry, with production decreasing 4% mostly driven by Libya, asset disposals
and PSC effects. As a whole, the industry did not grow in 2012, with growth
from the ‘smaller’ companies (MRO, REP, STL, Hess) offsetting the lack of
growth and decline from the ‘big’ companies (XOM, BP, COP, CVX, TOT).
Going forward, Petrobras has the chance to stand-out it it achieves multi-year
6%+ growth, double the industry aspired growth of 2-3%.
7%
6%
3% 2%
1%
2012
0%
ExxonMobil
ConocoPhillips
BP
Chevron
Total
Average
Petrobras
R.D.Shell
BG
OMV
ENI
Hess
Statoil
Repsol
Marathon
-1% -2% -3%
-4% -6%
Oil and gas production growth over time (YoY growth)
(%)
Sector
12%
11%
5%
4%
10%
9%
4%
1%
3%
3%
Petrobras
5%
1%
5%
6%
0%
1%
2%
0%
-1%
0%
-1%
1%
1%
-1%
-4%
2000
2001
2002
2003
2004
2005
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
2006
2007
2008
2009
2010
2011
2012
48
March 2014
LatAm Oil & Gas
Equity Research
Production & Reserves
Reserves base
Oil reserves (proven SEC) rankings
(mmbbls, Thousands)
12.8
2011
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
0.4
Repsol
0.6
OMV
1.2
Hess
1.4
BG
1.6
Marathon
Statoil
Average
Total
BP
Petrobras
2.3
2011
2012
42.8 40.3
Hess
2.8 2.3
Marathon
2.8
OMV
4.9
Repsol
Petrobras
12.2 11.6
BG
Statoil
ConocoPhillips
ENI
23.1 21.0 19.6
17.0
Average
Chevron
Total
30.9 29.2
ExxonMobil
Repsol
BG
Statoil
R.D.Shell
ENI
ExxonMobil
ConocoPhillips
Total
Average
OMV
Chevron
BP
Hess
3.4
74.1
BP
2012
R.D.Shell
2011
77% 75%
Marathon
3.5
Gas reserves (proven SEC) rankings
(bcf, Thousands)
59% 57% 57%
54% 52% 52% 51%
49% 46% 45%
41%
35%
Petrobras
5.7
4.3
ExxonMobil
85%
6.2
ENI
6.5
to production. This is also illustrated by the fact that Petrobras ranks close to the
bottom of the list in gas reserves.
Oil as % of oil and gas reserves rankings
(%)
2012
9.9
 Oily reserves, too. PBR has the most oily reserves in our universe, 85%, similar
ConocoPhillips
11.0
R.D.Shell
relevant player in LatAm when it comes to reserves. Using the SEC criteria, PBR
is the second largest reserve base in our coverage, behind Exxon. When the presalt discoveries are fully incorporated in PBR’s reserve base, there is a 30bn bbls
potential that could easily put the company in a far 1st place position.
Chevron
 Petrobras is big, again. Similarly to production, Petrobras is by far the most
49
March 2014
LatAm Oil & Gas
Equity Research
Production & Reserves
Reserves life
15.8
company consistently had very high reserves life for most of the decade (c.14-18
years), and is likely to continue to be so as pre-salt resource is converted into
proven reserves. As production evolves and the company incorporates reserves,
the aim is to keep the reserve life at the 14 year level, one of industry’s best.
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
Statoil
Hess
Repsol
R.D.Shell
ENI
Marathon
Average
ConocoPhillips
Chevron
Total
OMV
8.3
2012
6.6
Statoil
12.7
Repsol
12.8
11.6
Chevron
11.5
R.D.Shell
11.6
10.6 10.4 10.4 10.4 10.0
ENI
11.6
13.2 13.2 12.7 12.3
12.0
OMV
11.8
14.8
Hess
12.1
14.6
Average
12.1
14.0
14.7
ConocoPhillips
12.5
13.6
14.7
Total
12.8
14.6
15.0
BP
16.0
15.4
Marathon
16.9
2011
Petrobras
12.7
17.1
22.1
BG
12.7
16.9
Petrobras
ExxonMobil
16.4
11.9 11.8 11.8 11.8 11.4
11.0 10.6 10.3
10.0
Proven oil reserves life rankings
(Years)
Sector
18.2
14.3 13.5 13.4
2012
8.0
ExxonMobil
Industry oil and gas reserves life over time
(Years)
2011
14.6
BP
 Petrobras’ strength is im pressive when it comes to resource potential: the
Proven oil and gas reserves life rankings
(Years)
BG
decreasing reserves life from the 12-13 to the 11-12 level, the industry jumped
back to 12.8 years of reserve life in 2011, remaining at that level in 2012.
Petrobras
 Im proving reserves life in 2011, stable in 2012. After years of slightly
50
March 2014
LatAm Oil & Gas
Equity Research
Production & Reserves
Reserves replacement ratio
Organic oil and gas reserve replacement ratio rankings
(3-year average, %)
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
61%
OMV
Total
77%
91%
BP
92%
93%
ConocoPhillips
R.D.Shell
94%
ExxonMobil
101%
97%
Chevron
Statoil
114%
Average
121%
Hess
129%
Petrobras
137%
137%
ENI
51%
50%
OMV
BP
2012
R.D.Shell
75%
79%
101%
105%
113%
117%
122%
144%
142%
89%
Total
ConocoPhillips
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Petrobras
74% 83%
2011
91%
Repsol
71%
104%
ExxonMobil
100% 103%
111% 129%
Statoil
77%
105%
Average
86%
78%
Chevron
120%
101%
141%
Hess
92%
128%
2010
ENI
112% 110% 110%
165%
160%
BG
161%
177%
186%
167%
186%
Petrobras
Marathon
Sector
2012
Organic oil and gas reserve replacement ratio rankings
(yearly average, %)
192%
Industry organic oil and gas reserve replacement ratio
(3 year average, %)
Marathon
BG
100% RRR in two of the past 13 years. Yearly numbers can be more volatile as
timing for reserve recognition is variable. Taking three-year averages, PBR
continues to post 130%+ RRRs, the same level as the more E&P-like companies
such as BG and Marathon.
160%
 … but not for Petrobras. Contrary to the industry, Petrobras was only below
2011
Repsol
industry only managed to do it, on a sustainable 3-year average, in six out of the
past 13 years. Of those six years, three were in the beginning of the decade.
More recently, the industry is increasingly more dependent on inorganic
measures (ie acquisitions) to adequately replace reserves.
217%
 100% organic reserve replacem ent ratio (RRR) is hard to achieve… The
51
March 2014
LatAm Oil & Gas
Equity Research
Upstream returns breakdown
Returns overview: Profitability vs capital intensity
 Breaking-down the industry returns profile. In analysing the industry
Upstream returns profile, we look at two key elements: profitability and capital
intensity. As we have highlighted, the Upstream is generating a similar level of
returns in 2012 (c.12%) as it was in 2002, when oil prices were c.$30/bbl, vs
c.$110/bbl in 2011.
 Profitability has gone up.... Higher oil prices meant that Upstream profitability
has gone up. Industry EBIDAX/bbl (our best proxy for cash generation) has
increased from c.$10/boe to c.$36/boe. Petrobras stands out with a best in class
$41/bbl EBIDAX generation.
 ...but so has capital intensity, and this is key to a flat returns profile despite
rising profitability. Upstream spends roughly 90% of cash-generated in 2012, up
from 50% in the beginning of the decade. PBR capital deployment has not been
dissimilar to that of the industry.
Upstream ROGIC over time
(%)
40%
Sector
35%
Petrobras
Sector
20%
12.8
11.4
11.3
11.0
8.6
9.8
13.4
10.4
16.4
17.7
60
15%
40
10%
20
5%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
0
Upstream Capex/EBIDAX over time
(%)
25.4
23.0
22.0
80
25%
Petrobras
21.2
100
Oi price ($/bbl)
30%
0%
Upstream EBIDAX per bbl over time
(US$/boe)
120
25.5
32.8
33.9
30.3
40.8
41.1
36.6
36.9
Sector
120%
30.0
73% 77% 70%
23.3
19.2
Petrobras
49%
70%
53% 58% 66%
58%
65% 66%
60% 64%
80% 90%
87% 91%
72%
75% 69%
13.0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
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Upstream returns breakdown
Upstream profitability
Upstream revenues per boe produced
(US$/boe)
Upstream net income per boe produced
(US$/boe)
2012
49
46
23
2012
Repsol
55
48
BG
64
ExxonMobil
66
ConocoPhillips
68
BP
72
OMV
72
Marathon
72
Hess
73
ENI
Total
Chevron
74
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
43
43
42
41
40
35
35
33
29
28
25
2012
22
22
BG
Hess
Repsol
ConocoPhillips
BP
ExxonMobil
OMV
Marathon
ENI
R.D.Shell
Total
Average
Chevron
9
Statoil
BG
10
Marathon
11
Repsol
11
Hess
12
ConocoPhillips
13
ExxonMobil
13
R.D.Shell
15
Total
15
Statoil
16
ENI
BP
Average
OMV
Chevron
Petrobras
18
2011
76
2011
Petrobras
2011
19
80
Upstream EBIT per boe produced
(US$/boe)
28
20
81
R.D.Shell
83
Statoil
91
Petrobras
expenses (due to higher exploratory success) and lower DD&A (lower depletion,
differences in accounting), Petrobras business is the most profitable in the
industry. Petrobras is generating close to $10/bbl more net income in Upstream
than the average oil company. Another interesting feature is PBR’s oily
production profile: Petrobras has the highest revenue per barrel in our universe.
Average
 High profitability. With higher cash-generation per barrel,, lower exploration
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Upstream returns breakdown
Upstream cost structure
 Costs keep rising. Like capital intensity, costs have been increasing at an
average 12% CAGR over the past decade. Upstream cash-costs reached
$23/boe in 2012, flat vs 2011 and up from c.$6/boe in 2000.
Upstream cash-costs per boe over time
(US$/boe)
Sector
 Operating cash-costs vs taxes. When we analyse cash costs before and after
taxes, we reach an interesting conclusion. Petrobras cash-costs (including
royalties) are the highest in our coverage, probably due to a high $18/bbl of
combined royalties + special participation cash costs. This is offset by a lower
corporate tax. PBR’s Upstream tax rate of 35% is virtually the lowest in our
universe. We note that average tax rate in the industry has been rising from
c.45% in 2000 to 56% in 2012, significant and a sign that Governments worldwide are taking a higher toll of oil profits with rising oil prices.
Petrobras
34.5
34.8
22.5
22.5
26.5
23.7
14.6
7.9
5.8
7.1
6.3
8.0
10.1
10.6
7.1
8.2
6.1
16.3
18.5
17.2
14.3
10.8
22.9
15.3
16.6
11.6
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
69% 68%
64% 61% 61%
58% 56% 56% 55%
2011
51% 50%
44%
OMV
Hess
Chevron
BG
Average
Repsol
ConocoPhillips
ENI
ExxonMobil
Total
R.D.Shell
12
2012
38% 35%
Petrobras
76%
Statoil
13
Total
14
BG
14
Repsol
15
ENI
15
Chevron
17
Marathon
19
OMV
19
ExxonMobil
20
Hess
23
Average
23
BP
23
R.D.Shell
ConocoPhillips
Petrobras
24
2012
Marathon
2011
Statoil
35
Upstream income tax rates rankings
(%)
BP
Upstream cash-costs per boe rankings (excluding income taxes)
(US$/boe)
54
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LatAm Oil & Gas
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Upstream returns breakdown
Upstream capital intensity
 Capital intensity is key to returns: it has been the reason for a flat returns
profile despite rising profitability. Upstream spent roughly 90% of cash-generated
in 2012, up from 50% in the beginning of the decade. Yearly performance has
been volatile for all the companies, but overall all of them are spending larger
portions of cash-flow vs 2000.
Upstream capex / EBIDAX over time
(%)
Sector
Petrobras
120%
 Upstream capex as % of Gross Invested Capital has remained relatively
stable through the decade at c.10% level. PBR has presented above-average
investment rates since most of the period analysed.
 F&D costs are lower for Petrobras vs Big Oil, mostly due to prolific acreage
leading to high exploratory success (leading to low finding costs) and high
reserves accretion. Industry organic F&D costs averaged $23/boe in 2012, close
to five times 2000’s $4.7/boe. Higher F&D are testimony not only to cost inflation,
but also to the increasingly tougher environments (deepwater, arctic, heavier oil)
oil companies need to go to replace reserves. Going forward, this trend could
change somewhat as shale increases its importance.
Upstream capex / GIC over time
(%)
Sector
73%
77%
70%
58%
49%
53%
60%
58% 66% 70%
64% 65% 66%
87% 91%
72%
75% 69%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Organic F&D costs over time (3-year average)
(US$/boe)
Sector
Petrobras
Petrobras
22.8
18.4
24.0%
15.9
16.5%
10.2%10.2% 9.7% 9.9%
80% 90%
8.8% 9.4%
18.1%
17.0%
10.7%11.9%
18.0%
13.5%
13.4
9.3% 10.9%10.6%
10.4
10.1%12.5%12.9%12.9%
4.7
4.7
3.7
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
8.3
6.3
5.3
3.5
6.5
3.7
19.1
15.3 16.0 16.1
15.5
14.7
14.0
19.8
11.7
9.7
6.6
3.5
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
55
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Upstream returns breakdown
Upstream capital intensity (cont’d...)
10.2
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
60%
61%
70%
72%
78%
OMV
ENI
BP
Petrobras
ExxonMobil
Statoil
Chevron
ConocoPhillips
Average
Marathon
Repsol
2011
21
20
Petrobras
Chevron
R.D.Shell
ConocoPhillips
Average
Statoil
Total
OMV
19
19
18
16
14
BP
22
Repsol
23
ENI
23
ExxonMobil
26
Marathon
28
2012
13
BG
36
8%
Repsol
8%
ExxonMobil
8%
Marathon
8%
ConocoPhillips
10%
ENI
7%
BP
10%
Total
12%
Chevron
11%
14%
2012
28
Average
R.D.Shell
13%
Petrobras
10%
Statoil
12%
OMV
Total
F&D costs rankings (3-year average)
(US$/boe)
2011
18%
Hess
BG
16%
Upstream capex / GIC rankings
(%)
R.D.Shell
3.5 3.6 3.9
2.9 2.5 2.6 2.5 3.6
1.1 1.0 0.9 0.9 0.9 1.0 1.3 1.9 2.3
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Hess
8.0
BG
3.5
6.1
2012
11.4 11.8 11.7
Hess
5.0
12.0
79%
16.5
14.0
84%
89%
97%
101%
110%
2011
115%
136%
Dev costs
142%
Finding costs
Upstream capex / EBIDAX rankings
(%)
140%
Organic F&D costs over time (3-year average), with F&D split
(US$/boe)
56
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Equity Research
Downstream
Refining overview
Refinery cover ratio (Refining capacity / oil & gas production)
Long Refining / Short Upstream
Refining capacity rankings (kbd)
3,360
1,953
0%
ConocoPhillips
0%
Marathon
18%
Statoil
47%
ENI
75%
Chevron
80%
BP
Average
Total
Repsol
83%
767
ExxonMobil
5,000
4,000
Royal Dutch Shell
3,000
Petrobras
2,000
442
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
316
Statoil
Repsol
Chevron
Total
Average
Petrobras
BP
R.D.Shell
ExxonMobil
998
OMV
2,048
ENI
2,107
93%
6,000
2012
Crude oil refined
2011
2,249
93%
2012
Crude oil refined vs oil product sold (kbd)
6,253
2,681
101%
R.D.Shell
150% 143%
every barrel refined. Globally, refining throughput is at 67% of marketing barrels
sold. This ratio is down for the 6th year in a row, as majors continue to rely more
on trading to supply marketing networks.
two decades as demand shrank and integrated companies continue to divest
downstream assets (Conoco spin off of PSX in 2012, Marathon’s spin off of
MPC in 2011).
2011
Petrobras
 More trading. In general, the industry is selling 1.5x barrels of oil product for
 Spin-off. Both marketing volumes and refining throughput fell to lowest levels in
Short Refining / Long Upstream
311%
ExxonMobil
Downstream positioning, with refining capacity roughly similar to total production.
In practice however, Downstream dominates the returns profile of the company
as PBR supplies a growing local Brazilian market with loss-making imports
subsidised by the company. Repsol/OMV/Exxon/Shell are long Refining,
whereas Total/BP/CVX/ENI/Statoil are long Upstream.
OMV
 Integration m atters. Petrobras is theoretically on a neutral Upstream vs
Chevron
1,000 EcopetrolOMV ENI
Statoil
0
0
YPF
Repsol YPF
ConocoPhillips
Hess
1,000
BP
2,000
3,000
Total
4,000
5,000
6,000
7,000
Oil products sold
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Equity Research
Downstream
Dark Ages in Europe, better elsewhere
 Dark Ages. Downstream returns peak in 2005-2006 at the 10% level, and have
been in continued decline since then. 2012 returns of 3.3% are at decade-lows,
skewed by Petrobras’ strong loss-making Downstream. Ex-Petrobras, returns
remain tepid at the 5.0% level.
Downstream ROGIC over time (%)
15%
 Declining profitability. The first element for a declining returns profile in
10%
Downstream is a structural profitability decline since 2005-2006. Profitability is
close to all time low levels at $1.1/bbl, barely profitable, though highly skewed by
Petrobras high losses of close to $15/bbl.
5%
 No capital discipline is the second element for a declining returns profile. Even
with a poor returns profile, capital intensity has not decreased significantly over
time. Capex was 5% of GIC in 2012, similar to 10-year average. Petrobras
capital intensity is close to 3x industry average at 15% of Gross Invested Capital.
Excluding Petrobras, the industry invested c.60% of cashflow (EBIDA)
generation in 2012, below 2009’s peak 123% but in line with ten-year average.
Downstream Net income per barrel sold over time (US$/bbl)
Sector
0%
Petrobras
(5%)
(10%)
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Downstream capex / GIC over time (%)
25%
15
Petrobras
10
5
Petrobras
20%
Sector
15%
0
10%
-5
5%
-10
Sector
-15
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
0%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
58
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Equity Research
Downstream
Profitability and capital intensity rankings
 Illustrating the dam age. All three figures in this slide illustrate well the negative
impact of Brazilian fuel pricing policy on Petrobras. Petrobras is by far the least
profitable refining business globally (bottom-left chart, net loss of $15/bbl), and is
by far the company that shows higher capital intensity (bottom-right, PBR invests
almost three times the industry average in Downstream). This has a devastating
effect on returns, with PBR ranking on the bottom of our universe (top-right
chart).
Downstream ROGIC rankings (%)
11%
9%
9%
2011
7%
7%
7%
5%
4%
3%
2012
3%
 Opportunity? In a way, we could also see this as an ‘opportunity’. Should PBR
0%
achieve pricing parity, capital intensity will remain high, but profitability will return
more in line to industry average and PBR’s Downstream business can start to
become competitive again.
Downstream Net income per barrel sold rankings (US$/bbl)
3.0
2.9
2.5
2.1
1.4
1.4
2012
5%
5%
6%
5%
4%
Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale.
2%
ENI
Total
BP
Statoil
Chevron
Average
OMV
Repsol
Petrobras
Petrobras
ENI
Average
Hess
Total
Repsol
BP
Statoil
ExxonMobil
R.D.Shell
Petrobras
ENI
4%
-14.5
OMV
R.D. Shell
Average
Repsol
Total
10%
3%
Chevron
2012
14%
-0.9
2011
Hess
Statoil
BP
OMV
2011
1.1
2%
3%
ExxonMobil
3.5
Hess
3.8
Downstream capex / GIC rankings (%)
R.D.Shell
3.9
Chevron
ExxonMobil
-9%
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Equity Research
The business plan
FOTO
The long-term : 2030
‘Petrobras self-sufficient, partners exporting’: this is a simple but yet effective way
to see long-term trends of the Brazilian oil sector. From 2020 to 2030, Petrobras
expects Brazilian oil production to remain relatively flat at the 5mbpd level. PBR will
follow the domestic demand with refinery additions, in a way to be close to fully
integrated (PBR oil production = PBR refinery capacity = Brazilian oil product
demand, with PBR’s partners and the Government’s share oil being exported).
Short-to-m edium term : 2014-2018
We provide a simple view of PBR’s 2014-2018 business plan, including how it has
evolved over time and the impact of Graça’s structural programmes in earnings and
cash balances. On the plan itself, we make the following observations: (1) a
$220bn capex plan is visually better than last year's $236bn, with an optically better
mix (E&P is 70% of the capex vs 62% in the last plan); (2) however, a $207bn for
projects being implemented / in bidding is virtually flat vs the last plan, and now
include the Northeast Premium refineries, which bidding will start in 2014 - a
negative, in our view; (3) a FX assumption to finance the plan of BRL/USD 2.231.92 looks aggressive and could generate skepticism in the market; (4) the only
true undisputed positive in the plan was a strong 7.5% growth announcement for
2014, with a +-1% range that is tighter than the usual +-2% - which we interpret as
a sign of greater management confidence. This is important as it comes at a
moment where consensus was turning incrementally negative on production.
March 2014
LatAm Oil & Gas
Equity Research
The business plan
The long-term: 2030
 ‘Petrobras self-sufficient, partners exporting’: this is a simple but yet effective way to see long-term trends of the Brazilian oil sector. As the chart below illustrates,
Brazilian production is expected to more than double from today’s 2mpbd levels, to 5mpbd by 2020, of which Petrobras will be responsible for 4.2mbpd. From 2020 to
2030, Petrobras expects Brazilian oil production to remain relatively flat at the 5mbpd level, and PBR’s share also relatively flat at the 3.7mbpd level. Oil product demand
is expected to grow by 2-3% p.a., increasing from today’s 2.3mbpd levels to c.3.0mbpd by 2020 and 3.7mbpd by 2030. PBR will follow the higher domestic demand
with refinery additions, in a way to be close to fully integrated (PBR oil production ~ PBR refinery capacity ~ Brazilian oil product demand, with PBR’s partners and the
Government’s share of crude oil production being exported).
Brazilian oil outlook: crude oil production, oil product demand, and refinery capacity
6
Average oil production in Brazil
Petrobras+Third Parties+Government 2020-2030:
5.2 millions bpd
Oil Products Self-sufficiency:
Total throughput = Total demand
5
Million bpd
4
Volumes Self-sufficiency:
Oil production = oil products consumption
Petrobras average oil production
in Brazil 2020-2030: 3.7 million bpd
Average demand for oil products in Brazil
2020-2030: 3.4 million bpd
3
2
1
0
2013
2014
2015
2016
2017
2018
2019
Throughput in Brazil
Source: Petrobras.
2020
Brazil
2021
2022
2023
2024
Oil Products Demand in Brazil
2025
2026
2027
2028
2029
2030
Petrobras
61
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Equity Research
The business plan
The short-medium term: 2014-2018
Business plan budgets over time ($bn)
$224bn $225bn
2014-2018 business plan budget split (%)
$237bn $237bn
$221bn
$174bn
$112bn
A budget that is optically down 7% YoY masks
a flat budget 'under implementation/bidding'
($207bn), with the inclusion of the Premium
refineries – a negative in our view.
$87bn
$54bn
Another optically positive is the
higher E&P mix and lower
Downstream mix in the new plan
vs the past. If we look at the
projects under implementation,
the mix barely changed from the
previous plan
Downstream
18%
G&P
5%
International
4%
Biofuels
1%
Distribution
1%
Others
E&P
70%
1%
5-year E&P plan over time: steady increase ($bn and %)
E&P spend
57%
$49bn
$74bn
Downstream
E&P share
51%
5-year Downstream budget over time ($bn and %)
$105bn
58%
60%
$65bn
$28bn
Source: Petrobras, Credit Suisse analysis.
$154bn
$142bn $148bn
$128bn
70%
$119bn
62%
60%
57%
53%
$71bn
Downstream share
$66bn
$65bn
$43bn
$13bn
$22bn
24%
25%
$39bn
$30bn
26%
25%
33%
31%
28%
27%
18%
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Equity Research
The business plan
‘In implementation’ vs ‘under evaluation’ and financing of the plan
Projects under implementation in the past three business plans ($bn and %)
$209bn
$207bn
$207bn
$19bn
$17bn
$14bn
25%
$52bn
21%
$43bn
19%
$39bn
66%
$138bn
71%
$147bn
74%
$154bn
2012-2016 plan
2013-2017 plan
E&P
Downstream
Dividing the business plan budget in ‘projects under
implementation’ and ‘projects under evaluation’ was an initiative
from the current management team. When we analyse this part
of the plan, the past three plans look incredibly similar, with c.
$207-209bn of projects being implemented (compatible with a
c.$40bn/year spend), with roughly 70% dedicated to E&P and
20% to refining. RNEST, COMPERJ and the Premium
refineries remain much contested projects by investors from an
economic perspective
2014-2018 plan
Others
Financing of the business plan ($bn and %)
$207bn
$207bn
$10bn
$11bn
$10bn
$9bn
$6bn
$21bn
$182bn
$165bn
2013-2017 plan
Net cash flow
New issuance
Source: Petrobras.
Cash
2014-2018 plan
Divestments / business models
Both 2013-2017 and 2014-2018 plans have similar budget
levels, but are financed differently. The 2014 version counts
with a much higher percentage of cash from operations, and
less debt issuances (a difficult assumption to see without
meaningful price increases, in our view).
A 2.23-1.92 BRL/USD rate in the new could be seen as
aggressive by the market, with a strong BRL vs current 2.4
levels. Even though, in the long term, Petrobras would benefit
from a stronger dollar (as a net oil exporter with domestic
prices following international levels in USD), in the short term
the company is negatively affected as a net importer, with most
revenues in BRL. This is important given the current situation
of the balance sheet.
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The business plan
Divisional summary
E&P 5-year capex summary ($bn and %)
Product Development
112.5 (73.1%)
Logistics for
Oil 1.4 (3%)
Refining Capacity Expansion
16.8 (43%)
Downstream
US$ 38.7 billion
Gas and Power capex summary ($bn and %)
Regas – LNG 0.1 (1%)
Energy 1.3 (13%)
Projects Under Im plem entation
Projects Under Im plem entation
RNEST (Pernambuco)
UNF III (Mato Grosso do Sul)
UNF V (Minas Gerais)
Route 2: Gas pipeline and NGPU
Route 3: Gas pipeline and NGPU
COMPERJ 1st phase (RJ)
Gas, Energy and
Gas-Chemical
US$ 10.1 billion
PROMEF - 45 Vessels to transport
Oil and Oil Products
Premium I - 1st phase (Maranhão)
Premium II (Ceará)
Operational Improvement
9.4 (24%)
Source: Petrobras.
Total with Partners
US$ 198.7 billion
(100%)
Projects Under Bidding Process
Quality and
Conversion
5.5 (14%)
E&P Partners
US$ 44.8 billion
(23%)
Pre-Salt (concession
+ ToR + Libra)
82.0 (60%)
Downstream capex summary ($bn and %)
Fleet Expansion
3.3 (9%)
Post-Salt
53.9 (40%)
Infrastructure and Support,
18.0 (11.7%)
Exploration
23.4 (15.2%)
Distribution 0.3 (1%)
Corporate 0.3 (1%)
Logistics for Ethanol 0.4 (1%)
Petrochemical 1.4 (4%)
E&P Petrobras
US$ 153.9 billion
(77%)
Production Development + Exploration
RS$ 135.9 billion
Total E&P
RS$ 152.9 billion
Gas-Chemical
Operational Units
(Nitrogenous 2.6 (25%)
Network
6.1 (61%)
64
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Equity Research
The business plan
Graça’s programmes: PROCOP, PROEF, PRODESIN, INFRALOG, PRC-Poço
Impact of structural programmes in PBR’s net income (R$bn)
Impact of structural programmes in PBR’s cash balances (R$bn)
R$ -9.7 billion (-41%)
23.6
R$ +14.7 billion (+47%)
46.3
4.3
+130 kbpd
3.3
2.1
+100 kbpd
+63 kbpd
8.9
0.8
0.7
4.3
13.9
31.6
Structural programmes gains are
equivalent of exports results of
+293 kbpd of crude oil
2013
Net Income
PROCOP
Operating Costs
Optimization Program
PRODESIN
Divestment
Program
PROEF
Program to Increase
Operational Efficiency
of UO-BC and UO-RIO
PROCOP in lifting costs (R$/boe)
34.8
+0.78% p.a.
32.7
2014
Cash
Position
2013
PRODESIN
Divestment
Program
PROCOP in Downstream logistics (R$/bbl)
-5.9% p.a.
-7.2% p.a.
2013 Net
Income without
Structuring
Program
27.3
24.2
2018
INFRALOG
Integrated
Management of
Logistics Projects
PRC Poço
Program to
Reduce Well
Costs
PROCOP
Cash Position
Operating Costs
without
Optimization
Structuring
Program
Programs
PROCOP in refining costs (R$’000/UEDC)
+1.32% p.a.
10.8
1,177
10.5
+0.12% p.a.
10.1
10.1
2014
2018
1,029
1,240
1,013
-0.40% p.a.
2014
2018
Gains from PROCOP reduce Lifting Cost
Gains from PROCOP reduce Logistic Cost
Gains from PROCOP reduce Refining Cost
Optimization of routine processes and resources used in
the production of oil & gas.
Integrating common and interdependent activities among
refineries.
Excellence level in the management of material and spares.
Reduction in shipping costs simplification of customs
procedures; optimization of fuel consumption; and
implementation of new management tools.
Adequacy of overhead.
Optimization of inventory level of oil and oil products.
Optimization in the consumption of energy, catalyzers and
chemicals.
Reduction of stored water in the logistics system.
Without PROCOP
Source: ANP data, Credit Suisse Research analysis.
Optimized use of support resources.
With PROCOP
65
March 2014
LatAm Oil & Gas
Equity Research
A little more on Upstream
FOTO
Braz ilian Pre-Salt
We provide a brief recap of the pre-salt, a new oil province discovered in 2006 and
which has been one of the major new oil frontiers globally. In 2005-2010, Brazil
was 62% of new deepwater discoveries globally, led by the pre-salt. Only in the
Santos basin (there is also pre-salt oil production in Campos and Espirito Santo),
there is a potential 23bn bbls of oil from the concession, transfer of rights and Libra
areas. The pre-salt currently
represents ‘only’ around 7% of Petrobras’
production, but its importance is expected to rise to 50% by 2020. We also
provide a brief overview of geology and the main technological challenges to
explore hydrocarbons below 2km of salt layer.
Ten fields to rem em ber
A lot of investor attention is given to Petrobras’ new projects and upcoming
platforms. These of course do matter, as are the source of future capacity addition,
and thus production. However, we think little attention is given to the existing fields.
And these do matter: despite having one of the largest production bases in the
world, Petrobras’ output is extremely concentrated around very large fields. We
provide useful detail on 10 selected fields that represent almost 70% of Petrobras
current oil production. Of the 10 fields we chose, 9 are among the top-ten
producers in Brazil (Marlim, Marlim Sul, Marlim Leste, Roncador, Jubarte,
Barracuda, Albacora, Lula and Baleia Azul), and the remaining one will be a large
producer and at the same time illustrates the challenges of the pre-salt and project
implementation (Sapinhoá).
March 2014
LatAm Oil & Gas
Equity Research
Brazilian Pre-Salt
What, Where and Who
 What. The pre-salt has been one of the major new oil frontiers globally. In 20052010, Brazil was 62% of new deepwater discoveries globally, led by the pre-salt.
Santos pre-salt map, key blocks, discoveries and PBR partners
 Where and who. There are currently 16 major pre-salt blocks in the Santos
BM-S-11 (Lula, Iara
and Cernambi):
 Petrobras (65%)
 BG (25%)
 Petrogal (10%)
basin, holding ‘at least’ 23bn bbls of oil:
– 10bn bbls in 9 blocks in the concession regime (BM-S-8, 9, 10, 11, 21, 22,
24), one of which was recently relinquished by Exxon (BM-S-22). Petrobras
partners in those blocks are BG, Petrogal, Repsol-Sinopec, QGEP and
Barra Energia.
– 5bn bbls in 6 blocks acquired by Petrobras in 2010 as part of the Transfer
of Rights (ToR) transaction (by order of size: Franco, Surround Iara, Florim,
Northeast of Tupi, South of Guara, South of Tupi). Petrobras owns 100% of
the areas.
– 8-12bn bbls in Libra, auctioned in 2013 as part of the first pre-salt auction
under the new PSC terms. Shell (20%), Total (20%), CNOOC (10%) and
CNPC (10%) are the partners.
 Cam pos
and Espirito Santo too. Most pre-salt resources are located in the
Santos basin, but there is also pre-salt oil in Campos basin (beneath existing
post-salt reservoirs and producing platforms) and also in the border with Espirito
Santo basin in Parque das Baleias.
Libra
 Petrobras (40%)
 Total (20%)
 Shell (20%)
 CNOOC (10%)
 CNPC (10%)
BM-S-10
 Petrobras (65%)
 BG (25%)
 Partex (10%)
Atlanta
Oliva
Franco
Libra
Cernambi
Florim
BM-S-8
 Petrobras (66%)
 Petrogal (14%)
 Barra Energia (10%)
 QGEP (10%)
BM-S-10
Parati
Surround Iara
Iara
NE of Tupi
Lula
Carcará
Carioca
Bem-te-vi
Júpiter
Sapinhoá
South of Tupi
Biguá
Global oil discoveries (2005-2010): 34bn bbls
Abaré
Abaré Oeste
Others
49%
Deepwater
51%
Source: Petrobras, ANP, Credit Suisse Research.
Other
countries
38%
BM-S-21
Caramba
Braz il
62%
BM-S-9 (Sapinhoá and
Carioca)
 Petrobras (45%)
 BG (30%)
 Repsol Sinopec (25%)
Peroba
South of
Guará
Producing units
BM-S-24 (Júpiter)
 Petrobras (80%)
 Petrogal (20%)
Transfer of Rights
Libra
Units to start
production
Pre-salt concession
67
March 2014
LatAm Oil & Gas
Equity Research
Brazilian Pre-Salt
Pre-salt’s early history
 It all started in 2000 and 2001, when PBR and partners participated in the 2nd
Key pre-salt blocks, discoveries, partners and size
and 3rd licence rounds and won the rights to explore 9 blocks in the Santos
basin. Of the 9 blocks, PBR was the operator with a majority 45-80% stake in 8
of them. The remaining block was BM-S-22, operated and already relinquished
by Exxon. In 2001, the largest 3D seismic programme at the time was hired to
cover the area. In 2003, seismic interpretation started to corroborate with the
thesis that there could be hydrocarbons beneath the salt layer. The decision to
drill, however, was more difficult given the high costs involved in drilling a UDW
well, 300km from the coast, below a 2km salt-layer and total depth of more than
6,000m. Drilling go-ahead was taken in 2003, and in March 2004 the Parati well
in BM-S-10 was chosen as the first location, and drilling started December 2004.
Above the salt-layer, Parati found a water-bearing reservoir, but gas shows led to
the decision of keeping drilling to reach the pre-salt. The well finished July 2006
and found gas condensate. Parati results motivated Petrobras to drill Tupi in
2006, opening up one of the world’s largest exploratory frontiers to date.
Block
100
Parati
Tupi
Jun-06
Sep-06
90
Tupi Sul
Carioca
Caramba
Jul-07
Sep-07
Dec-07
Júpiter
Bem-te-vi
Guará
Iara
Jan-08
May-08
Jun-08
Aug-08
Iguaçu
Iracema
Abaré W
Tupi NE
Declaration of Recoverable
Commerciality
volume
Discoveries
BM-S-8
PBR (66%), Petrogal (14%), QGEP (10%), Bem-te-vi, Biguá,
Barra (10%)
Carcará
BM-S-9
Petrobras (45%), BG (30%), Repsol (25%)
BM-S-10 Petrobras (65%), BG (25%), PAX (10%)
Petrobras share price and key pre-salt discoveries
(US$/ADR)
110
Consortium
Requested
Extension to
ANP
Dec-11
Dec-13
Sapinhoá (Guará)
Carioca
2.1bn bbls
-
Mar-16
-
Lula (Tupi)
BM-S-11 Petrobras (65%), BG (25%), Petrogal (10%) Cernambi (Iracema)
Iara
Dec-10
Dec-10
Dec-13
6.5bn bbls
1.8bn bbls
3-4bn bbls
BM-S-21 Petrobras (80%), Petrogal (20%)
Caramba
Apr-15
-
BM-S-24 Petrobras (80%), Petrogal (20%)
Petrobras (100%)
ToR
PBR (40%), Shell (20%), Total (20%),
Libra
CNOOC (10%), CNPC (10%)
Jupiter
7 Blocks
Feb-16
Sep-14
5bn bbls
Libra
Dec-17
8-12bn bbls
Apr-09
Jun-09
Sep-09
Nov-09
Guará N
Tupi OW
Franco
Tupi Alto
Mar-10
Apr-10
May-10
Jun-10
Iracema N
Tupi SW
Libra
Tupi W
Oct-10
Oct-10
Oct-10
Dec-10
80
70
Parati
-
Carioca NE
Macunaíma
Iara-Horst
Guará S
Biguá
Abaré
Jan-11
Feb-11
Mar-11
Jul-11
Nov-11
Nov-11
60
50
Carioca Sela
Franco NW
Carcará
Tupi NE
Dolomita S
Iara W
Sul de Guará
Franco SW
Júpiter NE
Carioca N
Feb-12
Feb-12
Mar-12
Mar-12
Apr-12
Apr-12
Jun-12
Aug-12
Oct-12
Oct-12
40
30
20
10
Jan-06
Jun-06
Nov-06
Apr-07
Sep-07
Source: Petrobras, IPEA, Credit Suisse, Woodmac.
Feb-08
Jul-08
Dec-08
May-09
Oct-09
Mar-10
Aug-10
Jan-11
Jun-11
Nov-11
Apr-12
Sep-12
Feb-13
Jul-13
68
March 2014
LatAm Oil & Gas
Equity Research
Brazilian Pre-Salt
Importance for PBR’s production profile
PBR production mix: pre-salt gaining share
 The pre-salt will be a key part of PBR’s future growth. Out of the 38
platforms Petrobras is adding in the 2013-2020 period, 26 are in pre-salt areas.
Currently pre-salt production is around 7% of Petrobras’ total. Petrobras has an
aspiration to increase that share to 42% by 2017 (35% pre-salt concession, 7%
ToR), and to 50% by 2020 (31% pre-salt concession, 19% ToR), without
including any production for Libra. In addition to production, pre-salt could
change PBR’s E&P profitability in a couple of ways: (1) higher productivity means
that Lula’s lifting cost today is almost half PBR’s c.$15/bbl average; (2) ToR
areas will not have SPT, which was already paid by PBR, and (3) when Libra
comes in, a PSC will result in lower profitability vs current fiscal terms.
Pre-Salt (Concession)
Post-Salt
2012
New Discoveries
2017
2.0 million bpd
2020
2.75 million bpd
7%
4.2 million bpd
7%
58%
Transfer of Rights
6%
44%
19%
93%
35%
31%
Petrobras production profile
4.5
CS estimates
10%+ p.a. growth
after 2016
Historical production
4.0
3.5
7%+ p.a. growth
until 2016
No growth
since 2010
 Espadarte
 Cd. Rio de
Janeiro
 100kbd
 Polvo
 90kbd
 Piranema
 30kbd
 Golfinho
 Cd. Vitória
 100kbd
 Marlim Leste
 P-53
 180kbd
 Golfinho
 Cd. Vitoria
 100kbd
 Roncador
 P-52
 180kbd
 Siri Pilot
 Cd. Rio
das Ostras
 15kbd
 Roncador
 P-54
 180kbd
 Marlim South
 P-51
 180kbd
2007
2008
Source: Petrobras, Credit Suisse.
 Tupi South
 Cid Sao Vicente
 30kbd
 Frade
 Frade FPSO
 100kbd
 Marlim Leste
 Cd. Niteroi
 100kbd
 Lula Pilot
 Cd. Angra dos
Reis
 100kbd
 Sapinhoa Pilot
 Cd São Paulo
 120kbd
 FPSO Capixaba
 Cachalote/Balei
a Franca
 100kbd
 Camarupim
 Cid Sao Mateus
 25kbd
 Sidon / Tiro
 Atlantic Zephyr
20kbd
 Parque das
Conchas
 100kbd
 Jubarte
 FPSO P-57
 180kbd
2009
 Lula NE
 Cd Paraty
 120kbd
2010
 Papa – Terra
 P-63
 150kbd
 Roncador
 P-55
 180kbd
 Marlim Sul
 SS P-56
 100kbd
2011
 Baleia Azul
 Cid Anchieta
 100kbd
2012
 Bauna /
Piracaba
 Cid Itajai
 80kbd
2013
 Franco (Buzios) 2
 P-75
 150kbd
 Sapinhoá
Norte
 Cid. Ilhabela
 150kbd
 (Start-up Q3)




 Franco (Buzios) 1
 P-74
 150kbd
Iracema Sul
Cd. Mangaratiba
150kbd
(Start-up Q4)
 Papa – Terra
 P-61 & TAD
 (Start-up Q2)




 Roncador
module 4
 P-62
 180kbd
 (Start-up Q2)
2014e
 Lula Norte
 P-67
 150kbd
 Franco (Buzios)
3 (NW)
 P-76
 150kbd
 Carioca (Lapa)
 Cd.
Caraguatatuba
 100kbd
 Iara Horst
 P-70
 150kbd
 Lula Sul
 P-66
 150kbd
Pq. Baleias
P-58 FPSO
180kbpd
(Start-up Q1)
 Lula Central
 Cid Saquarema
 150kbd




Iracema Norte
Cd Itaguai
150kbd
(Start-up Q3)
2015e
 Franco (Buzios)
4 (Sul)
 P-77
 150kbd
 Lula Alto
 Cd Marica
 150kbd
2016e
 Lula Oeste
 P-69
 150kbd
 Tupi NE
 P-72
 150kbd
3.0
2.5
 Entorno de
Iara
 P-73
 150kbd
 Iara NW
 P-71
 150kbd
 Sul
 Pq Baleias
 Carcará
 Deepwater
Espirito Santo
2.0
1.5
Pre-Salt + Libra
Transfer of Rights
Post-Salt
FPSOs already
contracted
 Florim
 Libra
 Lula Ext Sul +
ToR Sul de Lula  Deepwater
 P-68
Sergipe I
 150kbd
 Tartaruga Verde
e Mestiça
2017e
mnbpd
Petrobras targets
 Deepwater
Sergipe II
 Maromba
 Franco (Buzios)
5 (Leste)
 Marlilm Revitali II
 Marlim Revital I
 Júpiter
 Espadarte III
2018e
2019e
2020e
69
Brazilian Pre-Salt
Geology & Challenges
Ocean
Production platforms (FPSOs) need to (1) have
larger production facilities to deal with higher
flow of oil; (2) have more complex topsides to
treat high CO2 and H2S contents; (3) have
more robust mooring systems to resist higher
tensions and riser weight
March 2014
LatAm Oil & Gas
Equity Research
Historically PBR used flexible
risers for most developments. In a
minority of pre-salt fields, hybrid or
rigid solutions are required given a
higher level of wax and
contaminants in the oil (CO2, H2S)
and the lack of flexibles
qualification to resist high pressure
and low temperature for the full life
of the field. The first hybrid
installation is occurring in Tupi NE
and Sapinhoá, after substantial
delays and overruns from supplier
Subsea7.
Petrobras is conducting a number
of pilot tests to develop subsea oil,
water gas gas separation,
reinjection of produced water into
the seabed, gas-lift technology
enhancement, subsea gas
compression, oil boosting from the
seabed, and a new generation of
electric submersible pumps
capable of working in UDW
conditions.
0m
3.000m
Post Salt
Salt
A thick salt-layer with heterogeneous mechanical
properties, in addition to high depths, presents a
significant challenge for drilling, well casing and
geometry. The first pre-salt well, Parati, took 1year and
3 months to be completed. Today average pre-salt
drilling time is 150 days. Only in 2013, six years after
the Parati well, was PBR able to perform horizontal
drilling (85o angle) through the salt-layer
Pre-salt
Large Campos basin fields such as Marlim, Albacora
and Roncador have high porosity/permeability
sandstone reservoirs. Oil quality is heavy, c.20oAPI.
Some post salt reservoirs, such as Papa-Terra and
BS-4, are more challenging due to even heavier oil
(15oAPI) and shallow reservoir – both which would call
for TLPs rather than FPSO development
The salt layer is a barrier for traditional seismic to illuminate hydrocarbons. Advanced
seismic techniques such as wide-azimuth (WAZ) shooting were required before oil
companies could ‘see’ through the salt. The most tangible example has been Shell
relinquishing part of the BS-4 block that contained the Franco pre-salt discovery
because of lack of proper seismic imaging. PBR has recently specifically highlighted
the greater precision obtained in the ToR areas by WesternGeco’s Coil Shooting
technique.
4.000m
6.000m
Pre-salt reservoirs are mainly microbialite carbonates, less known and
more heterogeneous rocks than Campos’ basin sandstones. While so
far the reservoirs have shown to be extremely potent and productive, it
is still unknown how the reservoirs will respond to water and gas
injection, and how fast decline will be. Pre-salt oil, contrary to
Campos, is light, in the high 20s-30oAPI.
7.000m
Source: Credit Suisse Research.
70
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
PBR’s 10 most important fields
 They are im portant. Historically, a lot of investor attention is given to Petrobras’ new projects and upcoming platforms. These of course are important as a source of
future capacity addition, and thus production. However, we think little attention is given to the existing fields. And these do matter: despite having one of the largest
production bases in the world, Petrobras’ output is extremely concentrated around very large fields. We selected 10 fields that are already producing that represent
almost 70% of Petrobras current oil production. Of the 10 fields we chose, 9 are among the top-ten producers in Brazil (Marlim, Marlim Sul, Marlim Leste, Roncador,
Jubarte, Barracuda, Albacora, Lula and Baleia Azul), and the remaining one will be a large producer and at the same time illustrates the challenges of the pre-salt and
project implementation (Sapinhoá).
Table with 10-fields production, ranking of production, reserves,
and play type
Production
Ranking Field
(2013)
Oil
Oil
% of PBR
Production
reserves Basin
Production
(kbd)
(mmbbl)
Marlim Sul
291
15%
1,002
Campos Post-salt
22
Roncador
245
13%
1,297
Campos Post-salt
33
Marlim
177
9%
536
Campos Post-salt
44
Jubarte
138
7%
771
Campos Pre and Post salt
55
Marlim Leste
108
6%
268
Campos Post-salt
66
Barracuda
107
6%
278
Campos Post-salt
77
Baleia Azul
63
3%
406
Campos Pre and Post salt
88
Lula
63
3%
8,172
99
Albacora
58
3%
186
22
22
Sapinhoá
13
Source: ANP, Woodmac, Credit Suisse Research.
1%
1,797
Pre-salt
Campos Post-salt
Santos
1,400
70%
1,200
60%
1,000
50%
800
40%
600
30%
400
20%
200
10%
Play type
11
Santos
‘Ten fields’ oil production and importance to Petrobras
(production in kbd, share in %)
Pre-salt
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
0%
MARLIM
MARLIM SUL
RONCADOR
MARLIM LESTE
ALBACORA
BALEIA AZUL
BARRACUDA
JUBARTE
LULA
SAPINHOÁ
% of total
71
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Marlim
Oil production by vintage (kbd)
600
2013
Ownership
Location
Peak
Production
Oil
Quality
Petrobras
100%
Campos
Basin
595 kbd
(2002)
18-24º
API
Remaining
Reserves
Water
Depth
Oil: 536mmbbls 650-1,050
Gas: 5bcf
meters
 With initial reserves estimated at 2.7bn bbls, Marlin was Petrobras largest discovery
until the emergence of the pre-salt. After peak production of 595kbd in 2002, the
field has declined c.12% per year since, which led to increased efforts to improve
productivity, including infill drilling and a 4D seismic programme, and also the
Varredura project – Petrobras has made the pre-salt Brava discovery in 2010, below
Marlim reservoirs.
2012
2011
2010
Small amount of wells
drilled post 2008 coupled
with natural decline
400
300
200
100
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
Average well production by vintage (kbd)
600
25
20
400
P-37
300
P-35
P-33
P-26
P-20
P-19
P-18
200
100
pre 2009
500
Oil production by platform (kbd)
500
2009
Sharp decline of most
wells drilled post-2008
2012
15
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10 Jun-11 May-12 Apr-13
Source: ANP, Woodmac, Credit Suisse Research.
2009
10
pre 2009
2011
2013
5
2010
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10
Jun-11 May-12 Apr-13
72
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Marlim Sul
Oil production by vintage (kbd)
350
Ownership
Location
Oil
Quality
Remaining
Reserves
Water
Depth
Petrobras
100%
Campos
Basin
13-27º
API
Oil: 1,0bn bbls
Gas: 261bcf
1,159-1,874
meters
 Marlim Sul has a similar size to neighbour Marlim, with 1.8bn bbls of initial reserves.
Both fields were discovered only two years apart, but Marlim’s development took
priority due to a thinner and more heterogeneous reservoirs at Marlim Sul. The field
was developed in two phases. Phase 1 started in 2001 and aimed at exploring
reserves at up to 1,500m water depth. Phase two started in 2011 with the P-56
platform.
Good productivity of new
P-56 wells led to an
increase in production
300
2013
2012
250
200
2010
150
2009
100
Pre - 2009
50
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10 Jun-11 May-12 Apr-13
Oil production by platform (kbd)
Average well production by vintage (kbd)
350
30
300
25
250
P-56
P-56
2011
Good productivity and
slow decline of wells
drilled in 2011-2013
20
2009
2010
2011
2012
200
15
150
100
50
P-51 P-51
P-26 and others
FPSO Marlim Sul
P-40
P-40
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10 Jun-11 May-12 Apr-13
Source: ANP, Woodmac, Credit Suisse Research.
pre 2009
10
2013
5
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10 Jun-11 May-12 Apr-13
73
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Marlim Leste
Oil production by platform (kbd, LHS) and average well (RHS)
200
180
Ownership
Location
Oil
Quality
Petrobras
100%
Campos
Basin
23º
API
180
160
160
Oil: 268mmbbls
Gas: 98bcf
933-2,444
meters
120
25
100
20
20
Flat number of
producing wells
18
20
5
FPSO Cidade de Niteroi
0
Oil production by vintage (kbd, LHS) and number of wells (RHS)
200
12
120
100
10
100
8
80
6
60
40
4
40
20
2
20
20
Number of
wells count
180
120
Source: ANP, Woodmac, Credit Suisse Research
Others
0
Jan-08 Sep-08 May-09 Jan-10 Sep-10 May-11 Jan-12 Sep-12 May-13
140
0
10
40
160
0
Jan-08 Sep-08 May-09 Jan-10 Sep-10 May-11 Jan-12 Sep-12 May-13
15
60
14
60
P- 53
80
140
Total
30
140
16
80
35
Water
Depth
Oil production (kbd, LHS) and average production per well (RHS)
Average
prduction per
well (bbl/day)
Average well
production Cid.
De Niteroi
Remaining
Reserves
 Marlim Leste is smaller than Marlim and Marlim Sul, with c.470mmbbls of initial oil
reserves, and still 270mmbbls remaining. Given the smaller size versus the larger
fields, Marlim Leste full-development occurred 22 years after discovery. Discovery
was roughly at the same time as Marlim and Marlim Sul in the late 80s, but definitive
units FPSO Cidade de Niteroi and P-53 only started in 2008-2009. There is also one
producing pre-salt well in the Tracaja discovery linked to P-53. Average well
production has seen a strong decline, with current 6kbd being half of 12kbd in 2010.
200
40
Decline of old wells
connected to Cid.
de Niteroi
18
16
2011
2012
2013
2010
14
12
10
8
2009
Pre - 2009
0
Jan-08 Sep-08 May-09 Jan-10 Sep-10 May-11 Jan-12 Sep-12 May-13
6
4
2
0
74
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Roncador
Oil production by platform: P-55 and P-62 to come online in 2013
and 2014 (kbd)
400
Ownership
Location
Oil
Quality
Remaining
Reserves
Water
Depth
Petrobras
100%
Campos
Basin
18-31º
API
Oil: 1,3bn bbls
Gas: 338bcf
1,700 meters
Maintenance
in P-54
350
300
250
P-54
200
 With initial oil reserves of 2bn bbls and remaining reserves of 1.3bn bbls, Roncador
is one of Petrobras’ most important fields, something illustrated by the fact there are
two additional large units to start-up late 2013/early 2014 (P-55 and P-62, both
180kbd). Given its size, the field will be developed in four phases: (1) starting 1999
with P-36, which sank due to a gas explosion in 2011, and Brasil and P-52, starting
2002/2007; (2) With P-54 in 2007 to explore the heavier oil in the Southwest, and
modules 3 (P-55, Southeast) and module 4 (P-62, South/Central) upcoming.
150
P-52
100
Maintenance
in P-52
50
FPSO Brasil
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
Oil production (kbd, LHS) and number of wells (RHS)
Average production by well (kbd, LHS) and number of wells (RHS)
400
35
16
35
350
30
14
30
300
25
250
200
150
20
Number of
wells count
(RHS)
25
10
15
Flat number of wells,
declining productivity
Oil production (LHS, kbd)
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
Source: ANP, Woodmac, Credit Suisse Research.
10
6
4
20
Average
production per
well (LHS, kbd)
8
100
50
12
15
10
Number of
wells count
(RHS)
5
2
0
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
5
0
75
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Barracuda
Oil production by platform (kbd)
200
180
Ownership
Location
Peak
Production
Petrobras
100%
Campos
Basin
163 kbd
(2006)
Oil
Quality
Remaining
Reserves
Water
Depth
160
25º
API
Oil: 278mmbbl
Gas: 50bcf
800-873
meters
120
140
 With 710mmbbls of initial reserves, full production started in late 2004, reaching a
peak in 2006. Barracuda has so far produced 60% of initial reserves. The field is
facing an average 10% decline in observed production, though development drilling
on the eastern flank of the field with P-48 provided a rise in production in 2011-2012.
Like many other fields in the Campos basin, there is pre-salt potential below existing
post-salt reservoirs in the Nautilus discovery (made in 2010).
Oil production (kbd, LHS) and average well production (RHS)
200
180
160
Average well
production
(RHS, kbd)
Well additions on P-48
offset declining
productivity
140
120
100
80
60
40
20
Oil production (LHS, kbd)
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
Source: ANP, Woodmac, Credit Suisse Research.
Maintenance
in P-43
100
P-48
80
60
P-43
40
20
Others
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10 Jun-11 May-12 Apr-13
Average well production (kbd, LHS) and number of wells (RHS)
12
12
30
10
10
8
8
20
6
6
15
4
4
2
2
0
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
25
Number of
wells (RHS)
Average
production per
well (LHS, kbd)
10
5
0
76
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Albacora
Average well production by vintage (kbd)
8
Ownership
Location
Peak
Production
Petrobras
100%
Campos
Basin
156 kbd
(1999)
Remaining
Reserves
Water
Depth
19-29º
API
Oil: 186mmbbl
Gas: 6bcf
380-590
meters
6
 Albacora is a historically important field for Petrobras. Discovered in the mid 1980’s,
one year before Marlim, it led Petrobras to shift its focus to deepwater turbidite
sandstones. Given a wide range of water depths within the field, Petrobras opted for
a phased development. Production 1987, peaked in 1999 with the second phase,
and has been in a c. 7% decline since then. As part of the Varredura project,
Petrobras made a small 50mmbbls discovery in 2011, which has yet to be tested.
Other initiatives such as raw seawater injection are currently being tested in the field.
Oil production (kbd, LHS) and average well production (RHS)
140
2013
2012
2011
120
2010
2009
pre 2009
Well
productivity
(RHS, bbls/day)
5
4
2009
3
2
pre 2009
1
2012
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10
3,500
3,000
140
80
2,000
80
60
1,500
60
40
1,000
40
20
500
20
Source: ANP, Woodmac, Credit Suisse Research.
0
Maintenance in P-25
and P-31, ended in June
120
100
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
Jun-11 May-12 Apr-13
Oil production by platform (kbd)
2,500
100
2011
Low well
productivity in a
very mature field
7
Oil
Quality
P-50
P-31
P-25
Others
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
77
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Parque das Baleias: Baleia Azul
Oil production per well (kbd)
35
Ownership
Location
Petrobras
100%
Campos
Basin
Oil
Quality
17º (post-salt)
30º (pre-salt)
Remaining
Reserves
Water
Depth
Oil: 406mmbbl
Gas: 14bcf
1,338-1,348
meters
 Baleia Azul is a medium sized (c.400mmbbls) oil field located within Petrobras
Parque das Baleias complex, northern Campos basin. Other fields in Parque das
Baleias are Jubarte, Cachalote, Baleia Franca and Baleia Ana. Parque das Baleias is
interesting because it contains significant pre-salt oil reserves, to the tune of 1.52.0bn bbls, in addition to the known post-salt. Baleia Azul reserves are c.60% presalt. Field production started in 2012 already focused on the pre-salt, via FPSO Cid
Anchieta, and P-58 to start-up soon. Post salt will be targeted in 2014 with P-34.
Fields within the Parque das Baleias (Whale’s Park) complex
BM-C-25
BM-C-25
Argonauta
Baleia
Azul
20
7BAZ6ESS
15
10
7BAZ2ESS
5
7BAZ3ESS
0
Sep-12
Nov-12
Jan-13
Mar-13
May-13
Jul-13
Sep-13
Nov-13
Total and average well production (kbd, LHS) and well-count (RHS)
6
70
Number of
wells (RHS)
5
4
50
Nautilus
40
3
30
Mangangá
Average well
production
(LHS, kbd)
20
Caxareu Pirambu
6BRSA631DBE
SS
60
Baleia Franca
Jubarte
25
80
Cachalote Baleia Anã
ES
7BAZ4ESS
30
C-M-61
Oil production (LHS, kbd)
2
1
10
0
0
Sep-12
Source: ANP, Woodmac, Credit Suisse Research.
Nov-12
Jan-13
Mar-13
May-13
Jul-13
Sep-13
Nov-13
78
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Parque das Baleias: Jubarte
Oil production (kbd, LHS) and number of wells (RHS)
200
180
Ownership
Location
Oil
Quality
Petrobras
100%
Campos
Basin
17º (post-salt)
30º (pre-salt)
Remaining
Reserves
Water
Depth
Oil: 771mmbbl
Gas: 20bcf
1,245-1,347
meters
 Like Baleia Azul, Jubarte is a field within Parque das Baleias that has both post-salt
and pre-salt reserves. Pre-salt is estimated at c. 30% of total initial reserves. Postsalt development started in 2002 via an EWT. A pilot project using FPSO JK (P-34)
went from 2006 to 2012, producing from both pre and post-salt. End 2010, two units
started: P-57 targeting the post-salt, and FPSO Capixaba targeting the pre-salt.
FPSO Cid de Anchieta started in 2013, draining pre-salt oil mostly from Baleia Azul,
but also a smaller part from Jubarte. FPSO P-58 is due to start-up by year end 2013,
and will produce from both pre-salt and post-salt, also a unit that will drain oil from
Baleia Azul and Jubarte.
Oil production by platform (kbd)
160
Decline offset by the
increasing number of
producing wells
14
120
12
100
10
Number of
wells (RHS)
80
60
160
100
60
20
2
0
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13
15
0
Strong decline of P-57
wells since 2010
2010
pre 2009
2012/13
P-57
10
Maintenance
in FPSO JK
40
20
6
4
20
120
8
40
180
FPSO Cidade de
Anchieta to produce from
Jubarte, Baleia Azul and
Pirambu fields
16
140
25
140
18
Oil production
(LHS, kbd)
Average well production by vintage (kbd)
200
80
20
5
FPSO JK
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10
Source: ANP, Woodmac, Credit Suisse Research.
FPSO Capixaba
Jun-11 May-12 Apr-13
2011
0
Jan-05 Dec-05 Nov-06 Oct-07 Sep-08 Aug-09 Jul-10 Jun-11 May-12 Apr-13
79
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Lula (former Tupi)
Scheduled
maintenance,
ended in June
Well-by-well production (kbd)
35
Ownership
Location
Petrobras: 65%
BG: 25%
Petrogal: 10%
Oil
Quality
Remaining
Reserves
Water
Depth
Santos
Basin
28º
API
Oil: 8,172mmbbl
Gas: 3,934bcf
2,200
meters
30
140
Number of
wells (RHS)
120
20
3
Oil production (LHS, kbd)
2
1
20
0
Sep-10
0
Feb-11
Jul-11
Dec-11
Source: ANP, Woodmac, Credit Suisse Research.
May-12
Oct-12
Mar-13
3BRSA496RJS
9BRSA908DRJS
10
5
9BRSA716RJS
7LL3DRJS
0
Sep-10 Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13
140
FPSO
Cid. de Paraty
120
100
80
40
6
4
Average
pruduction per
well (LHS, kbd)
15
Oil production per FPSO (kbd)
5
100
60
7LL11RJS
25
 Discovered in 2006, Lula was not the first pre-salt discovery (it was Parati), but
surely the most prominent. With 8bn bbls, the field will be developed with 8 FPSOs,
with upside for more. Lula wells are producing at 20-30kbd and since 2010 when
full-development started with FPSO Cd Angra dos Reis, there has been no decline
observed. FPSO Cd Paraty recently started up in the NE flank, but with only one well
due to delays with the hybrid riser system. There is an ongoing discussion between
Petrobras and the ANP regarding the connectivity of Lula and Cernambi, which is
important due to fiscal treatment implications (if Lula and Cernambi are treated as
one field, higher Special Participation Tax is due).
Oil production, average production per well and number of
producing wells (kbd)
High quality wells:
slow decline and
high production
Aug-13
80
60
40
FPSO
Cid. de Angra dos Reis
20
0
Sep-10
Feb-11
Jul-11
Dec-11
May-12
Oct-12
Mar-13
Aug-13
80
March 2014
LatAm Oil & Gas
Equity Research
Ten fields to remember
Sapinhoá (former Guará)
Oil production (kbd): only one flexible riser producing so far
35
30
Ownership
Location
Petrobras: 45%
BG: 30%
Repsol: 25%
Oil
Quality
Santos
Basin
28-30º
API
Remaining
Reserves
Water
Depth
25
Oil: 1,797mmbbl
Gas: 1,209bcf
2,141
meters
20
 Discovered in 2008 and holding 2.1bn bbls, Sapinhoá is not the largest pre-salt
discovery, but its reservoirs are understood to be the best in the whole pre-salt. So
far two FPSOs are ascribed to the field: Cid de Sao Paulo (started in 2013) and Cid
de Ilhabela (due 2014). Together with Lula NE, Sapinhoá is facing strong delays in
the supply and installation of the hybrid riser systems (buoys), provided by Subsea7.
Both FPSOs (Cd Paraty in Lula NE and Cd Sao Paulo in Sapinhoá) are currently
producing from one flexible riser each. With each well capable of producing more
than 20kbd, the delays cost Petrobras 60kbd of production in 2013.
15
10
5
0
1-Jan
1-Feb
1-Mar
1-Apr
1-May
1-Jun
1-Jul
1-Aug 1-Sep
1-Oct
1-Nov
Illustration of a hybrid riser system
FPSO
Flexible jumpers
Buoy
Steel Catenary Risers
Due to the characteristics of the fields, Lula NE and Sapinhoa
required the use of relatively new hybrid technology, a departure
from PBR’s widely used flexible riser systems. Providor Subsea7
faced numerous delays and overruns with its $1bn workscope. Initial
deadline was for mid’12, whereas most likely date now is end’14
Mooring
lines
Wellheads
Source: ANP, Woodmac, Credit Suisse Research.
81
March 2014
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Equity Research
A little more on Downstream
FOTO
Refineries overview
In theory, Brazil is a great market for refineries to be set up. The market is large, it
grows, and it’s just next to large oil reserves in the Campos and Santos basin,
taking much of logistics and raw material purchase issues. In practice, government
influence on prices have eroded the economics, and lack of inter-regional logistics
and higher obstacle to build refineries in the NE (the highest growing region with a
regional supply gap) further increases costs of the Downstream business in Brazil.
Downstream demand
Brazil’s transportation matrix is extremely road-dependent. Together with Brazil’s
continental size, a high dependence on road-transportation is a strong driver of diesel
demand. Add to that incentives to the automotive industry (7% p.a growth in the fleet),
and you have a complete equation of diesel demand in Brazil.
Gasoline being pretty much driven by the light-vehicle fleet in Brazil, demand has been
highly correlated to the rise in the income of the middle class (together with reduction of
taxes for purchase of vehicles). Easy substitution between gasoline and ethanol are now
increasingly a reality, with the ethanol+flex-fuel fleet being 50% of total light vehicle
fleet. Therefore, effects in the ethanol industry have an implication for the gasoline
market in Brazil.
Distribution
In this section we provide the evolution of the consumer price of gasoline, diesel and
LPG, across Brazil, alongside a breakdown of the constituents of the pump price. The
data gives interesting insights into the fuel pricing dynamics in Brazil, for instance: (1)
the multiplier effect of higher refinery prices into sometimes higher distribution and
resale margins, state taxes, offset by the decrease in Federal taxes (CIDE) to keep a lid
on inflation; (2) on the LPG side, Petrobras prices have remained flat, alongside
distributors profitability, but that has not prevented wider cost inflation to push LPG
bottles’ prices from increasing; (3) higher profitability of gasoline than diesel due to the
large scale nature of diesel consumers commanding stronger pricing power; (4)
different profitability amongst regions within Brazil (higher convenience needs in the
S/SE can command higher prices in the region, higher white-flag competition in the
Northeast keeps a lid on profitability, whereas in the North, despite higher informality, a
low-density network of distribution channels and resellers gives them better pricing
power, making margins in the North one of the highest in the country).
March 2014
LatAm Oil & Gas
Equity Research
Refineries overview
Old refineries and poor distribution infrastructure
Refinery capacity
(kbd)
• REMAN (built in 1949)
• LUBNOR (1966)
• RPCC (2009)
393
• RNEST (2014)
281 252 239
195 189 172 151
• RLAM (1956)
• REGAP (1968)
• REDUC (1961)
• REVAP (1980)
• REPAR (1977)
• RPBC (1952)
• REFAP (1968)
36
8
Output of refined products over time
(kbd)
2,500
1,500
1,000
500
0
Jan-00 Oct-01
Other
Source: Credit Suisse research based on Petrobras and the ANP.
46
2,000
• REPLAN (1972)
• RECAP (1954)
53
Jul-03
Naphtha
Apr-05 Jan-07 Oct-08
LPG
Fuel Oil
Jul-10
Gasoline A
Apr-12
Diesel
83
March 2014
LatAm Oil & Gas
Equity Research
Refineries overview
Southeast surplus, Northeast deficit
 Theory. In theory, Brazil is a great market for refineries to be set up. The market is large, grows, and is just next to large oil reserves in the Campos and Santos basin,
taking much of the logistics and raw material purchase issues.
 Practice. In practice, there have been a couple of problems with the Brazilian downstream market. Firstly, and most importantly, government influence on prices have
eroded the economics. Secondly, even though now Brazil is a net importer of diesel and gasoline, regional supply-demand is not balanced. A high concentration of
refining capacity in the Southeast has created a surplus in that region and a deficit in the Northeast. As a country, we could have two options: (1) keep building in the SE
but increase interregional distribution, which is poor; (2) build refineries in the Northeast – which recent experience has proved problematic – Abreu e Lima will have total
costs of c.$20bn, vs an initial budget of c.$2bn. The lack of infrastructure in the Northeast makes building a refinery in the NE in theory more expensive than in the SE.
Gasoline production and consumption per region
(kbd)
Consumption
Diesel consumption and production per region
(kbd)
Production
Production Surplus in the Southeast
Production
537
312
245
400
Fastest growing regions: high
expansion in disposable incom e
coupled with lack of production
110
107
195
181
NE
Source: Credit Suisse research based on the ANP. Data for 2013.
156
107
51
120
96
35
8
0
S
Abreu e Lima refinery
to increase Northeast
production capacity
104
65
SE
Consumption
MW
N
14
0
SE
S
NE
MW
N
84
March 2014
LatAm Oil & Gas
Equity Research
Refineries overview
Southeast overview
Southeast: Refinery capacity and product yield
(kbd)
• REGAP (1968)
• REDUC (1961)
• REVAP (1980)
• REPLAN (1972)
• RPBC (1952)
450
400
350
300
250
200
150
100
50
0
• RECAP (1954)
REPLAN
REVAP
REDUC
RPBC
REGAP
Other
Naphtha
LPG
Fuel Oil
Gasoline A
Diesel and gasoline production surplus in the Southeast
(kbd)
Southeast: Output of refined products over time
(kbd)
200
1,400
RECAP
Diesel
1,200
Diesel
150
1,000
800
100
600
400
50
200
Gasoline A
0
Jun-00
Feb-02
Oct-03
Jun-05
Source: Credit Suisse research based on the ANP.
Feb-07
Oct-08
Jun-10
Feb-12
0
Jan-00 Nov-01 Sep-03 Jul-05 May-07 Mar-09 Jan-11 Nov-12
Other
Naphtha
LPG
Fuel Oil
Gasoline A
Diesel
85
March 2014
LatAm Oil & Gas
Equity Research
Refineries overview
North and Northeast overview
North/Northeast: Refining capacity and product yield
(kbd)
• REMAN (built in 1949)
• LUBNOR (1966)
• RPCC (2009)
• RNEST(2014)
• RLAM (1956)
300
250
200
150
100
50
0
RLAM
Other
REMAN
Naphtha
Fuel oil
RPCC
Gasoline
LUBNOR
Diesel
Consumption of oil distillates: N/NE highest growing regions
Index (2000 = 100)
North/Northeast: Output of refined products over time
(kbd)
185
175
165
155
145
135
125
115
105
95
85
400
350
300
250
200
150
100
50
2000
2002
Midwest
2004
2006
2008
2010
Northeast
North
Southeast
Source: Credit Suisse research based on the ANP.
2012
South
0
Jan-00 Dec-01 Nov-03 Oct-05 Sep-07
Diesel
Gasoline A
Fuel Oil
Aug-09 Jul-11
Jun-13
Naphtha
Other
86
March 2014
LatAm Oil & Gas
Equity Research
Downstream demand
Diesel demand driven by economic activity, Gasoline by income
Diesel consumption per region
(kbd)
1,200
Diesel consumption growth among regions is more
evenly distributed than gasoline, where the North-NE
grow disproportionally more (income effect)
1,000
800
600
Diesel consumption x Industrial production index (2002 = 100)
(kbd and index )
1,100
CAGR
North
Midwest
5%
4%
Northeast
5%
South
3%
400
Southeast 4%
Apr-02
Jul-04
Oct-06
Jan-09
900
140
130
800
120
110
700
600
500
400
300
900
North
Midwest
8%
6%
Northeast
7%
700
South
5%
600
Southeast
100
Jul-04
Oct-06
Sep-01 May-03
Jan-05
Sep-06 May-08
90
Jan-10
80
Sep-11 May-13
1,000
CAGR
2,500
Seasonal increase during year end due to 13rd
salary income boost and vacation period
Jan-09
Source: Sindicom; Credit Suisse Research based on the ANP.
Apr-11
3%
2,000
800
500
200
Apr-02
Diesel (kbd,
LHS)
Gasoline and Ethanol consumption vs average income in Brazil
(kbd of gasoline equivalent, BRL)
Growth in gasoline consumption is concentrated
in North, Midwest and Northeast regions
800
100
600
500
Jan-00
Apr-11
Gasoline consumption per region
(kbd)
0
Jan-00
150
Industrial
production
(index, RHS)
1,000
700
200
0
Jan-00
160
1,500
Fuel
consumption
(kbd, LHS)
Average
Income (R$,
RHS)
400
300
Jan-02
1,000
500
Jul-03
Jan-05
Jul-06
Jan-08
Jul-09
Jan-11
Jul-12
87
March 2014
LatAm Oil & Gas
Equity Research
Downstream demand
Diesel demand fueled by transportation matrix and fleet growth
 Hit the road. As we show on the top-right chart, Brazil’s transportation matrix is
extremely road-dependent. Together with Brazil’s continental size, a high
dependence on road-transportation is a strong driver of diesel demand. Add to
that incentives to the automotive industry (7% p.a growth in the fleet), and you
have a complete equation of diesel demand in Brazil. For those reasons, there is
a high correlation between diesel demand and economic activity in Brazil.
Transportation matrix in selected countries
(%)
17%
25%
4%
43%
13%
11%
37%
46%
25%
43%
58%
Brazil
Licensing of new diesel vehicles
(thousand units)
420
Heavy Vehicles
140
70
0
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
Source: Credit Suisse Research.
China
Road
Rail
32%
Canada
USA
Water & Others
8%
Russia
123
Road-intensive transportation matrix and
continental dimension puts Brazil as 3rd
largest consumer in the road sector
33 32 31 28
210
43%
Consumption of diesel in the road sector
(kt of oil equivalent)
2000-2012 CAGR: 7%
280
Australia
50%
81%
17 15 15 15 14 13 11 10
9 9 6 5 5 5 4 4 4 3 3 3
United States
India
Brazil
France
Germany
Canada
Saudi Arabia
Russia
Mexico
Korea
Indonesia
Thailand
Australia
Poland
Turkey
Egypt
Vietnam
South Africa
Malaysia
Philippines
Colombia
Sweden
Peru
Chile
Venezuela
350
Light Vehicles
53%
11%
88
March 2014
LatAm Oil & Gas
Equity Research
Downstream demand
Gasoline and Ethanol are substitutes
 Incom e. Gasoline being pretty much driven by the light-vehicle fleet in Brazil,
demand has been highly correlated to the rise in the income of the middle class
(together with reduction of taxes for purchase of vehicles).
 Flex -fuel. Gasoline-ethanol substitution is also an important factor to monitor. Easy
substitution by drivers is now increasingly a reality: ethanol + flex fuel cars now
represent c.50% of the light vehicle fleet, a strong increase vs the 20% back in 2005.
In general terms, if hydrous ethanol is being sold at any price below 70% the price of
gasoline at the pump, consumer will use ethanol. The ratio is based on the energy
efficiency of the two fuels.
 Ethanol. Therefore, effects in the ethanol industry have an implication for the gasoline
market in Brazil. For instance, from 2010-2012, high sugar prices and a weak harvest
made sugarcane producers shift ethanol production to sugar, putting a cap on ethanol
supply, and forcing all the growth of the market to de catered by gasoline imports. In
this spirit, incentives to the ethanol industry are crucial to ensure adequate ethanol
supply, and in turn decrease the gasoline import needs from Petrobras.
Gasoline and hydrous ethanol consumption
(kbd)
900
Growth in Fuel
demand answered
by ethanol
800
700
100
0
Jan-00
4
Flex fuel and ethanol went from 21% of the
fleet in 2005 to c.50% in 2012, and is
expected to rise to 68% by the end of the
decade
3
20
2
10
1
0
2005
2006
2007
2008
Gasoline Fleet, LHS
Ethanol fleet, LHS
75%
70%
2009
2010
2011
2012
0
Flex fuel, LHS
Net additions to flex fuel, RHS
Gasoline more competitive
Max. Parity
65%
400
200
30
80%
Pressure on Gasoline C
demand due to high
ethanol prices at the pump
Gasoline C
300
40
Price parity in São Paulo between Gasoline C and Ethanol
(%)
600
500
Light vehicles fleet by fuel type
(mn vehicles)
60%
55%
Hydrous
Ethanol
Oct-01
50%
Jul-03
Apr-05
Jan-07
Source: UNICA, Bloomberg, Conab, Credit Suisse Analysis.
Oct-08
Jul-10
Apr-12
Price ratio
Ethanol m ore com petitive
45%
Jan-08 Sep-08 May-09 Jan-10 Sep-10 May-11 Jan-12 Sep-12
89
March 2014
LatAm Oil & Gas
Equity Research
Distribution
Pricing overview
Domestic gasoline pump prices breakdown (%)
Domestic diesel pump prices breakdown (%)
18%
Resale and distribution
13%
Anhydrous ethanol cost
27%
ICMS (state tax)
7%
CIDE, PIS/ PASEP, CONFINS (Federal taxes)
35%
Refinery gasoline price (Petrobras)
Gasoline pump prices comparison across countries (US$/liter)
16%
4%
14%
6%
Resale and distribution
Biodiesel cost
ICMS (state tax)
CIDE , PIS/ PASEP, CONFINS (Federal taxes)
60%
Refinery diesel price (Petrobras)
Domestic LPG consumer price breakdown (%)
2.6
2.2
1.9
1.5
Resale / Distribution margin
Taxes
1.1
0.7
Anhydrous ethanol
Refinery price
Source: Petrobras, ANP, MME, Credit Suisse Research.
Brazil
Uruguay
Chile
Argentina
USA
Canada
China
Japan
UK
Germany
0
Italy
0.3
56%
Resale and distribution
12%
5%
ICMS (state tax)
CIDE, PIS/ PASEP, CONFINS (Federal taxes)
27%
Petrobras price realisation
90
March 2014
LatAm Oil & Gas
Equity Research
Distribution
Consumer price dynamics
 The charts in this slide show an average of the consumer price of gasoline, diesel
and LPG, across Brazil, alongside a breakdown of the constituents of the pump
price. Even with the caveat that prices are Brazil-wide (and therefore different
pricing strategies within regions and an increasing mix to the North/NE could
pollute the trends), we find the data gives an interesting insight into the dynamics
of the fuel pricing policy in Brazil. Petrobras’ prices of gasoline, diesel and LPG
are not increasing fast enough (gasoline and diesel) or not increasing at all
(LPG). When Petrobras does increase prices, we see somewhat a multiplier
effect, with sometimes higher distribution and resale margins, and an offsetting
effect from a decrease in federal taxes (CIDE). A changing ethanol (20-25%) mix
also has an impact on pump prices. On the LPG side, increasing resale and
distribution ‘margins’ have been pushing prices higher, despite relatively flat
taxes and Petrobras LPG prices. This however seems not to come from
distributors higher profitability (Ultrapar, a listed company with business in LPG
distribution, has struggled to keep profitability of the business flat in the past five
years) but rather from wider cost inflation or even some regional mix effects.
Gasoline pump price evolution over the years (R$/liter)
3.0
Local taxes
2.5
1.0
Federal Taxes
Transportation
costs
Resale margin
Distribution
margin
Anhydrous
ethanol
0.5
Gasoline
2.0
1.5
0.0
May-08
Apr-09
Mar-10
Feb-11
Jan-12
Dec-12
Nov-13
LPG consumer price evolution over the years (R$/bottle)
Diesel pump price evolution over the years (R$/liter)
45
2.5
40
35
30
Local Taxes
Federal Taxes
Transportation
Costs
Resale Margin
2.0
Distribution
Margin
1.0
25
20
15
Federal Taxes
Transportation
costs
Resale margin
Distribution
margin
Biodisel
1.5
Diesel
10
LPG
5
0
May-08
Local taxes
Apr-09
Mar-10
Source: MME, Credit Suisse Research.
Feb-11
Jan-12
Dec-12
Nov-13
0.5
0.0
May-08
Apr-09
Mar-10
Feb-11
Jan-12
Dec-12
Nov-13
91
March 2014
LatAm Oil & Gas
Equity Research
Distribution
Distribution, resale and refinery price trends
 In this slide we analyse Brazilian wide trends for refinery prices, and compare them with
distribution and resale margins. On the top right chart, we illustrate a relatively known fact:
gasoline is more profitable than diesel, and resellers, on a per liter basis, make more money
than distributors. Gasoline margins are higher than diesel due to less consumer pricing power
of individuals driving cars vs large corporations fueling their fleet or diesel-consuming
industries.
 On the charts in the bottom, we illustrate a more general trend of rising distribution margins,
alongside higher refinery prices. Distribution margins have been increasing in the past years
for a number of reasons, formalisation of the industry, better competitive practices from key
incumbent players (BR, Ipiranga, Raizen), but also due to increase (albeit not as frequently as
PBR needs) refinery prices, which makes it easier for distributors and resellers to have pricing
power with customers. The volatility in the distribution margins in the charts below, in our
view, also reflects other factors such as monthly regional mix in sales. As we will see in the
next slides, different regions command different profitability over time for both distributors and
resellers (a number of factors come into play here – higher convenience needs in the S/SE
can command higher prices in the region, higher white-flag competition in the Northeast keeps
a lid on profitability, whereas in the North, despite higher informality, a low-density network of
distribution channels and resellers gives them better pricing power, making margins in the
North one of the highest).
Distribution margin (R$/l)
0.16
0.14
Gasoline
0.12
0.10
0.08
0.30
0.25
Diesel resale
margins
0.20
Gasoline
distribution
margins
0.15
0.10
Diesel
distribution
margins
0.05
0.00
May-08
1.60
1.40
1.20
1.00
0.80
0.60
0.40
0.06
0.20
0.04
May-08 Feb-09 Nov-09 Aug-10 May-11 Feb-12 Nov-12 Aug-13
0.00
Source: MME, Credit Suisse Research.
0.35
Jan-09
Sep-09
May-10
Jan-11
Sep-11
May-12
Jan-13
0.16
Distribution margin (R$/l)
Distribution
margin
Gasoline resale
margins
0.40
Sep-13
Diesel margins vs refinery price (R$/liter)
Gasoline refinery price (R$/l)
0.18
0.45
1.80
1.60
0.14
1.40
Diesel
1.20
0.12
0.10
0.08
1.00
0.80
Distribution
margin
0.60
0.40
Diesel refinery price (R$/l)
Gasoline margins vs refinery price (R$/liter)
Gasoline and diesel distribution and resale margins (R$/liter)
0.20
0.06
May-08 Feb-09 Nov-09 Aug-10 May-11 Feb-12 Nov-12 Aug-13
0.00
92
March 2014
LatAm Oil & Gas
Equity Research
Distribution
Which region is more profitable?
Gasoline distribution margins by region (R$/liter)
Gasoline resale margins by region (R$/liter)
0.30
0.50
N
0.25
0.45
0.20
MW
0.40
SE
0.15
NE
0.35
0.10
S
0.05
0.00
May-08
N
NE
Sep-09
SE
0.25
MW
Jan-09
0.30
May-10
Jan-11
Sep-11
May-12
Jan-13
Sep-13
0.20
May-08
S
Jan-09
Sep-09
May-10
Jan-11
Sep-11
Diesel distribution margins by region (R$/liter)
Diesel resale margins by region (R$/liter)
0.35
0.33
0.30
0.27
N
0.25
MW
SE
0.21
0.10
0.00
May-08
0.19
Sep-09
Source: MME, Credit Suisse Research.
May-10
Jan-11
Sep-11
May-12
S
NE
MW
0.17
S
Jan-09
SE
N
0.23
0.05
Sep-13
0.29
0.25
0.15
Jan-13
0.31
NE
0.20
May-12
Jan-13
Sep-13
0.15
May-08
Jan-09
Sep-09
May-10
Jan-11
Sep-11
May-12
Jan-13
Sep-13
93
March 2014
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Equity Research
Distribution
The market share game
Brazil
Distribution market share
Market share evolution
40%
22% Other
22%
30%
4%
20%
10%
19%
North/
Northeast/
Mid-West
33%
0%
Jan-09 Nov-09 Sep-10
50%
27%
4%
North/Northeast/Mid-West
40%
30%
20%
14%
10%
41%
0%
Jan-09 Oct-09 Jul-10 Apr-11 Jan-12 Oct-12 Jul-13
14%
South/
Southeast
Jul-11 May-12 Mar-13
South/SE
27%
20%
4%
21%
28%
30%
25%
20%
15%
10%
5%
0%
Jan-09 Oct-09 Jul-10 Apr-11 Jan-12 Oct-12 Jul-13
Other
Source: Credit Suisse research based on Sindicom.
94
March 2014
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Equity Research
Distribution
The fight against the white flags
Brazil
Number of gas stations (thousands)
and white flag market share
Current share of number of Gas stations
5%
WF share
19%
White-flag
39%
38%
16%
9% Other
12%
North/
Northeast/
Mid-West
42%
41%
40%
39%
Branded
22.8
21.9
22.7
23.5
24.3
White-flag
14.0
15.8
15.6
15.7
15.5
2008
2009
2010
2011
2012
49%
48%
47%
46%
7.4
7.0
7.5
7.8
8.2
6.0
6.7
6.8
7.1
7.1
2008
2009
2010
2011
2012
38%
37%
35%
34%
15.4
14.8
15.2
15.7
16.1
7.9
9.1
8.8
8.6
8.4
2008
2009
2010
2011
2012
4%
20%
North/Northeast/Mid-West
46%
45%
9%
8%
13%
South/SE
South/
Southeast
5%
19%
34%
34%
21%
14%
7%
Other
Source: Credit Suisse research based on Sindicom.
White-flag
Branded
WF share
95
March 2014
LatAm Oil & Gas
Equity Research
Understanding Gas & Power
FOTO
The black-box
Gas & Power is one of Petrobras’ least known business, partly because of its
smaller size relative to E&P and R&M, but also because of complexity. Results are
volatile, and rising energy prices can actually imply in lower profitability for the
business. It is therefore, a business hard to understand and to model. In three
slides, we provide a simple but effective overview of G&P, a first step for the
market to try to better understand this business.
March 2014
LatAm Oil & Gas
Equity Research
Understanding Gas & Power
A brief overview
G&P and Petrobras
Revenues of c.$12bn and EBITDA of c. $2bn
Natural Gas
Revenues
8.2%
 Revenues of c. $8bn
 Three main markets for
natural gas are:
- Industrial, commercial and
retail customers
- Thermoelectric generation
- Petrobras refineries and
fertilizer plants
c. 65% of
revenues
Power
91.8%
 Revenues of c. $3.7bn
 Petrobras has participation
c. 30% of
revenues

EBITDA
in Thermopower, wind and
small-scale hydroelectric
plants
6,235 MW of installed
capacity
7.2%
Fertilizers
c. 5%of
revenues
92.8%
G&P
 Revenues of c.$600m
 The company is focused on
the production of ammonia
and urea for the Brazilian
market
Petrobras ex-G&P
Source: Petrobras, Credit Suisse research.
97
March 2014
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Equity Research
Understanding Gas & Power
The Gas
Supply
Sources of natural
gas supply (%)
11%
LNG
36%
Domestic
production
53%
Imported
from Bolivia
Natural gas pipeline network
Pipeline networks footprint
Total Natural Gas supply of
75MM3/d
LNG
Pecem
LNG
Bahia
LNG
Baía de
Guanabara
Three main markets

Petrobras natural gas pipeline network
has a total extension of 9,190 km

The company invested $13bn
between 2006 and 2012
22%
Gas-fired power
plants

The integrated system centered
around two main interlinked pipeline
networks allows the company to
deliver natural gas from main offshore
natural gas producing fields in the
Santos, Campos and Espírito Santo
Basins, as well as from three LNG
Terminals (one of which is under
construction), and a gas pipeline
connection with Bolivia
25%
Internal
consumption
53%
Local
distribution
companies
Natural gas
demand (%)
Total Natural Gas sales of
55MM3/d and internal
consumption of 19MM3/d
Gas contracts
 Gas is sold primarily to distribution companies and to power plants generally based on standard take-or-pay long term supply contracts (72% of total sale volumes) where
the prices are indexed to an international fuel oil basket.
 Petrobras also has contracts designed to create flexibility in matching customers demand. These include flexible and interruptible long-term gas supply contracts, auction
mechanisms for short-term contracts, weekly electronic auctions and a new gas sale contract, which consists of a seller delivery option aiming to help balance natural gas
supply and demand in case of a low dispatch of natural gas from power plants.
Source: Credit Suisse research based on Petrobras.
98
March 2014
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Equity Research
Understanding Gas & Power
The Power
Brazil installed capacity by type (%)
Brazil installed capacity by operator (%)
Brazil installed capacity
of 134,912 MW as of
February 2014
CESP, 7%
CEMIG, 6%
Eletrobrás, 30%
Thermo power, 19%
Itaipu, 6%
Tractebel, 6%
Hydro, 63%
Petrobras, 6%
Biomass, 8%
Copel, 4%
CPFL, 2%
AES Tietê, 2%
Duke Energy, 2%
Wind, 2%
Imports from Itaipú (Hydro), 8%
 Petrobras currently operates 21 thermopower plants.
 There are roughly three types of contracts/needs under which Petrobras sells its
certified power capacity: (1) contracts in auction power (standby availability), (2)
bilateral contracts with free customers and (3) energy for PBR own needs.
– Under the standby availability contracts, the power plants shall produce
energy whenever requested by the national operator. In this type of
contract, in addition to a capacity payment, the plants also receive from the
Electric Energy Trading Chamber (CCEE) a reimbursement for its declared
variable costs incurred whenever they are called to generate electricity.
– Under merchant bilateral contracts, Petrobras sells the energy at market
prices in contracts usually adjusted by inflation, and usually under longerterm contracts.
Source: ANEEL, Tractebel, Petrobras.
Others, 29%
Volumes of electricity sold by Petrobras
MW avg
2012
2011
2010
Total sales commitments
4,438
3.991
3,853
2,318
2,000
2,024
423
395
438
1,697
1,596
1,391
Generation volume
2,699
653
1,837
Revenues (US$ mm)
3,755
2,336
2,752
Bilateral merchant contracts
Self-production
Standby-availability
99
March 2014
LatAm Oil & Gas
Equity Research
Petrobras financial statements
FOTO
March 2014
LatAm Oil & Gas
Equity Research
Key Petrobras financials
P&L
Group P&L
2006
2007
2008
2009
2010
2011
2012
2013
2014E
2015E
2016E
2017E
2018E
2019E
2020E
Revenues
USDm
72,837
87,606
126,186
91,355
121,178
146,213
143,561
141,153
142,650
159,948
169,049
183,033
208,243
236,121
228,652
COGS
USDm
(43,575)
(53,617)
(85,597)
(54,519)
(77,302)
(99,963) (107,384) (108,206) (113,791) (122,483) (123,220) (140,274) (154,550) (170,121) (169,972)
SG&A
USDm
(5,330)
(6,414)
(8,224)
(7,281)
(9,464)
(10,537)
(9,921)
(9,885)
(10,053)
(10,254)
(10,459)
(10,669)
(10,882)
(11,100)
(11,322)
Exploration costs, write-offs
USDm
(958)
(1,549)
(2,489)
(2,001)
(2,157)
(2,651)
(4,016)
(2,984)
(2,804)
(2,804)
(2,804)
(2,804)
(2,804)
(2,804)
(2,804)
Other expenses (R&D, others)
USDm
(3,533)
(5,179)
(5,092)
(4,491)
(5,518)
(5,874)
(5,711)
(4,168)
(4,500)
(4,500)
(4,500)
(4,500)
(4,500)
(4,500)
(4,500)
EBIT
USDm
19,442
20,847
24,784
23,064
26,737
27,187
16,529
15,909
11,502
19,907
28,065
24,786
35,507
47,597
40,054
Financial income
USDm
1,095
1,288
2,064
1,753
2,579
3,918
3,694
1,811
855
804
988
1,147
1,391
1,694
2,037
Financial expense
USDm
(1,712)
(1,691)
(2,851)
(2,927)
(1,881)
(1,450)
(2,015)
(2,683)
(1,913)
(2,360)
(2,657)
(2,941)
(3,214)
(3,295)
(3,283)
FX variation & others
USDm
4
(1,616)
2,973
(245)
759
(2,395)
(3,579)
(1,999)
0
0
0
0
0
0
0
Associates
USDm
(107)
(350)
(217)
(42)
118
231
43
507
200
200
200
200
200
200
200
EBT
USDm
18,721
18,478
26,753
21,603
28,311
27,492
14,672
13,545
10,644
18,550
26,596
23,192
33,883
46,196
39,008
Income taxes
USDm
(5,476)
(5,790)
(8,858)
(4,989)
(6,952)
(6,731)
(3,466)
(2,383)
(3,193)
(5,581)
(7,811)
(6,762)
(10,156)
(13,860)
(11,704)
Minorities & employee contribution USDm
(1,315)
(1,640)
537
(2,124)
(1,365)
(813)
(399)
(250)
(250)
(250)
(250)
(250)
(250)
(250)
(250)
Net income
USDm
11,930
11,048
18,432
14,491
19,994
19,948
10,807
10,912
7,202
12,719
18,536
16,180
23,478
32,086
27,055
number of ADRs
millions
4,387
4,387
4,387
4,387
6,522
6,522
6,522
6,522
6,522
6,522
6,522
6,522
6,522
6,522
6,522
number of shares
millions
8,774
8,774
8,774
8,774
13,044
13,044
13,044
13,044
13,044
13,044
13,044
13,044
13,044
13,044
13,044
Earnings per ADR (EPADR)
$/ADR
2.72
2.52
4.20
3.30
3.07
3.06
1.66
1.67
1.10
1.95
2.84
2.48
3.60
4.92
4.15
EPS
R$/sh
2.95
2.45
3.87
3.30
2.70
2.55
1.62
1.81
1.38
2.51
3.76
3.38
5.05
7.11
6.17
Tax rate
%
29%
31%
33%
23%
25%
24%
24%
18%
30%
30%
30%
30%
30%
30%
30%
EBIT margin
%
27%
24%
20%
25%
22%
19%
12%
11%
8%
12%
17%
14%
17%
20%
18%
EBITDA margin
%
32%
29%
25%
33%
28%
25%
19%
21%
17%
21%
25%
25%
28%
31%
29%
Revenue YoY growth
%
20%
44%
(28%)
33%
21%
(2%)
(2%)
1%
12%
6%
8%
14%
13%
(3%)
EBITDA YoY growth
%
10%
20%
(4%)
14%
9%
(27%)
7%
(14%)
38%
25%
6%
29%
25%
(8%)
EPADR YoY growth
%
(7%)
67%
(21%)
(7%)
(0%)
(46%)
1%
(34%)
77%
46%
(13%)
45%
37%
(16%)
P&L metrics
Memo: EBITDA reconciliation
EBIT
USDm
19,442
20,847
24,784
23,064
26,737
27,187
16,529
15,909
11,502
19,907
28,065
24,786
35,507
47,597
40,054
DD&A
USDm
4,522
5,493
6,538
7,384
8,455
10,622
11,105
13,179
13,425
14,424
14,987
20,838
23,234
25,809
27,343
Impairment and others
USDm
(551)
(520)
(228)
(476)
(918)
(537)
(369)
63
0
0
0
0
0
0
0
EBITDA
USDm
23,413
25,820
31,094
29,972
34,274
37,273
27,265
29,151
24,927
34,330
43,052
45,623
58,740
73,405
67,397
Source: Credit Suisse estimates.
101
March 2014
LatAm Oil & Gas
Equity Research
Key Petrobras financials
Cash-flow statement
Cash-flows, CS adjusted
EBITDA
Tax payments (P&L)
Deffered tax payments, other adjustments
Cash earnings
Inventories increase (-), decrease (+)
Receivables increase (-), decrease (+)
Payables increase (+), decrease (-)
Working capital movements
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
2006
23,413
(5,476)
0
17,937
0
2007
25,820
(5,790)
245
20,276
(2,452)
(818)
4,081
811
2008
31,094
(8,858)
2,592
24,828
1,398
300
(713)
985
2009
29,972
(4,989)
159
25,142
(3,776)
(3,094)
4,364
(2,506)
2010
34,274
(6,952)
3,292
30,614
447
(2,147)
(742)
(2,441)
2011
37,273
(6,731)
3,687
34,229
(3,266)
(2,833)
1,327
(4,772)
2012
27,265
(3,466)
2,171
25,970
555
1,863
612
3,030
2013
29,151
(2,383)
150
26,918
335
2,043
(1,394)
984
2014E
24,927
(3,193)
150
21,883
0
0
0
0
2015E
34,330
(5,581)
150
28,898
0
0
0
0
2016E
43,052
(7,811)
150
35,390
0
0
0
0
2017E
2018E
2019E
2020E
45,623
58,740
73,405
67,397
(6,762) (10,156) (13,860) (11,704)
150
0
0
0
39,011
48,584
59,545
55,693
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
CFO
Capex
Divestments
CFI
USDm
USDm
USDm
USDm
17,937
21,087
25,814
22,636
28,173
29,457
29,000
27,901
21,883
28,898
35,390
39,011
48,584
59,545
55,693
0 (21,265) (28,325) (34,480) (41,573) (41,584) (40,440) (45,388) (41,420) (41,420) (41,420) (41,420) (41,420) (41,420) (41,420)
3,824
4,500
4,500
0
0
0
0
0
0 (21,265) (28,325) (34,480) (41,573) (41,584) (40,440) (41,564) (36,920) (36,920) (41,420) (41,420) (41,420) (41,420) (41,420)
Free-cash-flow to the firm (FCFF)
Financial expenses (cap + expensed)
Financial income
Issuance of debt
Repayment of principal
Equity issuance
Dividend payment
CFF
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
17,937
0
0
0
0
0
0
0
(178)
(2,257)
1,427
4,549
(6,169)
0
(4,009)
(6,459)
Change in cash before FX variation
FX, accounting change
Change in cash and equivalents
Capex breakdown
Exploration & Production
Refining, Transportation and Marketing
Gas & Power
International
Distribution
Biofuel
Corporate
PBR capex
Reported capex
USDm
USDm
USDm
17,937
(6,637)
1,284
(5,353)
(265)
(533)
(799)
3,401
6,306
9,707
18,313
(1,197)
17,116
(4,935)
(847)
(5,782)
(4,459)
497
(3,963)
(126)
(4,092)
(4,217)
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
7,049
1,925
721
3,296
296
0
417
13,703
0
9,459
4,947
830
3,376
858
0
449
19,919
21,265
13,403
5,495
2,077
3,333
303
0
674
25,286
28,325
15,410
8,254
3,281
3,417
318
0
1,153
31,832
34,480
18,424
15,913
2,775
2,711
509
0
1,505
41,836
41,573
20,510
16,238
2,304
2,659
693
301
737
43,441
41,584
21,923
14,724
2,126
2,601
667
153
733
42,927
40,440
27,775
14,231
2,740
2,374
519
149
553
48,341
45,388
Source: Credit Suisse estimates.
(2,511) (11,844) (13,400) (12,127) (11,440) (13,662) (15,037)
(2,298) (2,385) (4,060) (4,878) (5,136) (5,499) (7,246)
1,641
694
1,255
2,938
1,695
1,289
855
15,429
29,731
21,331
24,211
24,965
38,736
30,000
(7,779) (5,084) (10,852) (8,696) (11,386) (18,315) (8,000)
0
0
29,388
0
0
0
0
(4,747) (7,712) (5,349) (6,383) (3,157) (2,674) (4,085)
2,246
15,245
31,713
7,192
6,981
13,537
11,525
(8,022)
(7,867)
804
30,000
(8,000)
0
(3,510)
11,427
(6,030)
(8,857)
988
30,000
(8,000)
0
(4,575)
9,556
(2,409)
7,164
18,125
14,273
(9,805) (10,713) (10,983) (10,942)
1,147
1,391
1,694
2,037
30,000
20,000
15,000
15,000
(8,000) (8,000) (8,000) (8,000)
0
0
0
0
(5,763) (5,525) (7,022) (8,846)
7,580 (2,848) (9,311) (10,751)
(3,513)
3,405
3,527
5,171
4,317
8,814
3,522
(3,513)
3,405
3,527
5,171
4,317
8,814
3,522
29,500
8,640
1,180
640
580
220
660
41,420
29,500
8,640
1,180
640
580
220
660
41,420
29,500
8,640
1,180
640
580
220
660
41,420
29,500
8,640
1,180
640
580
220
660
41,420
29,500
8,640
1,180
640
580
220
660
41,420
29,500
8,640
1,180
640
580
220
660
41,420
29,500
8,640
1,180
640
580
220
660
41,420
102
March 2014
LatAm Oil & Gas
Equity Research
Key Petrobras financials
Balance sheet
Balance sheet
Cash and equivalents
Receivables and tax receivables
Inventories
Others
Current assets
PP&E and investments
Intangibles
LT receivables and advances to suppliers
Deferred taxes, judicial deposits
Others
Non-current assets
Total assets
Current debt
Suppliers and tax payables
Dividends, labour and pension
Others
Current liabilities
Non-current debt
LT taxes payables
Pension benefits and legal provisions
Decommissioning provisions
Others
Non-current liabilities
Share capital
Profit reserves and others
Minorities
Equity
Total equity + Liabilities
Balance sheet metrics
Total debt
Net debt
Net debt/EBITDA
Net debt / (ND + Equity)
Total debt to equity
Book value
Book value per share
Book value per ADR
Returns
ROE
ROA
ROCE
Memo: Capital employed
Source: Credit Suisse estimates.
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
2006
13,065
9,971
7,484
1,038
31,558
56,383
2,072
2,029
4,975
1,826
67,286
98,844
5,879
9,354
4,389
2,987
22,609
14,809
4,280
5,384
0
2,464
26,937
22,659
23,130
3,509
49,299
98,844
2007
7,712
10,789
9,936
1,695
30,133
83,421
3,123
2,717
7,092
4,056
100,409
130,541
4,799
13,435
5,166
3,448
26,848
16,828
6,631
7,786
0
4,612
35,857
29,721
34,557
3,560
67,837
130,541
2008
6,914
10,489
8,537
1,229
27,169
83,701
3,420
2,529
2,648
5,388
97,688
124,856
5,673
12,722
5,591
2,748
26,734
21,388
6,151
5,886
2,813
1,621
37,859
33,747
25,384
1,134
60,264
124,856
2009
16,621
13,583
12,313
1,548
44,066
134,126
3,913
2,632
9,935
3,954
154,559
198,625
8,556
17,086
3,353
4,355
33,350
48,680
10,616
8,526
2,814
2,067
72,703
45,383
46,263
925
92,572
198,625
2010
33,737
15,730
11,866
2,551
63,883
174,681
49,759
5,947
11,987
5,102
247,476
311,359
9,382
16,344
4,493
3,813
34,032
61,226
15,665
9,970
3,895
807
91,563
122,968
60,724
2,071
185,763
311,359
2011
27,955
18,563
15,131
2,799
64,449
188,572
43,768
6,380
10,751
4,777
254,248
318,697
10,088
17,671
4,514
4,010
36,283
72,653
17,696
9,582
4,702
1,066
105,699
109,245
66,202
1,269
176,715
318,697
2012
23,992
16,700
14,576
2,625
57,893
211,369
39,807
7,610
13,469
2,066
274,321
332,214
7,510
18,283
5,973
2,362
34,127
88,723
19,246
10,558
9,457
773
128,756
100,682
67,494
1,154
169,330
332,214
2013
19,775
14,657
14,241
4,041
52,714
234,827
15,436
7,770
3,638
7,395
269,067
321,781
8,026
16,888
6,846
3,506
35,267
106,426
9,917
13,017
7,141
725
137,226
87,782
60,910
596
149,288
321,781
2014E
16,262
14,657
14,241
4,041
49,201
258,522
15,436
7,770
3,488
7,395
292,613
341,814
8,026
16,888
6,846
3,506
35,267
123,094
9,917
13,017
7,141
725
153,893
87,782
64,027
845
152,654
341,814
2015E
19,667
14,657
14,241
4,041
52,607
281,219
15,436
7,770
3,339
7,395
315,159
367,766
8,026
16,888
6,846
3,506
35,267
139,587
9,917
13,017
7,141
725
170,386
87,782
73,236
1,095
162,113
367,766
2016E
23,194
14,657
14,241
4,041
56,133
307,852
15,436
7,770
3,189
7,395
341,643
397,776
8,026
16,888
6,846
3,506
35,267
155,387
9,917
13,017
7,141
725
186,186
87,782
87,197
1,344
176,323
397,776
2017E
28,365
14,657
14,241
4,041
61,304
328,634
15,436
7,770
3,040
7,395
362,276
423,580
8,026
16,888
6,846
3,506
35,267
170,523
9,917
13,017
7,141
725
201,323
87,782
97,614
1,594
186,990
423,580
2018E
32,682
14,657
14,241
4,041
65,621
347,020
15,436
7,770
3,040
7,395
380,662
446,283
8,026
16,888
6,846
3,506
35,267
175,024
9,917
13,017
7,141
725
205,823
87,782
115,567
1,843
205,192
446,283
2019E
41,496
14,657
14,241
4,041
74,435
362,831
15,436
7,770
3,040
7,395
396,473
470,908
8,026
16,888
6,846
3,506
35,267
174,336
9,917
13,017
7,141
725
205,135
87,782
140,631
2,093
230,506
470,908
2020E
45,018
14,657
14,241
4,041
77,958
377,108
15,436
7,770
3,040
7,395
410,750
488,707
8,026
16,888
6,846
3,506
35,267
173,677
9,917
13,017
7,141
725
204,476
87,782
158,839
2,342
248,964
488,707
USDm
USDm
x
%
x
USDm
R$/sh
$/ADR
20,688
7,623
0.37
16%
45%
45,789
11
10
21,627
13,915
0.53
19%
34%
64,277
14
15
27,061
20,147
0.85
26%
46%
59,130
12
13
57,236
40,615
1.19
31%
62%
91,647
21
21
70,608
36,871
1.03
17%
38%
183,692
25
28
82,741
54,787
1.66
24%
47%
175,446
22
27
96,232
72,240
2.77
30%
57%
168,176
25
26
114,453
94,678
3.52
39%
77%
148,692
25
23
131,120
114,858
4.61
43%
86%
151,809
29
23
147,613
127,946
3.73
44%
92%
161,018
32
25
163,413
140,219
3.26
44%
93%
174,979
36
27
178,550
150,185
3.29
45%
96%
185,397
39
28
183,051
150,369
2.56
42%
90%
203,349
44
31
182,363
140,867
1.92
38%
80%
228,413
51
35
181,703
136,685
2.03
35%
74%
246,622
56
38
%
%
%
USDm
26%
14%
25%
56,921
17%
12%
18%
81,752
31%
13%
20%
80,412
16%
9%
14%
133,187
11%
6%
9%
222,635
11%
6%
9%
231,502
6%
4%
5%
241,570
7%
4%
6%
243,966
5%
2%
3%
267,512
8%
4%
5%
290,059
11%
5%
6%
316,542
9%
4%
5%
337,175
12%
6%
7%
355,561
14%
7%
9%
371,373
11%
6%
7%
385,649
103
March 2014
LatAm Oil & Gas
Equity Research
Key Petrobras financials
E&P operational metrics
E&P
2007
2008
2009
2010
2011
2012
2013
2014E
2015E
2016E
2017E
2018E
2019E
2020E
x
1.95
1.84
2.00
1.76
1.67
1.96
2.16
2.50
2.57
2.65
2.73
2.81
2.89
2.97
Brazilian inflation (IGPM)
%
3.6%
5.7%
4.9%
5.0%
6.6%
5.4%
6.3%
5.3%
5.0%
5.0%
5.0%
5.0%
5.0%
5.0%
US inflation (PPI)
%
3.1%
3.5%
(0.1%)
1.5%
3.3%
2.0%
1.6%
1.7%
2.0%
2.0%
2.0%
2.0%
2.0%
2.0%
kbd
3,622
Macro
BRL-USD (average)
Production
Oil production
1,792
1,855
1,971
2,004
2,022
1,980
1,931
2,077
2,341
2,377
2,623
3,054
3,524
Gas production
kboed
273
321
317
334
355
375
389
418
447
475
620
701
782
862
Total production
kboed
2,065
2,176
2,288
2,338
2,377
2,355
2,320
2,494
2,787
2,852
3,243
3,755
4,305
4,485
Oil production YoY growth
%
4%
6%
2%
1%
(2%)
(2%)
8%
13%
2%
10%
16%
15%
3%
Revenues
Brent
$/bbl
73
97
62
79
111
112
109
110
110
112
114
117
119
121
Domestic discount (-), premium (+)
$/bbl
(11)
(15)
(8)
(5)
(9)
(7)
(10)
(10)
(10)
(10)
(10)
(10)
(10)
(10)
Domestic oil price
$/bbl
62
82
54
75
102
105
98
100
100
102
104
107
109
111
Domestic gas price
$/boe
35
40
23
16
53
48
47
45
45
45
45
45
45
45
Domestic gas price
$/mcf
6.3
7.2
4.0
2.8
9.5
8.7
8.5
8.0
8.0
8.0
8.0
8.0
8.0
8.0
Costs & Taxes
Royalties per bbl
$/bbl
5
7
5
6
9
9
8
9
9
9
9
9
9
9
SPT per bbl
$/bbl
5
8
5
7
10
9
8
8
8
8
10
10
10
10
Other production taxes
$/bbl
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Total production taxes
$/bbl
12
17
12
15
20
20
18
19
19
19
21
21
21
21
DDA per bbl
$/bbl
4
4
5
6
7
8
9
9
9
9
13
13
13
13
Lifting costs
$/bbl
8
9
9
10
13
14
15
14
15
16
17
17
18
19
Lifting cost nominal inflation
%
20%
(5%)
14%
26%
11%
6%
(3%)
5%
5%
5%
5%
5%
5%
USD-BRL exposure
Portion of lifting costs in BRL
%
50%
49%
46%
46%
46%
46%
46%
46%
46%
Portion of lifting costs in USD
%
50%
51%
54%
54%
54%
54%
54%
54%
54%
Lifting costs in BRL
BRL/bbl
14
15
16
18
19
21
22
24
26
Lifting costs in USD
USD/bbl
7
7
8
8
9
9
9
10
10
Total lifting costs
USD/bbl
14
14
14
15
16
17
17
18
19
Memo:
Capex
USDm
Capex per bbl
$/bbl
Source: Credit Suisse estimates.
9,459
13,403
15,410
18,424
20,510
21,923
27,775
27,775
27,775
27,775
27,775
27,775
27,775
27,775
13
17
18
22
24
26
33
31
27
27
23
20
18
17
104
March 2014
LatAm Oil & Gas
Equity Research
Key Petrobras financials
E&P financials
E&P
Divisional P&L
Revenues
COGS
SG&A
Exploration costs
Other expenses (R&D, others)
EBIT
Financials & associates
EBT
Income taxes
Minorities & employee contribution
Net income
E&P tax rate
EBIT margin
EBITDA margin
Memo: EBITDA reconciliation
EBIT
DD&A
Impairment and others
EBITDA
Returns
Asset base
ROA
Unit P&L
Revenues
Royalties
SPT
Lifting costs
SG&A
Exploration costs
Other costs & Taxes
EBITDA
DD&A
Impairment
EBIT
EBT
Net income
Source: Credit Suisse estimates.
2007
2008
2009
2010
2011
2012
2013
2014E
2015E
2016E
2017E
2018E
2019E
2020E
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
%
%
%
41,648
(17,942)
(293)
(622)
(872)
21,919
(260)
21,658
(7,301)
(579)
13,778
34%
53%
60%
57,722
(23,793)
(435)
(1,386)
(1,130)
30,977
0
30,977
(10,450)
(20,887)
(360)
34%
54%
60%
38,092
(19,570)
(330)
(1,536)
(1,670)
14,986
0
14,986
(5,012)
(174)
9,801
33%
39%
49%
54,234
(25,172)
(451)
(1,478)
(1,381)
25,752
(306)
25,447
(8,652)
0
16,794
34%
47%
56%
74,268
(33,005)
(490)
(2,200)
(1,536)
37,037
(248)
36,789
(12,493)
11
24,308
34%
50%
58%
74,272
(33,495)
(491)
(3,630)
(1,342)
35,313
(176)
35,137
(11,947)
(3)
23,187
34%
48%
56%
68,186
(34,221)
(443)
(2,804)
(896)
29,822
(175)
29,647
(10,080)
(25)
19,543
34%
44%
55%
74,836
(36,966)
(466)
(2,804)
(896)
33,704
(175)
33,529
(11,400)
0
22,129
34%
45%
60%
84,781
(42,208)
(490)
(2,804)
(896)
38,383
(175)
38,209
(12,991)
0
25,218
34%
45%
60%
88,311
(44,003)
(514)
(2,804)
(896)
40,094
(175)
39,920
(13,573)
0
26,347
34%
45%
59%
101,173
(58,529)
(540)
(2,804)
(896)
38,404
(175)
38,229
(12,998)
0
25,231
34%
38%
56%
121,042
(69,149)
(567)
(2,804)
(896)
47,626
(175)
47,452
(16,134)
0
31,318
34%
39%
56%
143,181
(80,856)
(595)
(2,804)
(896)
58,030
(175)
57,855
(19,671)
0
38,185
34%
41%
57%
151,115
(85,774)
(625)
(2,804)
(896)
61,016
(175)
60,842
(20,686)
0
40,156
34%
40%
56%
USDm
USDm
USDm
USDm
21,919
3,082
(186)
24,814
30,977
3,382
86
34,444
14,986
4,081
(244)
18,823
25,752
5,177
(365)
30,564
37,037
6,411
(46)
43,403
35,313
6,512
(138)
41,687
29,822
7,809
(172)
37,458
33,704
8,395
2,804
44,904
38,383
9,381
2,804
50,569
40,094
9,599
2,804
52,498
38,404
15,386
2,804
56,594
47,626
17,818
2,804
68,248
58,030
20,428
2,804
81,262
61,016
21,279
2,804
85,100
USDm
%
50,390
43%
50,524
61%
74,702
20%
136,288
19%
140,798
26%
152,058
23%
152,876
20%
55
(5)
(5)
(8)
(0)
(1)
(3)
33
(4)
0
29
29
18
73
(7)
(8)
(9)
(1)
(2)
(3)
43
(4)
(0)
39
39
(0)
46
(5)
(5)
(9)
(0)
(2)
(2)
23
(5)
0
18
18
12
64
(6)
(7)
(10)
(1)
(2)
(2)
36
(6)
0
30
30
20
86
(9)
(10)
(13)
(1)
(3)
(2)
50
(7)
0
43
42
28
86
(9)
(9)
(14)
(1)
(4)
(1)
48
(8)
0
41
41
27
81
(8)
(8)
(15)
(1)
(3)
(1)
44
(9)
0
35
35
23
82
(9)
(8)
(14)
(1)
(3)
2
49
(9)
(3)
37
37
24
83
(9)
(8)
(15)
(0)
(3)
2
50
(9)
(3)
38
38
25
85
(9)
(8)
(16)
(0)
(3)
2
50
(9)
(3)
39
38
25
85
(9)
(10)
(17)
(0)
(2)
1
48
(13)
(2)
32
32
21
88
(9)
(10)
(17)
(0)
(2)
1
50
(13)
(2)
35
35
23
91
(9)
(10)
(18)
(0)
(2)
0
52
(13)
(2)
37
37
24
92
(9)
(10)
(19)
(0)
(2)
0
52
(13)
(2)
37
37
25
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
105
March 2014
LatAm Oil & Gas
Equity Research
Key Petrobras financials
Refining operational metrics
RTM (Refining, Trading, Marketing)
2006
2007
Crude destillation capacity
Crude destillation capacity
kbd
1,986
Utilization
%
90%
Feedstock processed
kbd
1,787
Oil product multiplier
x
1.00
Output of oil products
kbd
1,795
Diesel
kbd
674
682
Gasoline
kbd
347
352
Naphtha
kbd
149
159
Fuel Oil
kbd
261
265
LPG
kbd
143
147
Others (Jet, Kerosene, Coke, Asphalt)
kbd
190
Diesel
yield %
38%
Gasoline
yield %
19%
Naphtha
yield %
8%
Fuel Oil
yield %
15%
LPG
yield %
8%
Others (Jet, Kerosene, Coke, Asphalt)
yield %
0%
Domestic market demand = PBR volumes sold
Diesel
kbd
700
Gasoline
kbd
269
Naphtha
kbd
166
Fuel Oil
kbd
106
LPG
kbd
206
Others (Jet, Kerosene, Coke, Asphalt)
kbd
242
Total
kbd
1,689
Diesel
YoY%
Gasoline
YoY%
Total products
YoY%
Oil product imports / inventory decrease (+), exports / inventory buildup (-)
Diesel
kbd
26
Gasoline
kbd
(78)
Others
kbd
(54)
Oil product imports (+), exports (-)
kbd
(106)
Crude oil import & exports
Feedstock processed
kbd
1,787
Share of domestic oil
%
78%
Domestic oil processed
kbd
1,394
Crude oil import needs
kbd
393
Prices
International diesel price
$/bbl
89
International gasoline price
$/bbl
85
Diesel: domestic vs international
%
121%
Gasoline: domestic vs international
%
104%
Domestic diesel price
$/bbl
108
Domestic gasoline price
$/bbl
89
Domestic diesel price
BRL/liter
1.32
Domestic gasoline price
BRL/liter
1.09
Source: Credit Suisse estimates.
2008
2009
2010
2011
2012
2013
2014E
2015E
2016E
2017E
2018E
2019E
2020E
1,942
91%
1,767
1.01
1,787
707
346
140
252
143
199
40%
19%
8%
14%
8%
11%
1,942
92%
1,787
1.02
1,823
739
333
145
242
135
228
41%
18%
8%
13%
7%
13%
1,942
93%
1,806
1.01
1,832
714
355
127
239
132
265
39%
19%
7%
13%
7%
14%
2,013
92%
1,852
1.02
1,896
733
389
109
227
136
301
39%
21%
6%
12%
7%
16%
2,018
96%
1,937
1.03
1,997
782
440
110
237
143
285
39%
22%
6%
12%
7%
14%
2,102
97%
2,039
1.04
2,124
858
494
93
257
138
284
40%
23%
4%
12%
6%
13%
2,102
94%
1,976
1.02
2,015
814
469
88
244
131
270
40%
23%
4%
12%
6%
13%
2,145
94%
2,016
1.02
2,057
835
469
94
248
133
278
41%
23%
5%
12%
6%
14%
2,459
94%
2,311
1.02
2,358
976
491
129
280
149
332
41%
21%
5%
12%
6%
14%
2,597
92%
2,389
1.02
2,437
1,020
480
146
287
153
351
42%
20%
6%
12%
6%
14%
2,597
92%
2,389
1.02
2,437
1,020
480
146
287
153
351
42%
20%
6%
12%
6%
14%
2,597
92%
2,389
1.02
2,437
1,020
480
146
287
153
351
42%
20%
6%
12%
6%
14%
3,197
92%
2,941
1.02
3,000
1,302
480
230
344
181
463
43%
16%
8%
11%
6%
15%
741
281
151
97
213
226
1,709
6%
4%
1%
730
300
164
102
210
200
1,705
(2%)
7%
(0%)
794
354
167
100
218
272
1,905
9%
18%
12%
862
434
167
82
224
289
2,059
9%
23%
8%
919
521
165
84
224
305
2,218
7%
20%
8%
965
529
171
98
231
309
2,303
5%
2%
4%
1,013
556
177
101
238
318
2,402
5%
5%
3%
1,064
584
182
104
245
328
2,506
5%
5%
3%
1,117
613
187
107
252
338
2,614
5%
5%
3%
1,150
631
193
110
260
348
2,692
3%
3%
3%
1,185
650
199
113
268
358
2,773
3%
3%
3%
1,220
670
205
117
276
369
2,856
3%
3%
3%
1,257
690
211
120
284
380
2,942
3%
3%
3%
34
(65)
(48)
(78)
(10)
(33)
(75)
(118)
80
(1)
(6)
73
129
45
(12)
163
137
81
3
221
107
36
37
179
199
87
101
387
229
115
105
449
141
122
(6)
256
130
151
(26)
255
165
170
2
336
200
189
30
419
(45)
209
(223)
(58)
1,767
78%
1,378
389
1,787
79%
1,411
375
1,806
82%
1,481
325
1,852
82%
1,519
333
1,937
82%
1,589
349
2,039
82%
1,672
367
1,976
82%
1,620
356
2,016
82%
1,653
363
2,311
82%
1,895
416
2,389
82%
1,959
430
2,389
82%
1,959
430
2,389
82%
1,959
430
2,941
82%
2,412
529
118
98
97%
96%
114
94
1.32
1.09
69
67
140%
125%
96
84
1.21
1.06
90
86
112%
112%
102
96
1.13
1.06
125
115
87%
88%
108
102
1.13
1.07
128
117
78%
83%
100
98
1.23
1.21
126
113
83%
87%
105
99
1.42
1.34
127
115
77%
77%
98
88
1.54
1.39
127
115
82%
82%
105
94
1.69
1.53
130
117
95%
95%
123
111
2.06
1.85
133
119
95%
95%
126
113
2.16
1.94
135
122
95%
95%
128
116
2.27
2.04
138
124
95%
95%
131
118
2.38
2.14
141
127
95%
95%
134
120
2.50
2.25
106
March 2014
LatAm Oil & Gas
Equity Research
Key Petrobras financials
Refining financials
RTM (Refining, Trading, Marketing)
Divisional P&L
Revenues
COGS
SG&A
Other expenses (R&D, others)
EBIT
Financials & associates
EBT
Income taxes
Minorities & employee contribution
Net income
Downstream tax rate
EBIT margin
EBITDA margin
Memo: EBITDA reconciliation
EBIT
DD&A
Impairment and others
EBITDA
Returns
Asset base
ROA
Unit P&L (per barrel sold)
Revenues
Crude purchase costs
Refining costs
Oil product import costs
Other costs
EBITDA
DD&A
Impairment, others
EBIT
EBT
Net income
Source: Credit Suisse estimates.
2006
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
USDm
%
%
%
57,880
(51,770)
(145)
(1,604)
4,360
38
4,398
(1,424)
(161)
2,812
32%
2007
2008
2009
68,384 100,752
(61,076) (100,056)
(2,064)
(2,851)
(535)
(692)
4,709
(2,846)
14
(301)
4,722
(3,147)
(1,538)
1,020
(149)
(64)
3,035
(2,191)
33%
32%
7%
(3%)
8%
(2%)
73,384
(60,431)
(2,336)
(377)
10,241
85
10,326
(3,437)
(224)
6,666
33%
14%
16%
2010
2011
2012
2013
2015E
2016E
2017E
2018E
2019E
2020E
97,993 118,872 116,144 110,816 117,480 133,792 141,875 154,992 179,314 206,282 197,880
(91,115) (123,352) (129,538) (119,471) (134,866) (147,844) (145,868) (158,562) (182,135) (208,259) (198,129)
(2,953)
(3,315)
(3,028)
(2,773)
(2,919)
(3,065)
(3,219)
(3,380)
(3,549)
(3,726) (3,912)
(678)
(892)
(1,011)
(1,025)
(1,000)
(1,000)
(1,000)
(1,000)
(1,000)
(1,000) (1,000)
3,247
(8,687) (17,433) (12,453) (21,306) (18,117)
(8,212)
(7,950)
(7,370)
(6,703) (5,161)
(56)
(307)
(241)
(58)
(58)
(58)
(58)
(58)
(58)
(58)
(58)
3,191
(8,995) (17,673) (12,511) (21,363) (18,175)
(8,270)
(8,008)
(7,428)
(6,761) (5,219)
(1,031)
3,025
5,974
4,279
7,306
6,216
2,828
2,739
2,540
2,312
1,785
0
9
0
8
8
8
8
8
8
8
8
2,160
(5,961) (11,699)
(8,224) (14,049) (11,951)
(5,433)
(5,261)
(4,879)
(4,441) (3,426)
32%
34%
34%
34%
34%
34%
34%
34%
34%
34%
34%
3%
(7%)
(15%)
(11%)
(18%)
(14%)
(6%)
(5%)
(4%)
(3%)
(3%)
4%
(6%)
(13%)
(9%)
(16%)
(12%)
(4%)
(3%)
(2%)
(2%)
(1%)
USDm
USDm
USDm
USDm
4,709
994
(142)
5,561
(2,846)
1,329
(153)
(1,670)
10,241
1,430
(134)
11,538
3,247
1,148
(215)
4,180
(8,687)
1,579
(42)
(7,150)
(17,433)
2,096
(278)
(15,614)
(12,453)
2,705
(131)
(9,880)
USDm
%
31,193
15%
27,685
(10%)
50,070
20%
70,434
5%
84,141
(10%)
91,615
(19%)
92,209
(14%)
111
(84)
(3)
5
(20)
9
(2)
0
8
8
5
162
(112)
(3)
4
(53)
(3)
(2)
0
(5)
(5)
(4)
118
(78)
(3)
5
(23)
19
(2)
0
16
17
11
141
(93)
(4)
(4)
(34)
6
(2)
0
5
5
3
158
(120)
(5)
(10)
(33)
(10)
(2)
0
(12)
(12)
(8)
143
(112)
(4)
(13)
(34)
(19)
(3)
0
(22)
(22)
(14)
132
(101)
(3)
(10)
(30)
(12)
(3)
0
(15)
(15)
(10)
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
2014E
(21,306)
2,566
(131)
(18,871)
(18,117)
2,619
(131)
(15,630)
(8,212)
3,002
(131)
(5,341)
(7,950)
3,103
(131)
(4,978)
(7,370)
3,103
(131)
(4,398)
(6,703)
3,103
(131)
(3,732)
(5,161)
3,820
(131)
(1,473)
134
(104)
(2)
(20)
(29)
(22)
(3)
0
(24)
(24)
(16)
146
(110)
(2)
(23)
(28)
(17)
(3)
0
(20)
(20)
(13)
149
(112)
(3)
(13)
(27)
(6)
(3)
0
(9)
(9)
(6)
158
(121)
(3)
(13)
(26)
(5)
(3)
0
(8)
(8)
(5)
177
(137)
(3)
(16)
(26)
(4)
(3)
0
(7)
(7)
(5)
198
(154)
(3)
(20)
(25)
(4)
(3)
0
(6)
(6)
(4)
184
(160)
(3)
2
(25)
(1)
(4)
0
(5)
(5)
(3)
107
March 2014
LatAm Oil & Gas
Equity Research
Other Brazilian oil themes
FOTO
Labour trends and wage inflation
Brazil, as a country, is seeing of quasi-full employment levels. In the oil industry, the
situation is even better (or worse), given the sheer volume of activity, spearheaded
by Petrobras. Brazil has presented one of the highest wage inflations in the oil
sector globally. Oil salaries in Brazil are amongst one of the highest globally. There
is evidence of saturation of the local labour market. In this section, we provide
extensive analysis of the oil labour market in Brazil and Latin America.
The comeback of licensing rounds
Welcome back. The pre-salt was discovered in 2006 and by 2008-2009 was relatively
well appraised so that the industry knew the province was high potential. That has
increased the Governmental ‘protection’ of such an strategic area, resulting in a
temporary pause in the licensing rounds that has been going on since 1997 with the
opening up of the sector to foreign companies. In the 2010-2012 period, a number of
discussions took place, such as (i) capitalisation of Petrobras, (ii) acquisition of the ToR
areas, (iii) change in the regulatory regime from Concession to PSC in the pre-salt
areas; (iv) creation of a government-controlled company (PPSA) to oversee and audit
future pre-salt contracts, (v) distribution of petroleum royalties among producing and
non-producing states and municipalities. With most of those discussions having
concluded by 2013 and a strong industry lobby to the comeback of license rounds,
activity is finally picking-up: (i) the 11th round focussed on the equatorial margin areas,
North Brazil, which happened in may, (ii) the first pre-salt PSC round with the auction of
Libra in October and (iii) the 12th round, focussed on onshore areas in the country-side,
in November 2013.
March 2014
LatAm Oil & Gas
Equity Research
Labour trends and wage inflation
Another oil salary increase
2012 oil salary changes in selected countries (%)
increase in the next twelve months (see next slide).
-4
-5
-7
-10
Venezuela
-2
Saudi Arabia
-2
Norway
0
Iran
Brazil
7
South Africa
7
Canada
9
USA
15
Russia
18
Singapore
 Next year shows few signs of slowdown, with 58% of respondents expecting a 5%+
China
Argentina
highest wage inflation in the past four years: Colombia has seen wage inflation of 30%,
Brazil 15%, and Argentina 13%. This illustrates well what happens to a market that needs
to develop local skills when faced by increasing activity. Yearly figures are more variable:
Brazil decreased in 2012 vs 2011 (Hays cites delays in the licensing rounds as key reason
– if this assessment is correct we could see a rebound in 2013 with re-start of the rounds),
and Argentina saw a 37% rise in 2012. Brazil/Arg rank 8th/10th highest wages globally.
Iraq
 The chart below has surprised us. LatAm has three countries out of the four with
UK
23
Global average
28
Australia
37
Mexico
c.6.0%, the oil labour market shows no signs of slowdown: 2012 oil salaries increased by
8.5% in 2012, according to Hays. This does not necessarily come as a surprise in an
industry that has through most of its history seen costs and capital intensity increase. This
year, Hays mentions key reasons for increased salaries were (1) a wave of hiring from
proliferation of unconventional field developments and (2) increasing trend for a global
labour market to address the skill gap in a number of countries seeing rising oil spend.
Colombia
 Another oil salary increase. After a 2011 that saw global oil salaries increase by
-15 -16 -18
2009 – 2012 YoY% average oil salary changes – LatAm winning the inflation race (%)
0
0
Libya
Azerbaijan
Russia
Venezuela
Mexico*
Angola
(3)
(4)
(4)
(5)
(5)
India
1
UK
3
USA
3
Canada
5
Global average
6
Australia
6
Netherlands
8
Oman
8
Iran
9
Saudi Arabia
9
New Zealand
10
China
10
Norway
10
Algeria
11
Kazakhstan
12
Indonesia
13
Iraq
13
Argentina
14
Singapore
Brazil
Colombia*
15
Malaysia
LatAm: three of top four highest
wage inflation countries globally
28
(8)
* 2010-2012 CAGR
Source: Credit Suisse analysis based on Hays – The Oil and Gas Global Salary Guide.
109
March 2014
LatAm Oil & Gas
Equity Research
Labour trends and wage inflation
We wish we worked there
Salary changes in the last 12 months, % of the workforce
4%
4%
Decrease
30%
30%
Flat
16%
17%
Expected salary changes for the next 12 months, % of the
workforce
1%
18%
Decrease
Flat
24%
Increase up to 5%
30%
Increase between 5-10%
32%
28%
Increase more than 10%
2011
2012
1%
16%
21%
Increase up to 5%
30%
50%
50%
2011
Increase more than 10%
2012
Average salaries in USD/year – Norway and Australia still top payers, Brazil and Argentina also among highest globally
2012
200,000
2011
160,000
120,000
80,000
Source: Credit Suisse analysis based on Hays – The Oil and Gas Global Salary Guide.
Sudan
Pakistan
Romania
Yemen
Philippines
India
Ghana
Egypt
Libya
Kazakhstan
Algeria
Poland
Iran
Indonesia
Iraq
Malaysia
Thailand
Azerbaijan
Mexico
Portugal
Angola
Vietnam
Russia
Nigeria
Trinidad
Venezuela
Spain
China
Italy
Oman
Turkey
South Africa
South Korea
Colombia
Singapore
Saudi Arabia
Global average
UK
France
Denmark
Argentina
Brazil
Kuwait
USA
Canada
Netherlands
New Zealand
Norway
0
Australia
40,000
110
March 2014
LatAm Oil & Gas
Equity Research
Labour trends and wage inflation
Local vs imported labour
 Increasing trend towards local labour, where possible. As the chart on the
bottom left shows, there is an increasing trend for a higher mix of local labour in
most regions of the world, South America included. The only two regions which
have shown a decrease in % of local workers have been the Middle East and
Australasia. In our view this reflects a local labour market that is already
saturated, therefore growth comes only via imported labour.
 Curious trend in 2012 in Braz il. We find it curious that in 2012 the local labour
participation in Brazil has actually fallen to 67% from a peak of 73% in 2011.
With the increasing ‘demand’ for foreigners, it has become again more expensive
to import labour vs hire locally (in 2011, local salaries were 12% higher than
imported salaries. In 2012, local salaries were 16% lower than imported
salaries). We wonder if this is just ‘normal’ year on year volatility, or the beginning
of the same trend seen in Australasia and the Middle East, with the saturation of
the local labour market. This may as well be the case – Brazil has all time low
unemployment levels, close to ‘technical’ full employment.
Local labour participation by region – trend towards local until
saturation
2009
100%
2010
2011
Low unemployment rate in Brazil and Argentina
16%
Colombia
14%
Eurozone
12%
10%
6%
Brazil
4%
Jan-09
Jul-09
Jan-10
Jul-10
Jan-11
Jul-11
Jan-12
Jul-12
Jan-13
Local salaries premium and use of local workforce in Brazil
2012
Local labor participation
80%
USA
Argentina
8%
59%
65%
60%
Local salaries premium (+)
73%
67%
12%
40%
0%
20%
0%
-16%
Africa
Asia
Australasia
CIS
Europe
Middle
East
North
America
South
America
Source: Credit Suisse analysis based on Hays – The Oil and Gas Global Salary Guide and Bloomberg.
-26%
2009
2010
2011
2012
111
March 2014
LatAm Oil & Gas
Equity Research
Labour trends and wage inflation
Local vs imported labour
 Braz il and Argentina stand out as two countries where the local wages are
Local-foreign labor participation by region in 2012
67%
49%
64%
51%
59%
86%
Imported
Workforce
14%
Local
Workforce
41%
Middle
East
72%
36%
CIS
Europe
33%
Australasia
82%
Asia
86%
industry working to iron out the extreme variations in pay between locals and
foreigners. This is a natural trend as companies try to arbitrage local-international
markets to keep costs under control and the global labour market becomes more
mobile.
28%
Africa
 Interestingly, Hays mentions it is increasingly observing recruiting in the oil
18%
South
America
14%
North
America
one of the highest compared to imported wages. Through the past three years,
Brazil has had an average local wage 13% cheaper than imported wages, and
Argentina 18% cheaper. This is good news for Brazilian and Argentinean oil
workers: most countries in the Hays survey have local salaries being 40-70%
lower than imported salaries (other LatAm countries such as Colombia, Mexico
and Venezuela are also within this range).
2009 – 2012 Average local labor premium: Brazil and Argentina are remarkably close to parity (%)
Philippines
-74%
Indonesia
-71%
Iraq
-70%
-69%
Vietnam
Ghana
-69%
-69%
Kazakhstan
Azerbaijan
-68%
Romania
Thailand
-67%
-68%
-69%
Egypt
Nigeria
-64%
-67%
Malaysia
-63%
Trinidad
India
-59%
Yemen
Portugal
-59%
-65%
Algeria
Poland
-55%
-58%
Russia
-53%
Angola
Sudan
-52%
-57%
Colombia
-51%
-57%
Pakistan
-51%
Mexico
Iran
-47%
China
South Korea
-45%
-56%
Venezuela
Libya
Singapore
-29%
-44%
Denmark
-34%
UAE
-27%
-28%
-40%
Oman
-23%
Bahrain
Turkey
-22%
Qatar
Italy
-21%
Source: Credit Suisse analysis based on Hays – The Oil and Gas Global Salary Guide.
-31%
Argentina
Spain
South Africa
-18%
-18%
France
-18%
Brazil
-13%
-14%
Australia
Korea
0%
-2%
Local labor cheaper than imported
-12%
4%
3%
USA
UK
New Zealand
5%
Canada
21%
6%
Netherlands
Saudi Arabia
29%
22%
Brunei
Norway
Kuwait
48%
Local labour more expensive
112
March 2014
LatAm Oil & Gas
Equity Research
Labour trends and wage inflation
Employer concerns: skill shortage, economic instability and environment
 Skill shortage is the top concern of employers for three consecutive years, both
Employer concern by region – skill shortage still top concern
globally and in South America. Economic instability and environmental concerns come in
second and third places. Another interesting trend to observe is how Environment and
Safety were at extremely high levels in 2010, the year of Macondo, and fell in the
following years. Last year, in South America, we have seen a rebound of those two
concerns, we think likely due to the Frade incident with Chevron in Brazil, and the initial
strong reactions by parts of the Brazilian Government, Institutions and the Media.
100%
Other
Security/social unrest
Immigration/visa
Safety regulations
80%
60%
 Lack of skilled labour is notable at the junior-entry levels. As we show on the next
Environmental concerns
40%
slide, Graduates were the ones with the highest pay increase last year – 12% vs an
average increase of 8.5% industry-wide. Scarcity at entry levels is also evident: the % of
employees with less than 4 years experience fell from 36% in 2011 to 28% in 2012.
Economic instability
20%
 Do you want to be em ployed by a super m ajor or by an oil services com pany?
Skills shortages
Africa
Middle East
Asia
CIS
South America
World
North America
Europe
Australasia
0%
Also on the next slide, we show that the majors are still the highest payers in the industry.
On the other hand, they are also the ones capable of ‘imposing’ the lowest pay rises in
the industry. This is a power equipment providers don’t have: they were the companies
seeing the highest wage inflation levels (17%!), a mix of lower base and need to have
more skilled labour as OFS is increasingly responsible to solve industry’s technological
challenges.
South America employers main concerns for next year – skill shortages still on top of the list
2010
2011
2012
45%
37%
28%
25%
25%
14%
28%
25%
12%
16%
3%
Skills shortages
Economic instability
Environmental concerns
Source: Credit Suisse analysis based on Hays – The Oil and Gas Global Salary Guide.
7%
Safety regulations
10%
3%
7%
Immigration/visa
2%
6%
Security/social unrest
2%
3%
2%
Other
113
March 2014
LatAm Oil & Gas
Equity Research
Labour trends and wage inflation
Super majors pay more, OFS inflation is higher, Graduate scarcity
Average salaries by company type in 2012, yearly
$116k
$108k
Wage inflation by company type in 2012 – manufacturers saw a
17% increase
17%
$99k
$96k
$83k
$73k
12%
$72k
11%
9%
8%
6%
Operator
Global Super
Major
EPCM
Consultancy Contractor
Oil Field
Services
Equipment
manufacture
and supply
Years of experience in the industry – Lack of entry level expertise
2011
36%
28%
22%
23%
21%
24%
2012
Equipment
manufacture
and supply
Operator
Contractor
Oil Field
Services
EPCM
Consultancy Global Super
Major
Wage inflation by current level in 2012 – Entry level saw highest
growth
12%
9%
25%
9%
9%
21%
5%
Less than 4
5-9 years
10-19 years
Source: Credit Suisse analysis based on Hays – The Oil and Gas Global Salary Guide.
6%
20+ years
Graduate
Operator/
technician
Senior
4%
VP/Director Manager lead/ Intermediate
Principal
114
March 2014
LatAm Oil & Gas
Equity Research
Labour trends and wage inflation
South America’s high benefit levels (but training is not one of them)
Share of the workforce receiving benefits by region, %
2010
South America the highest benefits ‘penetration’ globally
76%
72% 75%
South America
77% 75% 74%
77% 75%
73%
Asia
Middle East
70% 70%
66%
74% 72%
North America
64%
67%
Africa
63% 60%
CIS
58%
65%
57%
2011
2012
57% 57%
Australasia
51%
Europe
South America – Share of the workforce receiving each benefit
2010
36%
37%
39%
2012
39%
34%
Training not among top
benefits in 2012
31%
30%
24%
19%
Bonuses
2011
Health plan
Meal allowance
Source: Credit Suisse analysis based on Hays – The Oil and Gas Global Salary Guide.
22%
17%
21%
17%
Transport
17%
15%
Pension
28%
24%
25%
19%
12%
Training
No benefits
115
March 2014
LatAm Oil & Gas
Equity Research
The comeback of the licensing rounds
4 years without rounds, then 3 rounds in one year
 Welcom e back. The pre-salt was discovered in 2006 and by 2008-2009 was
relatively well appraised so that the industry knew the province was high
potential. That has increased the Governmental ‘protection’ of such an strategic
area, resulting in a temporary ‘hault’ in the licensing rounds that has been going
on since 1997 with the opening up of the sector to foreign companies. In the
2010-2012 period, a number of discussions took place, such as (i) capitalisation
of Petrobras, (ii) acquisition of the ToR areas, (iii) change in the regulatory regime
from Concession to PSC in the pre-salt areas; (iv) creation of a governmentcontrolled company (PPSA) to oversee and audit future pre-salt contracts, (v)
distribution of petroleum royalties among producing and non-producing states
and municipalities. With most of those discussions having concluded by 2013
and a strong industry lobby to the comeback of license rounds, 2013 is bound to
see three rounds at the same time: (i) the 11th round focussed on the equatorial
margin areas, North Brazil, which happened in may, (ii) the first pre-salt PSC
round with the auction of Libra in October and (iii) the 12th round, focussed on
onshore areas in the country-side, in November 2013.
Brazilian sedimentary basins and 2013 license rounds
Foz do Amazonas
Pará-Maranhao
Barreirinhas
Amazonas
Ceará
Solimões
Potiguar
Alto Tapajós
Parnaíba
Acre
Tucano
Round Zero
1999
Round 1
Camamu
Jequitinhonha
São Francisco
2000
2001
Round 2
Round 3
2002
2003
2004
2005
Round 4
Round 5
Round 6
Round 7
Sergipe-Alagoas
Recôncavo
Parecis
Licensing round calendar
1998
Pernambuco
Paraiba
Espiríto Santo
Paraná
Campos
Brazil’s sedimentary basins
Libra
License rounds in 2013:
Santos
Round 11
2006
Round 8
2007
Round 9
Source: Credit Suisse Research based on the ANP.
2008
2013
Round 12
Round 10
Round 11
Round 12
Libra
Libra PSC
Pelotas
116
March 2014
LatAm Oil & Gas
Equity Research
The comeback of the licensing rounds
License rounds over the years
Number of bidders and foreign/domestic composition
Blocks auctioned
(number of blocks and as % of blocks offered)
300
100%
50
100%
250
80%
40
80%
60%
30
60%
40%
20
40%
20%
10
20%
200
150
100
50
0
0%
1999 2000 2001 2002 2003 2004 2005 2007 2008 2013*
Auctioned blocks
Auctioned blocks as % of total blocks offered
0
0%
1999 2000 2001 2002 2003 2004 2005 2007 2008 2013*
Domestic Bidders
Foreign Bidders
Domestic Bidders (%)
Signature bonus and minimum exploratory programme
(USDm)
Local content bids
5,000
100%
4,000
Bonus (USDm)
90%
MEP (USDm)
80%
LC
development
phase
70%
3,000
60%
2,000
1999-2002: Minimum
exploratory programme
not disclosed
1,000
0
50%
40%
LC exploration
phase
30%
20%
1999 2000 2001 2002 2003 2004 2005 2007 2008 2013*
Source: Credit Suisse Research based on the ANP; * Note: data for 2013 only includes Round 11 (and not Libra or Round 12).
1999 2000 2001 2002 2003 2004 2005 2007 2008 2013*
117
March 2014
LatAm Oil & Gas
Equity Research
The comeback of the licensing rounds
Key learnings from round 11
Coordination from all players will be needed to face the operational challenges in the Equatorial Margin
FZA-M-57 FZA-M-59
bp
FZA-M-86 FZA-M-88 FZA-M-90
CE-M-603
FZA-M-125FZA-M-127
CE-M-661
SFZA-AP1
CE-M-663
CE-M-665
FZA-M-184
CE-M-715
CE-M-717
Foz do Amazonas
SCE-AP3
Pará-Maranhao
Barreirinhas
Ceará
Amazonas
Solimões
Foz do Amazonas: Total showing strong presence. The
company also has acreage/operations on nearby F. Guiana.
Potiguar
Alto Tapajós
Acre
Parecis
Ceará: A timid but interesting return from Exxon and
Chevron to Brazil. Round continuity is key for US players.
Pernambuco
Paraiba
Tucano
Sergipe-Alagoas
Recôncavo
Camamu
São Francisco
Jequitinhonha
Parnaíba
BAR-M-213 BAR-M-215BAR-M-217
ES-M-669
ES-M-596
ES-M-598
ES-M-671
ES-M-673
Espiríto Santo
Paraná
BAR-M-252 BAR-M254
Campos
BAR-M-298BAR-M-300
E3-M-743
Libra
Santos
SBAR-AP1
BAR-M-340BAR-M-342BAR-M-344BAR-M-346
bp
Pelotas
SES-AP2
Barreirinhas: BG bidding alone and securing operatorship
in a number of blocks. Being operator in Brazil is strategic.
Source: Credit Suisse Research based on the ANP.
Espírito Santo: Statoil faced little competition and secured
interest in a number of blocks in this less-sought area
118
March 2014
LatAm Oil & Gas
Equity Research
The comeback of the licensing rounds
Key learnings from round 12
Acre – 9 blocks
offered, 1 taken
 A ‘seed’. A very timid participation in round 12 means the
round was just what the ANP wanted, a ‘seed’ indeed. Key
things we note:
Parnaiba – 32 blocks
offered, 1 taken
Reconcavo – 50 blocks
offered, 30 taken
10
6
– Of the 240 blocks offered, only 30% (72) received bids;
– Of those 72, the great majority (80% or 58 blocks)
1
received a single bid;
8
4
2
– Petrobras participated in 49 blocks of the 72 bid. In 43 of
those PBR was the operator and in 27 it was operator
with no partners;
– Mature provinces such as onshore Sergipe-Alagoas and
– Reconcavo were responsible for 75% of the bids,
Parecis – 14 blocks
offered, none taken
showing little exploratory appetite for onshore gas
exploration;
Sergipe / Alagoas –
80 blocks offered, 24 taken
– Two of the six basins offered (Sao Francisco and Parecis)
7
received no bids. Acre and Parnaiba only received one
bid each;
1
– 12 companies won blocks as operators or partners, one
of the lowest numbers in history. Of those 12 companies,
four are non-oil and gas (utilities or engineering
companies);

– Aside Petrobras, there was no Big Oil major, which was
somewhat expected and an attempt from the Agency to
offer a round capable of incentivising smaller E&Ps
(Alvopetro, Cowan, Geopark, Novapetroleo, Ouro Preto,
Petra, Trayectoria). Two utilities, Copel and GDF Suez,
participated in the round as partners: Copel partnered
with Petra in three blocks in Parana, and GDF Suez
partnered with Petrobras in six blocks in Reconcavo.
Source: Credit Suisse Research based on the ANP.
4
Parana – 19 blocks
offered, 16 taken
4
3
4
1
Sao Francisco – 36 blocks
offered, none taken
2
3
7
4
119
Companies Mentioned
March 2014
LatAm Oil & Gas
Equity Research
Price as of 10-March-2014










BP (BP.L, 484.0p)
Chevron Corp. (CVX.N, $115.84)
ENI (ENI.MI, €17.42)
ExxonMobil Corporation (XOM.N, $95.5)
Hess Corporation (HES.N, $82.24)
OMV (OMVV.VI, €32.31)
Petrobras (PBR.N, $10.68, NEUTRAL[V], TP $14.0)
Repsol (REP.MC, €18.1)
Royal Dutch Shell plc (RDSa.L, 2193.0p)
Statoil (STL.OL, Nkr161.7)
120
Important Global Disclosures
March 2014
LatAm Oil & Gas
Equity Research
Vinicius Canheu, CFA and Andre Sobreira, CFA, each certify, with respect to the companies or securities that the individual analyzes, that (1) the views expressed in this report accurately reflect his or her personal views about all
of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report.
3-Year Price and Rating History for Petrobras (PBR.N)
PBR.N
Date
17-Mar-11
15-Aug-11
17-Aug-11
20-Nov-11
26-Feb-12
20-Jun-12
24-Jun-12
07-Mar-13
16-Jul-13
28-Oct-13
01-Dec-13
Closing Price
(US$)
39.10
29.23
29.37
26.65
30.08
20.47
19.60
17.56
13.42
17.35
15.94
Target Price
(US$)
48.00
38.00
38.00
34.00
32.00
27.00
25.00
25.00
25.00
14.00
Rating
N
O
N
O
*
O
U
N EU T RA L
O U T PERFO RM
U N D ERPERFO RM
* Asterisk signifies initiation or assumption of coverage.
The analyst(s) responsible for preparing this research report received Compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment
banking activities
As of December 10, 2012 Analysts’ stock rating are defined as follows:
Outperform (O) : The stock’s total return is expected to outperform the relevant benchmark*over the next 12 months.
Neutral (N) : The stock’s total return is expected to be in line with the relevant benchmark* over the next 12 months.
Underperform (U) : The stock’s total return is expected to underperform the relevant benchmark* over the next 12 months.
*Relevant benchmark by region: As of 10th December 2012, Japanese ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the
relevant sector, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. As of 2nd October 2012, U.S. and Canadian as well as European
ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractive, Neutrals
the less attractive, and Underperforms the least attractive investment opportunities. For Latin American and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of the relevant
country or regional benchmark; Australia, New Zealand are, and prior to 2nd October 2012 U.S. and Canadian ratings were based on (1) a stock’s absolute total return potential to its current share price and (2) the relative
attractiveness of a stock’s total return potential within an analyst’s coverage universe. For Australian and New Zealand stocks, 12-month rolling yield is incorporated in the absolute total return calculation and a 15% and a 7.5%
threshold replace the 10-15% level in the Outperform and Underperform stock rating definitions, respectively. The 15% and 7.5% thresholds replace the +10-15% and -10-15% levels in the Neutral stock rating definition,
respectively. Prior to 10th December 2012, Japanese ratings were based on a stock’s total return relative to the average total return of the relevant country or regional benchmark.
Restricted (R) : In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications, including an investment recommendation, during the course of Credit Suisse's
engagement in an investment banking transaction and in certain other circumstances.
Volatility Indicator [V] : A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24 months or the analyst expects significant volatility going forward.
Analysts’ sector weightings are distinct from analysts’ stock ratings and are based on the analyst’s expectations for the fundamentals and/or valuation of the sector* relative to the group’s historic fundamentals and/or valuation:
Overweight : The analyst’s expectation for the sector’s fundamentals and/or valuation is favorable over the next 12 months.
Market Weight : The analyst’s expectation for the sector’s fundamentals and/or valuation is neutral over the next 12 months.
Underweight : The analyst’s expectation for the sector’s fundamentals and/or valuation is cautious over the next 12 months.
*An analyst’s coverage sector consists of all companies covered by the analyst within the relevant sector. An analyst may cover multiple sectors.
121
Important Global Disclosures
March 2014
LatAm Oil & Gas
Equity Research
Credit Suisse's distribution of stock ratings (and banking clients) is:
Global Ratings Distribution
Rating
Versus universe (%)
Of which banking clients (%)
Outperform/Buy*
43%
(53% banking clients)
Neutral/Hold*
40%
(49% banking clients)
Underperform/Sell*
15%
(43% banking clients)
Restricted
2%
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Price Target: (12 m onths) for Petrobras (PBR.N)
Method: Our new target price (TP US$14/ADR) methodology incorporates a more bearish outlook for Petrobras based on signals of higher political interference. 90% of our target price is based on (1) a required 9% earnings
yield on trough 2014 earnings, (2) the need for PBR to offer a top-tier 5.5% dividend yield on a minimum R$0.96/sh dividend to attract investors amid more uncertainty, (3) a write-off of $25bn of value in the
company's valuation, equivalent to 2014's funding gap. The remaining 10% of our valuation incorporates a more fundamental view, and our estimate of intrinsic value when the companies reaches a 'steady-state'
business performance by 2020.
Risk:
Risks to our US$14/ADR target price for Petrobras include, but are not restricted to, (1) changes in oil prices, (2) foreign exchange rate variations, (3) changes in the regulatory environment in Brazil, (4) political
interference (Petrobras is controlled by the Brazilian government), (5) delays in the execution of its main E&P projects, and (6) potential controls on domestic prices of refined products.
Please refer to the firm's disclosure website at https://rave.credit-suisse.com/disclosures for the definitions of abbreviations typically used in the target price method and risk sections.
See the Companies Mentioned section for full company names
The subject company (PBR.N) currently is, or was during the 12-month period preceding the date of distribution of this report, a client of Credit Suisse.
Credit Suisse provided investment banking services to the subject company (PBR.N) within the past 12 months.
Credit Suisse has managed or co-managed a public offering of securities for the subject company (PBR.N) within the past 12 months.
Credit Suisse has received investment banking related compensation from the subject company (PBR.N) within the past 12 months
Credit Suisse expects to receive or intends to seek investment banking related compensation from the subject company (PBR.N) within the next 3 months.
As of the date of this report, Credit Suisse makes a market in the following subject companies (PBR.N).
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Important Regional Disclosures
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The analyst(s) involved in the preparation of this report have not visited the material operations of the subject company (PBR.N) within the past 12 months
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